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True Energy Trust announces first quarter 2008 financial results


View All News Releases May 8, 2008

    TSX: TUI.UN

    CALGARY, May 8 /CNW/ - (TSX: TUI.UN) True Energy Trust ("True" or the
"Trust") announces its financial and operating results for the three months
ended March 31, 2008. Highlights from the quarter include:-   In the first quarter of 2008, monthly distributions of $0.04 per unit
        were declared and paid on February 17, 2008, March 17, 2008 and
        April 15, 2008. The Board has announced it has set a distribution
        policy for the second quarter of 2008 at a monthly rate of $0.04 per
        unit, subject to monthly confirmation, based on current commodity
        prices, hedging program, anticipated production volumes and market
        conditions. True anticipates its $0.04 per unit monthly distributions
        to be sustainable in the current gas price, foreign exchange rate and
        cost environment.

    -   True generated average sales volumes for the first quarter of 2008 of
        13,552 boe/d as compared to 14,937 boe/d for the fourth quarter of
        2007. In addition to natural production declines, field production
        for the first quarter of 2008 was adversely impacted by extreme
        weather experienced in January and February 2008. An unplanned third
        party plant outage also impacted production in west central Alberta
        for February 2008.

    -   Funds flow from operations(*) for the first quarter of 2008 was
        $24.3 million on gross sales of $70.0 million compared to funds flow
        from operations of $30.0 million on gross sales of $71.2 million for
        the same period in 2007. The decrease in funds flow for the 2008
        first quarter was primarily the result of lower sales volumes,
        partially offset by higher overall commodity prices and operating
        netbacks for the period. Funds flow from operations for the first
        quarter of 2008 increased 25% from fourth quarter 2007 funds flow
        from operations of $19.5 million, reflecting improved commodity
        prices.

    -   The net loss for the first quarter of 2008 of $18.6 million was
        primarily due to higher mark-to-market unrealized losses on commodity
        risk management contracts of $17.7 million. This compares to a net
        loss of $8.6 million for the first quarter of 2007.

    -   During the first quarter of 2008, True achieved a 75% success rate in
        drilling or participation in 4 (3.0 net) working interest wells,
        resulting in 2 (1.0 net) gas wells, 1 (1.0 net) light oil wells, and
        1 (1.0 net) dry hole.

    -   In the first quarter of 2008, True was successful in completing the
        divestiture of a small non-core property in the Northeast area of
        Alberta for net proceeds after adjustments of $5.8 million.

    -   Further to True's announcement of its intention to divest of a
        portfolio of its Saskatchewan assets, on April 30, 2008, True closed
        on the sale of its Dodsland-Stranraer property for net proceeds of
        $39.3 million, after closing adjustments, which will be reflected in
        True's second quarter results. Dodsland-Stranraer was 1 of 5 packages
        of Saskatchewan assets announced for divestiture as part of a new
        strategic direction.

    -   On April 30, 2008 True further announced its decision not to pursue
        further Saskatchewan asset dispositions at this time. The Trust feels
        that the new strategic direction goal of increased financial
        flexibility is sufficiently achieved through the combination of
        vastly improved commodity prices, receipt of the Dodsland-Stranraer
        disposition proceeds, and a continued distribution level of $0.04 per
        unit per month, while retaining the benefit of a larger production
        base.

    -   The Kerrobert SAGD project continues to show positive response to the
        ongoing reservoir heating. Temperatures of up to 140 degrees Celsius
        are being observed in the new thermal producing wells as compared to
        initial reservoir temperatures of approximately 30 degrees Celsius.
        Fluid production rates from the new thermal producers are being
        carefully restricted to control continued steam chamber development
        and ensure uniform heating and conformance.

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

    True's first quarter report is presented below.


                                 HIGHLIGHTS
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
                                                          2008          2007
    -------------------------------------------------------------------------
    FINANCIAL
    (CDN $000s except unit and per unit amounts)
    Revenue (before royalties and hedging(1))           70,033       71,196
    Funds flow from operations(2)                       24,233       29,988
      Per basic trust unit                         $      0.31   $     0.43
      Per diluted trust unit                       $      0.30   $     0.42
    Net loss                                           (18,621)      (8,571)
      Per basic trust unit                         $     (0.24)  $    (0.12)
      Per diluted trust unit                       $     (0.24)  $    (0.12)
    Distributions paid                                   9,507       16,866
      Per trust unit                               $      0.12   $     0.24
    -------------------------------------------------------------------------
    Exploration and development                          8,453       45,653
    Corporate and property acquisitions                    197          705
    -------------------------------------------------------------------------
    Capital expenditures - cash                          8,650       46,358
    Property dispositions - cash                        (5,788)     (18,443)
    Other - non-cash                                      (193)         624
    -------------------------------------------------------------------------
    Total capital expenditures - net                     2,669       28,539
    -------------------------------------------------------------------------
    Long-term debt                                     171,850      178,379
    Convertible debentures(3)                           79,837       78,243
    Working capital deficiency (excess)(3)             (11,369)      31,748
    -------------------------------------------------------------------------
    Total net debt(3)                                  240,318      288,370
    -------------------------------------------------------------------------
    Total assets                                       861,569      979,160
    Unitholders' equity                                435,232      481,547
    -------------------------------------------------------------------------
    OPERATING
    Daily sales volumes
      Crude oil and NGLs                 (bbls/d)        4,873         6,472
      Natural gas                         (mcf/d)       52,252        71,931
      Total oil equivalent                (boe/d)       13,552        18,461
    Average prices
      Crude oil and NGLs                  ($/bbl)        71.59         41.26
      Crude oil and NGLs (including
       hedging(1))                        ($/bbl)        61.98         43.75
      Natural gas                         ($/mcf)         7.97          7.26
      Natural gas (including hedging(1))  ($/mcf)         7.99          7.52
      Total oil equivalent                ($/boe)        56.31         42.74
      Total oil equivalent (including
       hedging(1))                        ($/boe)        52.96         44.64
    Statistics
      Operating netback(4)                ($/boe)        29.28         24.36
      Operating netback (including
       hedging(1))(4)                     ($/boe)        25.92         26.25
      Transportation expenses             ($/boe)         0.68          0.41
      Production expenses                 ($/boe)        13.78          9.01
      General & administrative            ($/boe)         3.06          2.95
      Royalties as a % of sales after
       transportation                                      23%           21%
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                                                 Three months ended March 31
                                                          2008          2007
    -------------------------------------------------------------------------
    TRUST UNITS
    Trust units outstanding                         79,230,460    70,276,890
    Trust unit incentive rights outstanding          5,232,665     5,227,333
    Units issuable for exchangeable shares             337,351       303,547
    Units issuable for convertible debentures        5,390,625     5,390,625
    -------------------------------------------------------------------------
    Diluted trust units outstanding                 90,191,101    81,198,395
    Diluted weighted average trust units(5)         79,223,088    70,275,770

    -------------------------------------------------------------------------
    TRUST UNIT TRADING STATISTICS
    (CDN$, except volumes) based on intra-day trading
    High                                                  4.00          7.47
    Low                                                   2.94          4.87
    Close                                                 3.66          5.85
    Average daily volume                               257,218       601,724
    -------------------------------------------------------------------------
    (1) The Trust has entered into various commodity risk management
        contracts which are considered to be economic hedges. Per unit
        metrics after hedging includes only the realized portion of gains or
        losses on commodity contracts.

        Effective January 1, 2007 on adoption of CICA handbook sections 3855
        and 3865, the Trust no longer applies hedge accounting to these
        contracts. As such, these contracts are revalued to fair value at the
        end of each reporting date. This results in recognition of unrealized
        gains or losses over the term of these contracts which is reflected
        each reporting period until these contracts are settled, at which
        time realized gains or losses are recorded. These unrealized gains or
        losses on commodity contracts are not included for purposes of per
        unit metrics calculations disclosed.

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

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

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

    (5) In computing weighted average diluted earnings per trust unit for the
        three month period ended March 31, 2008 a total of 337,351(2007:
        303,347) exchangeable shares, 5,232,665 (2007: 5,227,333) trust
        incentive rights and 5,390,625 (2007: 5,390,625) trust units issuable
        pursuant to conversion of convertible debentures were excluded from
        the calculation of diluted earnings per trust unit as they were not
        dilutive. To calculate weighted average diluted funds flow from
        operations for the three month period ended March 31, 2008, 337,351
        exchangeable shares were added to the denominator, resulting in
        diluted weighted average trust units of 79,558,882 under this
        calculation. To calculate weighted average diluted funds 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 303,347 exchangeable shares 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 and funds flow from operations per diluted trust
        unit of $0.42 under this calculation.


                            REPORT TO UNITHOLDERSDramatically improved commodity prices, and natural gas pricing in
particular, is providing some long awaited relief for a stressed sector.
However the improved pricing has also placed significant negative pressure on
commodity hedges entered into under an entirely different environment. True's
hedges were placed over a span of several months to ensure adequate funding
would be available to meet distribution requirements. Approximately 50% of
Trust's natural gas production and 60% the liquids production remains
un-hedged and open to the upside in commodity pricing.
    Accomplishments for the first quarter ended March 31, 2008 include:

    Distributions

    In the first quarter of 2008, monthly distributions of $0.04 per unit
were declared and paid on February 15, 2008, March 17, 2008 and April 15,
2008.
    On April 8, 2008, the Trust announced that the Board has set the
distribution policy for the second quarter of 2008 at a monthly distribution
rate of $0.04 per unit, subject to monthly confirmation by the Board of
Directors, based on current commodity prices, hedging program, anticipated
production volumes and market conditions. True anticipates its $0.04 per unit
monthly distributions to be sustainable in the current gas price, foreign
exchange rate and cost environment.

    Production

    2008 first quarter sales volumes averaged 13,552 boe/d as compared to
14,937 boe/d in the fourth quarter of 2007. In addition to natural production
declines, field production in the first quarter of 2008 was adversely impacted
by the extreme weather experienced in January and February of 2008. An
unplanned third party plant outage also impacted production in west central
Alberta for February 2008.
    The Kerrobert SAGD project continues to show positive response to the
ongoing reservoir heating. Temperatures of up to 140 degrees Celsius are being
observed in the new thermal producing wells as compared to initial reservoir
temperatures of approximately 30 degrees Celsius. Fluid levels and reservoir
pressure continue to build however withdrawal rates are being carefully
restricted to control development of the steam chamber and ensure uniform
heating and conformance along the entire length of the horizontal producers.
True's goal is to maximize the long term success of the project and avoid
issues experienced in earlier projects by other operators such as collapsing
the steam chamber or pulling in cold bottom water by drawing on the producers
too hard, too early in the process.

    Drilling

    During the first quarter of 2008, True achieved a 75% success rate in
drilling or participation in 4 (3.0 net) working interest wells, resulting in
2 (1.0 net) gas wells, 1 (1.0 net) light oil wells, and 1 (1.0 net) dry hole.
The drilling program is expected to resume in third quarter following spring
break-up and the associated road ban issues.

    Financial

    Funds flow from operations for the first quarter of 2008 was
$24.3 million on gross sales of $70.0 million compared to funds flow from
operations of $30.0 million on gross sales of $71.2 million for the same
period in 2007. The decrease in funds flow for the 2008 first quarter was
primarily the result of lower sales volumes, partially offset by higher
overall commodity prices and operating netbacks in the period. Funds flow from
operations for the first quarter of 2008 increased 25% from fourth quarter
2007 funds flow from operations of $19.5 million, reflecting improved
commodity prices.
    The net loss for the first quarter of 2008 of $18.6 million was primarily
due to higher mark-to-market unrealized losses on commodity risk management
contracts of $17.7 million. This compares to a net loss of $8.6 million for
the first quarter of 2007.

    Dispositions

    On December 17, 2007, True announced its intention to divest of its
Saskatchewan assets and reduce the distribution level as part of a new
strategic direction for the Trust. Proceeds from the proposed divestiture
would be utilized to reduce True's bank indebtedness and the reduced
distribution level ensured additional financial resources.
    The additional cash flow generated though improved pricing has eased debt
concerns and allowed the Trust to modify the path of the new strategic
direction. On April 30, 2008 True announced that the sale of the
Dodsland-Stranraer asset, one of five asset packages comprising the
Saskatchewan divestiture program, had been successfully completed for net
proceeds after adjustments of $39.3 million, which will be reflected in True's
second quarter results. True further announced its decision to not pursue
further Saskatchewan asset disposition options at this time. The Trust feels
that the goal of increased financial flexibility is sufficiently achieved
through the combination of improved commodity prices, receipt of the
Dodsland-Stranraer sale proceeds, and a continued distribution level of $0.04
per unit per month, while retaining a larger asset and production base.
    In the first quarter of 2008, True was successful in completing the
divestiture of a non-core property in the Northeast area of Alberta for net
proceeds after adjustments of $5.8 million. Subsequent to quarter-end and in
early April 2008, True was also successful in completing the divestiture of a
small non-core property in the Northwest area of Alberta for net proceeds
after adjustments of $0.3 million. The proceeds were used to pay down debt.
True continuously reviews and optimizes its portfolio, divesting of non-core
and high cost properties.

    Liquidity

    True's net debt, excluding unrealized commodity contract assets and
liabilities, future income taxes and asset retirement obligations, as at
March 31, 2008 was $240.3 million, representing $171.9 million outstanding on
the credit facility, $79.8 million in convertible debentures (liability
component) and net the balance of working capital.
    As at March 31, 2008, the existing credit facility consists of a
$15 million demand operating facility provided by one Canadian bank and a
$175 million extendible revolving term credit facility syndicated by two
Canadian chartered banks, a U.S. bank, a Canadian financial institution and
one institutional lender.
    On March 31, 2008, True's borrowing base redetermination was re-scheduled
for renewal on or before June 2, 2008, while the Saskatchewan asset
divestiture was being finalized. To reflect the recent dispositions in True's
borrowing base, True's borrowing base was reduced from $190 million as at
March 31, 2008 to $164.5 million effective as at April 30, 2008. As at
April 30, 2008, there is approximately $40 million not drawn on these
facilities. Further borrowing base reductions are scheduled to occur on
June 2, 2008 and June 30, 2008, which will bring True's borrowing base to
$152 million as at June 30, 2008. The revolving period on the term credit
facility is also subject for renewal on June 28, 2008. The revolving period on
the term credit facility ends on June 30, 2008, unless extended for a further
364 day period. Should the facilities not be renewed they convert to 366 day
non-revolving term facilities on the renewal date.
    True does not hold any Asset-Backed Commercial Paper investments.
    In August 2007, True received Toronto Stock Exchange approval for its
normal course issuer bid ("NCIB") for the repurchase of its trust units from
August 28, 2007 to August 27, 2008, entitling the Trust to purchase up to
approximately 7.8 million of its outstanding trust units. Starting in the
fourth quarter and through the end of 2007, 500,000 units were repurchased at
a total price of $1.7 million. Future repurchases will be dependent on excess
cash available after consideration of the Trust's priority uses of cash and
the trading price of the Trust's units. No units were purchased during the
first quarter of 2008.
    True has maintained an active commodity price risk management program.
Approximately 50% of current natural gas production is hedged through the
remainder of 2008 and approximately 29% is hedged through the first half of
2009. Approximately 40% of current liquids production is hedged through the
remainder of 2008. No liquids are currently hedged subsequent to December 31,
2008. The Trust will continue its hedging strategies focusing on maintaining
sufficient cash flow to fund True's unitholder distributions and the capital
program.

    Alberta Royalty Regime

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

    2008 True Capex Budget

    True's first quarter 2008 capital program of approximately $8.7 million
compares to a front end loaded 2007 capital program of approximately
$46 million in first quarter 2007. True plans to continue to take a balanced
approach to the priority use of cash flow between level of distributions and
size of its 2008 capital program. True's 2008 capital expenditure program is
currently planned at $40 million. Given the nature of True's lands and their
inherent advantage of year round access, True plans to spread its 2008 capital
program more evenly through the full year of 2008 to take advantage of reduced
service costs during non-peak times. True plans to focus on increasing its
farm-out activity in non-core areas. As the 2008 outlook for commodity prices
improves, True may look to increase its capital spending in the latter part of
2008.

    Personnel Announcements

    As noted in the recently published Information Circular - Proxy
Statement, Mr. Norman Holton is not standing for nomination as a continuing
Director. On behalf of the Board I would like to thank Norm for his
contributions to True.
    True's annual and special meeting is scheduled for 2:00pm on May 21, 2008
in the Grand Lecture Theatre at the Metropolitan Conference Center in Calgary.

    Wayne M. Chorney, P. Eng.
    President, CEO and COO
    May 8, 2008MANAGEMENT'S DISCUSSION AND ANALYSISMay 8, 2008 - The following Management's Discussion and Analysis of
financial results as provided by the management of True Energy Trust ("True"
or the "Trust") should be read in conjunction with the unaudited interim
consolidated financial statements and selected notes for the three months
ended March 31, 2008 and the audited consolidated financial statements for the
years ended December 31, 2007 and 2006 for the Trust. This commentary is based
on information available to, and is dated, May 8, 2008. The financial data
presented is in accordance with Canadian generally accepted accounting
principles ("GAAP") in Canadian dollars, except where indicated otherwise.

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

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

    FORWARD LOOKING STATEMENTS: Certain information contained herein may
contain forward looking statements including management's assessment of future
plans and operations, drilling plans and the timing thereof, expected
production increases from certain projects and the timing thereof, the effect
of government announcements, proposals and legislation, plans regarding wells
to be drilled, expected or anticipated production rates, expected exchange
rates, distributions and method of funding thereof, proportion of
distributions anticipated to be taxable and non-taxable, anticipated borrowing
base under credit facility, maintenance of productive capacity and capital
expenditures and the nature of capital expenditures and the timing and method
of financing thereof, may constitute forward-looking statements under
applicable securities laws and necessarily involve risks including, without
limitation, risks associated with oil and gas exploration, development,
exploitation, production, marketing and transportation, loss of markets,
volatility of commodity prices, currency fluctuations, imprecision of reserve
estimates, environmental risks, competition from other producers, inability to
retain drilling rigs and other services, incorrect assessment of the value of
acquisitions, failure to realize the anticipated benefits of acquisitions,
delays resulting from or inability to obtain required regulatory approvals and
ability to access sufficient capital from internal and external sources. The
recovery and reserve estimates of True's reserves provided herein are
estimates only and there is no guarantee that the estimated reserves will be
recovered. Events or circumstances may cause actual results to differ
materially from those predicted, as a result of the risk factors set out and
other known and unknown risks, uncertainties, and other factors, many of which
are beyond the control of True. In addition, forward-looking statements or
information are based on a number of factors and assumptions which have been
used to develop such statements and information but which may prove to be
incorrect. Although the Trust believes that the expectations reflected in such
forward-looking statements or information are reasonable, undue reliance
should not be placed on forward-looking statements because the Trust can give
no assurance that such expectations will prove to be correct. In addition to
other factors and assumptions which may be identified herein, assumptions have
been made regarding, among other things: the impact of increasing competition;
the general stability of the economic and political environment in which the
Trust operates; the timely receipt of any required regulatory approvals; the
ability of the Trust to obtain qualified staff, equipment and services in a
timely and cost efficient manner; drilling results; the ability of the
operator of the projects which the Trust has an interest in to operate the
field in a safe, efficient and effective manner; the ability of the Trust to
obtain financing on acceptable terms; field production rates and decline
rates; the ability to replace and expand oil and natural gas reserves through
acquisition, development of exploration; the timing and costs of pipeline,
storage and facility construction and expansion and the ability of the Trust
to secure adequate product transportation; future commodity gas prices;
currency, exchange and interest rates; the regulatory framework regarding
royalties, taxes and environmental matters in the jurisdictions in which the
Trust operates; and the ability of the Trust to successfully market its oil
and natural gas products. Readers are cautioned that the foregoing list is not
exhaustive of all factors and assumptions which have been used. As a
consequence, actual results may differ materially from those anticipated in
the forward-looking statements. Additional information on these and other
factors that could effect True's operations and financial results are included
in reports on file with Canadian securities regulatory authorities and may be
accessed through the SEDAR website (www.sedar.com), at True's website
(www.trueenergytrust.com). Furthermore, the forward-looking statements
contained herein are made as at the date hereof and True does not undertake
any obligation to update publicly or to revise any of the included
forward-looking statements, whether as a result of new information, future
events or otherwise, except as may be required by applicable securities laws.
    The reader is further cautioned that the preparation of financial
statements in accordance with GAAP requires management to make certain
judgments and estimates that affect the reported amounts of assets,
liabilities, revenues and expenses. Estimating reserves is also critical to
several accounting estimates and requires judgments and decisions based upon
available geological, geophysical, engineering and economic data. These
estimates may change, having either a negative or positive effect on net
earnings as further information becomes available, and as the economic
environment changes.

    Net Income (Loss) and Funds Flow from Operations

    True generated funds flow from operations of $24.2 million ($0.30 per
diluted unit) for the three months ended March 31, 2008, down 20% from the
$30.0 million ($0.42 per diluted unit) for the first quarter of 2007. The
decrease in funds flow from operations for the 2008 period was primarily the
result of lower sales volumes, offset significantly by improved commodity
prices and operating netbacks for 2008. Funds flow from operations for the
first quarter of 2008 increased 25% from fourth quarter 2007 funds flow from
operations of $19.5 million.
    True generated a net loss of $18.6 million ($(0.24) per diluted unit) in
the first quarter of 2008 primarily due to higher mark-to-market unrealized
losses on commodity risk management contracts of $17.7 million. This compares
to a net loss of $8.6 million ($(0.12) per diluted unit) for the same period
in 2007.Funds Flow From Operations and Net Income
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($000s, except per unit amounts)                      2008          2007
    -------------------------------------------------------------------------
    Funds flow from operations                          24,233        29,988
      Basic   ($/unit)                                    0.31          0.43
      Diluted ($/unit)                                    0.30          0.42

    Net income (loss)                                  (18,621)       (8,571)
      Basic   ($/unit)                                   (0.24)        (0.12)
      Diluted ($/unit)                                   (0.24)        (0.12)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Reconciliation of Funds Flow from Operations and Cash Flow from Operating
    Activities
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($000s, except per unit amounts)                      2008          2007
    -------------------------------------------------------------------------
    Funds flow from operations                          24,233        29,988
    Asset retirement costs incurred                       (589)         (188)
    Change in non-cash working capital                  (5,801)       10,159
    -------------------------------------------------------------------------
    Cash flow from operating activities                 17,843        39,959
    -------------------------------------------------------------------------Sales Volumes

    Sales volumes for the three months ended March 31, 2008 averaged
13,552 boe/d as compared to 18,461 boe/d for the same period in 2007,
representing a 27% decrease. In comparison, sales volumes for the fourth
quarter of 2008 were 14,937 boe/d. The decrease in average sales volumes from
first quarter 2007 to 2008 was mainly due to natural production declines and
decreased production due to property dispositions during 2007. In addition,
field production for the first quarter of 2008 was adversely impacted by
extreme weather experienced in January and February 2008, as well as an
unplanned third party plant outage impacting production in wet central Alberta
for February 2008.Sales Volumes
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
                                                          2008          2007
    -------------------------------------------------------------------------
    Natural gas                           (mcf/d)       52,252        71,931
    -------------------------------------------------------------------------
    Heavy oil                            (bbls/d)        2,824         4,355
    Light oil and condensate             (bbls/d)        1,391         1,519
    NGLs                                 (bbls/d)          628           598
    -------------------------------------------------------------------------
    Total crude oil and NGLs             (bbls/d)        4,843         6,472
    -------------------------------------------------------------------------
    Total boe/d                             (6:1)       13,552        18,461
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------During the first quarter of 2008, True achieved a 75% success rate in
drilling or participation in 4 (3.0 net) working interest wells, resulting in
2 (1.0 net) gas wells, 1 (1.0 net) light oil wells, and 1 (1.0 net) dry hole. 
The drilling program is expected to resume in third quarter following spring
break-up and the associated road ban issues.
    The Kerrobert SAGD project continues to show positive response to the
ongoing reservoir heating. Temperatures of up to 140 degrees Celsius are being
observed in the new thermal producing wells as compared to initial reservoir
temperatures of approximately 30 degrees Celsius. Fluid levels and reservoir
pressure continue to build however withdrawal rates are being carefully
restricted to control development of the steam chamber and ensure uniform
heating and conformance along the entire length of the horizontal producers.
True's goal is to maximize the long term success of the project and avoid
issues experienced in earlier projects by other operators such as collapsing
the steam chamber or pulling in cold bottom water by drawing on the producers
too hard, too early in the process.
    For the three months ended March 31, 2008, the weighting towards natural
gas sales averaged 64% compared to 65% in the same period in 2007. Heavy oil
sales made up 21% of total production for the 2008 first quarter compared to
24% in the 2007 first quarter.
    Sales of natural gas averaged 52.3 mmcf/d for the first quarter of 2008,
compared to 71.9 mmcf/d in the same period of 2007, a decrease of 27%. Crude
oil and NGL sales for the first quarter of 2008 averaged 4,843 bbls/d,
compared to 2007 first quarter average sales of 6,472 bbls/d.Commodity Prices

    Average Commodity Prices
    -------------------------------------------------------------------------
                                   Three months ended March 31,
                                            2008          2007      % change
    -------------------------------------------------------------------------
    Exchange rate (US$/Cdn$)              0.9950        0.8535            17

    Natural gas:
    NYMEX (US$/mmbtu)                       8.64          7.17            20
    Alberta spot ($/mcf)                    7.97          7.39             8
    True's average price ($/mcf)            7.97          7.26            10
    True's average price (including
     hedging(1)) ($/mcf)                    7.99          7.52             6

    Crude oil:
    WTI (US$/bbl)                          97.22         58.27            67
    Edmonton par - light oil ($/bbl)       98.16         67.73            45
    Bow River - medium/heavy oil ($/bbl)   77.47         49.73            56
    Hardisty Heavy - heavy oil ($/bbl)     70.05         42.50            65
    True's average prices ($/bbl)
      Light crude oil, condensate and
       NGLs                                85.65         50.77            69
      Light crude oil, condensate and
       NGLs (including hedging(1))         62.58         58.36             7
      Heavy crude oil                      61.55         36.64            68
      Total crude oil and NGLs             71.59         41.26            74
      Total crude oil and NGLs (including
       hedging(1))                         61.98         43.75            42
    -------------------------------------------------------------------------

    (1) Per unit metrics including hedging include realized gains or losses
        on commodity contracts and exclude unrealized gains or losses on
        commodity contracts.True's natural gas is primarily sold on the daily spot market. During the
first quarter of 2008, the AECO Spot reference price increased by 8% compared
to the same period in 2007. Similarly, True's average sales price before
hedging for the first quarter of 2008 increased by 10% compared to the same
period in 2007. In comparison, True's first quarter 2008 natural gas price
before hedging was 25% higher than the fourth quarter 2007 price of $6.40/mcf.
True's natural gas price after including hedging for the first quarter of 2008
was $7.99/mcf compared to $7.52/mcf for the same period in 2007.
    For heavy crude oil, True received an average price before transportation
of $61.55/bbl for the first quarter of 2008, a increase of 68% over prices in
the 2007 period. The Bow River reference price increased by 56% and the
Hardisty Heavy reference price increased by 65% over the same period. The
majority of True's heavy crude oil density ranges between 11 and 16 degrees
API consistent with the Hardisty Heavy reference price.
    For light oil, condensate and NGLs, True recorded an average $85.65/bbl
before hedging during the first quarter of 2008, 69% higher than the average
price received in the same period of 2007. The Edmonton par price increased by
45% over the same period. The average WTI crude oil US dollar based price
increased 67% from the first quarter of 2007 to that in 2008. In comparison,
True's realized price for the first quarter of 2008 increased 9% from the
fourth quarter 2007 average price of $78.42/bbl, whereas the Edmonton par
price increased by 13%. True's realized price after including hedging was
$62.58/bbl for the first quarter of 2008 compared to $57.88/bbl for the same
period in 2007.

    Revenue

    Revenue before other income and hedging for the three months ended
March 31, 2008 was $69.4 million, 2% less than the $71.0 million in the same
period in 2007. The lower revenue for the 2008 period was the result of lower
production volumes for natural gas, crude oil, condensate and NGLs, offset
significantly by increased crude oil and natural gas prices.-------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($000s)                                               2008          2007
    -------------------------------------------------------------------------
    Light crude oil, condensate and NGLs                15,734         9,675
    Heavy oil                                           15,818        14,362
    -------------------------------------------------------------------------
    Crude oil and NGLs                                  31,552        24,037
    Natural gas                                         37,894        46,982
    -------------------------------------------------------------------------
    Total revenue before other                          69,446        71,019
    Other(1)                                               587           177
    -------------------------------------------------------------------------
    Total revenue before royalties and hedging          70,033        71,196
    -------------------------------------------------------------------------

    (1) Other revenue primarily consists of processing and other third party
        income.Financial Instruments

    The Trust has a formal risk management policy which permits management to
use specified price risk management strategies for up to 50% of crude oil,
natural gas and NGL production including fixed price contracts, 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.
    The Trust will continue its hedging strategies focusing on maintaining
sufficient cash flow to fund True's unitholder distributions and capital
program.
    A summary of the hedge volumes and average prices by quarter currently
outstanding as of May 8, 2008 is shown in the following tables (see Note 15 to
the consolidated financial statements for a detailed disclosure of all
commodity contracts in place as at May 8, 2008):Crude oil and liquids     Average Volumes (bbls/d)
    -------------------------------------------------------------------------
                                    Q2-Q3 2008   Q4 2008   Q1 2009   Q2 2009
    -------------------------------------------------------------------------
    Costless collars                     2,000     2,000         -         -
    -------------------------------------------------------------------------
    Total bbls/d                         2,000     2,000         -         -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Average Price (US$/bbl WTI)
    -------------------------------------------------------------------------
                                    Q2-Q3 2008   Q4 2008   Q1 2009   Q2 2009
    -------------------------------------------------------------------------
    Collar ceiling price                 82.00     82.00         -         -
    Collar floor price                   65.00     65.00         -         -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Natural gas     Average Volumes (GJ/d)
    -------------------------------------------------------------------------
                                    Q2-Q3 2008   Q4 2008   Q1 2009   Q2 2009
    -------------------------------------------------------------------------
    Costless collars                         -         -         -         -
    Fixed                               24,326    24,326    10,550    10,550
    -------------------------------------------------------------------------
    Total GJ/d                          24,326    24,326    10,550    10,550
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Average Price ($/GJ AECO C)
    -------------------------------------------------------------------------
                                    Q2-Q3 2008   Q4 2008   Q1 2009   Q2 2009
    -------------------------------------------------------------------------
    Collar ceiling price                     -         -         -         -
    Collar floor price                       -         -         -         -
    Fixed                                 6.68      6.89      7.74      7.01
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    As of March 31, 2008, the fair value of True's outstanding commodity
contracts is an unrealized liability of $28.0 million as reflected in the
financial statements.
    The following is a summary of the gain (loss) on commodity contracts for
the three month period ended March 31, 2008 and 2007:

    Commodity contracts
    -------------------------------------------------------------------------
                                       Crude Oil       Natural          2008
    ($000s)                            & Liquids           Gas         Total
    -------------------------------------------------------------------------
    Realized cash gain (loss) on
     contracts                            (4,239)           97        (4,142)
    Unrealized gain (loss) on
     contracts(2)                            898       (18,585)      (17,687)
    -------------------------------------------------------------------------
    Total gain (loss) on commodity
     contracts                            (3,341)      (18,488)      (21,829)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
                                       Crude Oil       Natural          2007
    ($000s)                            & Liquids           Gas         Total
    -------------------------------------------------------------------------
    Realized cash gain (loss) on
     contracts(1)                          1,447         1,697         3,144
    Unrealized gain (loss) on
     contracts(2)                            (92)       (2,373)       (2,465)
    -------------------------------------------------------------------------
    Total gain (loss) on commodity
     contracts                             1,355          (676)          679
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Includes the crude oil and natural gas commodity contract premium
        expenses in the period and the amortization of prior year crude oil
        and natural gas commodity contract premiums of a total $2.4 million
        for the three months ended March 31, 2007.
    (2) Unrealized gain (loss) commodity contracts represent non-cash
        adjustments for changes in the fair value of these contracts during
        the period.

    Royalties

    For the three months ended March 31, 2008, total royalties were
$15.0 million, compared to $14.9 million incurred in the same period in 2007.
Overall royalties as a percentage of revenue (after transportation costs) in
the first quarter of 2008 were 23%, compared with 21% in the same period in
2007. Royalties for the 2007 first quarter included the impact of the reversal
of certain over accruals of light and heavy crude oil royalties from periods
prior to 2007 of approximately $1.9 million; excluding that adjustment, the
average royalty rate for the first quarter of 2007 would have been 24%.

    -------------------------------------------------------------------------
    Royalties by Commodity Type                  Three months ended March 31,
    ($000s, except where noted)                           2008          2007
    -------------------------------------------------------------------------
    Light crude oil, condensate and NGLs                 3,766           881
      $/bbl                                              20.50          4.62
      Average light crude oil, condensate, and NGLs
       royalty rate (%)                                     25             9

    Heavy Oil                                            2,291         1,519
      $/bbl                                               8.91          3.88
      Average heavy oil royalty rate (%)                    15            11

    Natural Gas                                          9,443        12,494
      $/mcf                                               1.99          1.93
      Average natural gas royalty rate (%)                  25            27
    -------------------------------------------------------------------------
    Total                                               15,500        14,894
    -------------------------------------------------------------------------
      $/boe                                              12.57          8.96
    -------------------------------------------------------------------------
      Average total royalty rate (%)                        23            21
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Royalties, by Type
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($000s)                                               2008          2007
    -------------------------------------------------------------------------
    Crown royalties                                      9,899         6,203
    Indian Oil and Gas Canada royalties                  4,215         3,142
    Freehold & GORR                                      1,386         5,549
    -------------------------------------------------------------------------
    Total                                               15,500        14,894
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Expenses
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($000s)                                               2008          2007
    -------------------------------------------------------------------------
    Production                                          16,996        14,972
    Transportation                                         843           689
    General and administrative                           3,770         4,904
    Interest and financing charges                       4,516         4,547
    Unit-based compensation                                269         1,112
    -------------------------------------------------------------------------

    Expenses per boe
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($ per boe)                                           2008          2007
    -------------------------------------------------------------------------
    Production                                           13.78          9.01
    Transportation                                        0.68          0.41
    General and administrative                            3.06          2.95
    Interest and financing charges                        3.66          2.74
    Unit-based compensation                               0.22          0.67
    -------------------------------------------------------------------------Production Expenses

    For the three months ended March 31, 2008, production expenses totaled
$17.0 million, compared to $15.0 million recorded in the same period in 2007.
During the first quarter of 2008, production expenses averaged $13.78/boe,
compared to $9.01/boe over the same period in 2007. Production expenses are
increased as additional natural gas input costs are required to operate the
Kerrobert SAGD facility after startup in late 2007; this adds approximately
$1.83/boe to production expenses in the first quarter of 2008. The increase in
2008 costs on a boe basis was also due to a significant fixed component of
production expenses in combination with substantially reduced production
volumes.Production Expenses, by Commodity Type
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($000s, except where noted)                           2008          2007
    -------------------------------------------------------------------------
    Light crude oil, condensate and NGLs                 3,081         2,517
      $/bbl                                              16.77         13.21

    Heavy oil                                            5,035         5,408
      $/bbl                                              19.59         13.79

    Natural gas                                          8,880         7,050
      $/mcf                                               1.87          1.09

    -------------------------------------------------------------------------
    Total                                               16,996        14,972
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
      $/boe                                              13.78          9.01
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Total                                               16,996        14,972
    Processing and other third party income(1)            (587)         (177)
    -------------------------------------------------------------------------
    Total after deducting processing and other third
     party income                                       16,409        14,795
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
      $/boe                                              13.31          8.90
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Processing and other third party income is included within petroleum
        and natural gas sales on the statement of income.Operating Netback

    For the first quarter of 2008, corporate field operating netback (before
hedging) was $29.28/boe compared to $24.36/boe in the same period in 2007.
This was the result of increased overall commodity prices, offset by higher
royalties and operating costs experienced in the 2008 period. By comparison,
corporate field operating netback (before hedging) for the fourth quarter of
2007 was $20.51/boe. After including hedging activities, the corporate field
operating netback for the first quarter of 2008 was $25.92/boe compared to
$26.25/boe in the same period in 2007.Field Operating Netback - Corporate (before hedging)
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($/boe)                                               2008          2007
    -------------------------------------------------------------------------
    Sales                                                56.31         42.74
    Transportation                                       (0.68)        (0.41)
    Royalties                                           (12.57)        (8.96)
    Production expense                                  (13.78)        (9.01)
    -------------------------------------------------------------------------
    Field operating netback                              29.28         24.36
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------Field operating netback for natural gas for the first quarter of 2008
increased 3% to $4.21/mcf, compared to $4.09/mcf for the same period in 2007,
reflecting stronger natural gas prices experienced, the effects of which were
partially offset by higher production expenses. After including hedging
activities, field operating netback for natural gas for the first quarter of
2008 was $4.23/mcf compared to $4.35/mcf in the same period in 2007.Field Operating Netback - Natural Gas (before hedging)
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($/mcf)                                               2008          2007
    -------------------------------------------------------------------------
    Sales                                                 7.97          7.26
    Transportation                                        0.10         (0.15)
    Royalties                                            (1.99)        (1.93)
    Production expense                                   (1.87)        (1.09)
    -------------------------------------------------------------------------
    Field operating netback                               4.21          4.09
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------Field operating netback for crude oil and NGLs averaged $36.48/bbl for
the first quarter of 2008, up 52% compared to $24.06/bbl for the same period
in 2007, compared to a 74% increase in the crude oil and NGLs sales price over
the same period. After including hedging activities, field operating netback
for crude oil and NGLs for the first quarter of 2008 was $26.86/boe compared
to $26.55/boe in the same period in 2007.Field Operating Netback - Crude Oil and NGLs (before hedging)
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($/bbl)                                               2008          2007
    -------------------------------------------------------------------------
    Sales                                                71.59         41.26
    Transportation                                       (2.95)         0.52
    Royalties                                           (13.74)        (4.12)
    Production expense                                  (18.42)       (13.60)
    -------------------------------------------------------------------------
    Field operating netback                              36.48         24.06
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------General and Administrative

    Net general and administrative ("G&A") expenses for the three months
ended March 31, 2008 was $3.8 million compared to $4.9 million for the same
period in 2007. The decrease in the G&A expense from the first quarter of 2007
to the same period in 2007 is reflects a reduction of the number of salaried
personnel on staff and other efforts to reduce costs. On a per boe basis, G&A
expenses were $3.06/boe for the first quarter of 2008 compared to $2.95/boe
for 2007. The increase in G&A on a per boe basis is consistent with reduced
sales volumes experienced in the first quarter of 2008 compared to 2007.General and Administrative Expenses
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($000s, except where noted)                           2008          2007
    -------------------------------------------------------------------------
    Gross expenses                                       4,879         6,410
    Capitalized                                           (507)         (693)
    Recoveries                                            (602)         (813)
    -------------------------------------------------------------------------
    Net expenses                                         3,770         4,904
    -------------------------------------------------------------------------
    Net expenses, per unit ($/boe)                        3.06          2.95
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------Interest and Financing Charges

    True recorded $4.9 million of interest and financing charges for the
three months ended March 31, 2008 compared to $4.6 million in the same period
in 2007. True's net debt at March 31, 2008 of $240.3 million includes the
$79.8 million liability portion of convertible debentures, $171.9 million of
bank debt and net of the balance of working capital.Interest and Financing Charges
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($000s, except where noted)                           2008          2007
    -------------------------------------------------------------------------
    Interest and financing charges                       4,516         4,547
    Interest and financing charges ($/boe)                3.66          2.74

    Net debt(1) including convertible debentures
     at quarter end                                    240,318       288,370
    Debt to periods funds flow from operations
     ratio annualized(2)                                  2.5x          2.4x

    Net debt excluding convertible debentures at
     quarter end                                       160,481       210,127
    Debt to periods funds flow from operations ratio
     annualized(2)                                        1.7x          1.8x
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Net debt includes the net working capital deficiency before short-
        term commodity contract assets and liabilities and short-term future
        tax assets. Total net debt also includes the liability component of
        convertible debentures and excludes asset retirement obligations and
        the future income tax liability.
    (2) Debt to funds flow from operations ratio is calculated based upon
        first quarter funds flow from operations annualized.Unit-Based Compensation

    Non-cash unit-based compensation expense for the three month period ended
March 31, 2008 was $0.3 million compared to $1.1 million in the same period in
2007. The decrease in the expense for the first quarter of 2008 reflects a
reduction in the estimated weighted average fair value of incentive rights
granted for more recent options, a reduction to the 2008 expense of
$0.2 million for a reversal of prior year unit-based compensation expense for
2008 forfeitures of unvested incentive rights and reduced incentive rights
being granted in 2008 compared to the 2007 period.

    Capital Expenditures

    True invested $8.5 million on exploration and development activities
during the first three months of 2008, compared to $45.7 million in the same
period in 2007.
    During the first quarter of 2008, True achieved a 75% success rate in
drilling or participation in 4 (3.0 net) working interest wells, resulting in
2 (1.0 net) gas wells, 1 (1.0 net) light oil wells, and 1 (1.0 net) dry hole.Capital Expenditures(1)
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($000s)                                               2008          2007
    -------------------------------------------------------------------------
    Lease acquisitions and retention                       550           791
    Geological and geophysical                              67         6,919
    Drilling and completion costs                        6,512        33,071
    Facilities and equipment                             1,324         4,872
    -------------------------------------------------------------------------
      Exploration and development                        8,453        45,653
    Corporate and property acquisitions                    197           705
    -------------------------------------------------------------------------
      Total capital expenditures - cash                  8,650        46,358
    Property dispositions - cash                        (5,788)      (18,443)
    -------------------------------------------------------------------------
      Total net capital expenditures - cash              2,862        27,915
    -------------------------------------------------------------------------
    Other - non-cash(2)                                   (193)          624
    -------------------------------------------------------------------------
      Total capital expenditures                         2,669        28,539
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Excludes capitalized costs related to asset retirement obligation
        expenditures incurred during the year.
    (2) Other includes current period's asset retirement obligations and unit
        based compensation capitalized.The $8.7 million capital program for the first quarter of 2008 was
financed entirely with funds flow from operations compared to 65% in the same
period in 2007.
    True plans to continue to take a balanced approach to the priority use of
cash flow between level of distributions and size of its 2008 capital program.
True's 2008 capital expenditure program is currently planned at $40 million.
Given the nature of True's lands and their inherent advantage of year round
access, True plans to spread its 2008 capital program more evenly through the
full year of 2008 to take advantage of reduced service costs during non-peak
times. True plans to focus on increasing its farm-out activity in non-core
areas. As the 2008 outlook for commodity prices improves, True may look to
increase its capital spending in latter part of 2008.
    True holds an extensive land base. At March 31, 2008, True had
approximately 503,200 net undeveloped acres of land of its total developed and
undeveloped net acreage position of 893,500 net acres in Saskatchewan,
Alberta, and British Columbia.
    Dispositions during the first quarter of 2008 consisted principally of
the divestiture of a small non-core property in the Northeast area of Alberta
for net proceeds after adjustments and closing costs of $5.8 million. All
significant conditions of closing of this divestiture were satisfied on
March 31, 2008 and the disposal proceeds, included in accounts receivable at
March 31, 2008, were received on April 2, 2008.
    Subsequent to quarter-end and in early April 2008, True was successful in
completing the divestiture of another small non-core property in the Northwest
area of Alberta for net proceeds after adjustments of $0.3 million. The
proceeds were used to pay down debt.
    On April 30, 2008 True closed on the sale of its Dodsland-Stranrear
property in Saskatchewan for net proceeds of $39.3 million, after closing
adjustments and costs. Dodsland-Stranrear is 1 of 5 packages of Saskatchewan
assets originally announced for divestiture.
    At the end of the first quarter of 2008, the Trust had committed to drill
a total of 2 wells in Alberta with varying commitment dates up to the end of
the third quarter of 2008 pursuant to various farm-in agreements with oil and
gas companies. True expects to satisfy these various drilling commitments at
an estimated cost for True's interest of approximately $2.8 million.

    Depletion, Depreciation and Accretion

    Depletion, depreciation and accretion expense for the three months ended
March 31, 2008 was $36.3 million ($29.44/boe), compared to the $47.5 million
($28.56/boe) in the same period of 2007, which reflects reduced carrying costs
in 2008, combined with lower production volumes in the 2008 period as compared
to 2007.
    For the three month period ended March 31, 2008, True has included
$54.2 million for future development costs in the depletion calculation and
excluded from the depletion calculation $35.2 million for undeveloped land and
$45.9 million for estimated salvage.Depletion, Depreciation and Accretion Costs
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($000s, except where noted)                           2008          2007
    -------------------------------------------------------------------------
    Depletion and Depreciation                          35,748        46,947
    Accretion                                              555           511
    -------------------------------------------------------------------------
        Total                                           36,303        47,458
    -------------------------------------------------------------------------
    Per unit ($/boe)                                     29.44         28.56
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------Ceiling Test

    The Trust calculates a ceiling test quarterly and annually to place a
limit on the aggregate carrying value of its capitalized costs, which may be
amortized against revenues of future periods. The ceiling test is performed in
accordance with the requirements of the Canadian Institute of Chartered
Accountants ("CICA") AcG-16 "Oil and Gas Accounting - Full Cost, a two step
process.
    The Trust performed a ceiling test calculation at March 31, 2008
resulting in undiscounted cash flows from proved reserves and the undeveloped
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 undeveloped 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 as at
March 31, 2008.
    The ceiling test calculation will be updated during the remainder of 2008
on a quarterly and annual basis based upon the latest available data,
including but not limited to an updated annual external reserve engineering
report which incorporates a full evaluation of reserves or internal reserve
updates at quarterly periods, and the latest commodity pricing deck.
Estimating reserves is very complex, requiring many judgments based on
available geological, geophysical, engineering and economic data. Changes in
these judgments could have a material impact on the estimated reserves. These
estimates may change, having either a negative or positive effect on net
earnings as further information becomes available and as the economic
environment changes.

    Asset Retirement Obligations

    As at March 31, 2008, the Trust has recorded an Asset Retirement
Obligation ("ARO") of $28.5 million, compared to $26.4 million at March 31,
2007, for future abandonment and reclamation of the Trust's properties. For
the three months ended March 31, 2008, the ARO increased by $0.1 million total
as a result of accretion expense of $0.6 million, and $0.5 million net changes
in estimates and liabilities incurred on development activities, offset by
$0.4 million of liabilities released on dispositions and $0.6 million of
liabilities settled during the year.

    Income Taxes

    For the three months ended March 31, 2008, the Trust has recorded capital
tax expense of $0.5 million compared to $0.9 million expensed in the same
period of 2007. Capital taxes are based on debt and equity levels of the Trust
at the end of the year in addition to a resource surcharge component of
provincial taxes calculated as a percentage of revenues. In the second quarter
of 2006, the federal government enacted legislation that eliminates federal
capital tax, retroactive to January 1, 2006. As a result, since that date
capital taxes are based on only provincial capital taxes.
    Future income taxes arise from differences between the accounting and tax
bases of the Trust's assets and liabilities. For the three months ended
March 31, 2008, the Trust recognized a future income tax recovery of
$11.8 million compared to a recovery of $12.8 million in the same period in
2007. 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. On June 12,
2007, the federal government further reduced the general corporate tax rate by
0.5 percent starting 2011. Further as indicated on October 30, 2007 and
enacted on December 14, 2007, the federal government announced changes to the
tax system including reduction of the corporate income tax rate from
22.1 percent to 15 percent by 2012, with these reductions to be phased in
between 2008 and 2012. The reduction in the general corporate tax rate will
also apply to the taxation of Income Trusts. On February 26, 2008, the federal
government, in its budget, announced changes to the provincial component of
the SIFT tax whereby such component will be based on the provincial rates
where the SIFT has a permanent establishment rather than using a 13 percent
flat rate. As True currently has its permanent establishment in the Province
of Alberta, its combined SIFT tax rate applicable in 2012 is expected to fall
from 28 percent to 25 percent.
    Under our current structure, the operating entities make interest and
royalty payments to the Trust, which transfers taxable income to the Trust to
eliminate income subject to corporate and other income taxes in the operating
entities. With the new legislation (as referred to below), such amounts
transferred to the Trust could be taxable beginning in 2011 as distributions
will no longer be deductible for income tax purposes. At that time, True could
claim tax pools in its operating companies, reduce the income transferred to
the Trust, and pay all or a portion of distributions as a return of capital.
Until 2011, under the terms of its trust indenture, the Trust is required to
distribute amounts equal to at least its taxable income. In the event that the
Trust has undistributed taxable income in a taxation year (prior to 2011), an
additional special taxable distribution, subject to certain withholding taxes,
would be required by the terms of its trust indenture.
    The estimate of future taxes is based on the current tax status of the
Trust. Future events, which could materially affect future income taxes such
as acquisitions and dispositions and modifications to the distribution policy,
are not reflected under Canadian GAAP until the events occur and the related
legal requirements have been fulfilled. As a result, future changes to the tax
legislation could lead to a material change in the recorded amount of future
income taxes.
    The new legislation is not expected to directly affect our cash flow
levels and distribution policies until 2011 at the earliest.

    Enactment of the Tax on Income Trusts

    On June 12, 2007, the legislation implementing the new tax (the "SIFT
tax") on publicly traded income trusts and limited partnerships, referred to
as "Specified investment flow-through" ("SIFTs") entities (Bill C-52) received
third reading in the House of Commons and on June 22, 2007, Bill C-52 received
Royal assent. As a result, the SIFT tax was considered to be enacted for
accounting purposes in June 2007, which resulted in a $1.2 million future
income tax recovery amount being recorded to reflect current temporary
differences between the book and tax basis of assets and liabilities expected
to be remaining in the Trust in 2011. The SIFT tax announcement and the
related future income tax recovery did not affect cash flow or distributions
and is not expected to affect distribution policies until 2011 at the
earliest.
    SIFTs are certain publicly traded income and royalty trusts and limited
partnerships including True. For SIFTs in existence on October 31, 2006 the
SIFT tax will be effective in 2011, unless certain rules related to "undue
expansion" are not adhered to. Under the guidance provided, True can increase
its equity by approximately $737 million between now and 2011 without
prematurely triggering the SIFT tax.
    Under the current SIFT tax rules, distributions from certain types of
income will not be deductible for income tax purposes by SIFTs in 2011, and
thereafter, and any resultant trust level taxable income will be taxed at a
SIFT tax rate which will be the federal general corporate income tax rate plus
the provincial SIFT tax factor (which is set at a fixed rate of 13%). The SIFT
tax rate was initially proposed at 31.5 percent; however, on October 30, 2007,
the Government of Canada, in its Mini-Budget (Bill C-28), proposed reductions
to the general corporate tax rate, thereby reducing the SIFT rate to
29.5 percent in 2011 and 28.0 percent in 2012 and later. On December 14, 2007,
Bill C-28 received royal assent, resulting in a reduction to the SIFT tax rate
as it becomes effective in 2011, and lowering the rate at which any corporate
income taxes will be paid by True's operating entities. As the operating
companies currently have a significant tax pool base and expect to increase
such tax pool base until 2011, it is expected that the operating companies
could shelter its taxable income for a period after the effective date of the
SIFT tax. It is expected that funds could move from the operating companies to
the Trust as repayments of debt with the result that Trust distributions out
of the funds repaid would not be out of Trust income. Distributions of this
nature would not be currently taxable to unitholders as they would represent a
return of capital that would continue to be an adjustment to a unitholder's
adjusted cost base of trust units. Distributions from income subject to the
SIFT tax will be considered taxable dividends to unitholders and will
generally be eligible for the dividend tax credit. As a result, the SIFT tax
will not adversely affect Canadian investors who hold True units in a non-tax
deferred account.
    On February 26, 2008, the Federal Minister of Finance announced (the
"Provincial SIFT Tax Proposal") that instead of basing the provincial
component of the SIFT tax on a flat rate of 13%, the provincial component will
instead be based on the general provincial corporate income tax rate in each
province in which the SIFT has a permanent establishment. For purposes of
calculating this component of the tax, the general corporate taxable income
allocation formula will be used. Specifically, the Trust's taxable
distributions will be allocated to provinces by taking half of the aggregate
of:-   that proportion of the Trust's taxable distributions for the year
        that the Trust's wages and salaries in the province are of its total
        wages and salaries in Canada; and

    -   that proportion of the Trust's taxable distributions for the year
        that the Trust's gross revenues in the province are of its total
        gross revenues in Canada.Under the Provincial SIFT Tax Proposal the Trust would be considered to
have a permanent establishment only in Alberta, where the provincial tax rate
in 2011 is expected to be 10%. There can be no assurance, however, that the
Provincial SIFT Tax Proposal will be enacted as proposed.
    On December 20, 2007, the Finance Minister announced technical amendments
to provide some clarification to the SIFT tax legislation. As part of the
announcement the Minister indicated that the federal government intends to
provide legislation in 2008 to permit income trusts to convert to taxable
Canadian corporations without any undue tax consequences to investors or the
Trust.
    The True Board of Directors and Management continue to review the impact
of this tax on business strategy. At the present time, True believes some or
all of the following actions will or could result due to the enactment of the
SIFT tax:-   If structural or other similar changes are not made, the distribution
        yield net of the SIFT tax in 2011 and beyond to taxable Canadian
        investors will remain approximately the same; however, the
        distribution yield to tax-deferred Canadian investors (RRSPs, RRIFs,
        pension plans, etc.) would fall by an estimated 26.5 percent in 2011
        and 25.0 percent in 2012 and beyond. For U.S. investors, the
        distribution yield net of the SIFT and withholding taxes would fall
        by an estimated 25.3 percent in 2011 and 25.1 percent in 2012 and
        beyond;
    -   A portion of True's cash flow could be allocated to the payment of
        the SIFT tax, or other forms of tax, and would not be available for
        distribution or re-investment;
    -   True could convert to a corporate structure to facilitate investing a
        higher proportion or all of its cash flow in exploration and
        development projects. Such a conversion and change to capital
        programs could result in a significant reduction to or elimination of
        distributions and/or dividends;
    -   True might determine that it is more economic to remain in the trust
        structure, at least for a period of time, and shelter its taxable
        income using tax pools and pay all or a portion of its distributions
        on a return of capital basis, likely at a lower payout ratio.The Trust is reviewing all organizational structures and alternatives to
minimize the impact of the SIFT tax on our unitholders. While there can be no
assurance that the negative effect of the tax can be minimized or eliminated,
True and its advisors will continue to work diligently on these issues.
    As at March 31, 2008, the operating subsidiaries and the Trust itself
have a total future income tax liability balance of $52.6 million. Canadian
GAAP requires that a future income tax liability be recorded when the book
value of assets exceeds the balance of tax pools.
    At March 31, 2008, the Trust and operating subsidiaries of the Trust had
approximately $521 million in tax pools available for deduction against future
income as follows:-------------------------------------------------------------------------
                                                     Operating
    ($000s)                                Trust  subsidiaries         Total
    -------------------------------------------------------------------------
    Intangible resource pools             15,000       322,000       337,000
    Undepreciated capital cost                 -       142,000       142,000
    Loss carryforwards (expire
     through 2027)                             -        35,000        35,000
    Unit issue costs                       4,000         3,000         7,000
    -------------------------------------------------------------------------
                                          19,000       502,000       521,000
    -------------------------------------------------------------------------Distributions

    Trust unitholders who held their trust units throughout the first quarter
of 2008 received distributions of $0.12 per unit. For the three months ended
March 31, 2008 the Trust declared $9.5 million in total distributions as
follows:-------------------------------------------------------------------------
    ($000s, except per unit amount)               Distribution
    Three months ended March 31, 2008                 Per Unit         Total
    -------------------------------------------------------------------------

    Distributions declared                         $      0.12   $     9,507
    -------------------------------------------------------------------------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
    Calendar Year                       per unit       Portion    of Capital
    -------------------------------------------------------------------------

    2005 (two months)(2)             $     0.480   $     0.456   $     0.024
    2006                                   2.640         2.033         0.607
    -------------------------------------------------------------------------
    Cumulative to Dec. 31, 2006      $     3.120   $     2.489   $     0.631
    -------------------------------------------------------------------------
    2007 year                              0.960         0.960             -
    -------------------------------------------------------------------------
    Cumulative to Dec. 31, 2007      $     4.080   $     3.449   $     0.631
    -------------------------------------------------------------------------
    2008 year to date (three
     months)(3)                            0.120
    ---------------------------------------------
    Cumulative to March 31, 2008     $     4.200
    ---------------------------------------------

    (1) Applies to unitholders who are residents of Canada and hold their
        trust units as capital property.

    (2) Based upon the distributions paid in the 2005 calendar year, after
        the November 2, 2005 Arrangement with TKE Energy Trust.

    (3) It is currently estimated that the approximate taxable portion of
        2008 distributions to Canadian unitholders will be between 90 to
        100%. Any non-taxable amounts will be treated as a tax deferred
        return of capital, or an adjustment to the cost base of the units.
        Actual taxable amounts may vary depending on actual distributions and
        are dependent upon production, commodity prices and funds flow from
        operations experienced throughout the year.

        In consultation with its U.S. tax advisors, True believes that its
        trust units should be "qualified dividends" for U.S. federal
        purposes. As such, the portion of distributions made during 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 February 27, 2008 press release
        addressing this.Monthly Distributions

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

    Ex-distribution                                           Distribution
     Date                Record Date          Payment Date        per unit
    -------------------------------------------------------------------------
    December 27, 2007    December 31, 2007    January 15, 2008      $ 0.08
    January 29, 2008     January 31, 2008     February 15, 2008       0.04
    February 27, 2008    February 29, 2008    March 17, 2008          0.04
    March 27, 2008       March 31, 2008       April 15, 2008          0.04
    April 28, 2008       April 30, 2008       May 15, 2008            0.04
    May 28, 2008(1)      May 30, 2008         June 16, 2008           0.04(2)
    June 26, 2008(1)     June 30, 2008        July 15, 2008           0.04(2)
    -------------------------------------------------------------------------

    (1) Anticipated ex-distribution dates for May and June 2008. These dates
        are subject to change and/or confirmation by the Toronto Stock
        Exchange and will be confirmed by monthly press.
    (2) Subject to confirmation by the board of directors and based on True's
        current commodity prices, hedge positions, anticipated production
        volumes and market conditions and subject to change based an actual
        conditions.During 2008, to date distributions have been funded from funds flow from
operations.

    Foreign Ownership Update

    Based on information from Trust records and information provided by
intermediaries holding Trust units for others, The Trust estimates that, as of
April 18, 2008 approximately 28 percent of unitholders are non-Canadian
residents with the remaining 72 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, 2008 was $240.3 million, representing
$171.9 million outstanding on the credit facility, $79.8 million in
convertible debentures (liability component) and net the balance of working
capital.
    During the three month period ended March 31, 2008, the Trust has reduced
its net debt by approximately $10.8 million. Our calculation of net debt
includes the net working capital deficiency before short-term commodity
contract assets and liabilities and short-term future income tax assets. Total
net debt also includes the liability component of convertible debentures and
excludes asset retirement obligations and long-term future income taxes.
    As at March 31, 2008, the credit facility consists of a $15 million
demand operating facility provided by one Canadian bank and a $175 million
extendible revolving term credit facility syndicated by two Canadian chartered
banks, a U.S. bank, a Canadian financial institution and one institutional
lender. The revolving period on the revolving term credit facility ends on
June 29, 2008, unless extended for a further 364 day period. Should the
facilities not be renewed they convert to 366 day non-revolving term
facilities on the renewal date.
    On March 31, 2008, True's borrowing base redetermination was re-scheduled
for renewal on or before June 2, 2008, while the Saskatchewan asset
divestiture was being finalized. To reflect the recent dispositions in True's
borrowing base, True's borrowing base was reduced from $190 million as at
March 31, 2008 to $164.5 million effective as at April 30, 2008. As at
April 30, 2008, there is approximately $40 million not drawn on these
facilities. Further borrowing base reductions are scheduled to occur on
June 2, 2008 and June 30, 2008, which will bring True's borrowing base to
$152 million as at June 30, 2008. The revolving period on the term credit
facility is also subject for renewal on June 28, 2008.
    The Trust does not hold any Asset-Backed Commercial Paper investments.
    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 16, 2008, the Trust had outstanding a total of 5,219,165
incentive units exercisable at an average exercise price of $8.55 per unit,
374,099 exchangeable shares (convertible, as at April 16, 2008 into an
aggregate of 340,909 trust units, subject to further adjustments based on
distributions made on trust units), $86.25 million principal amount of
debentures convertible into trust units (at a conversion price of $16.00 per
trust unit) and 79,230,460 trust units.
    On April 30, 2008, True closed on the sale of its Dodsland-Stranraer
property in Saskatchewan for net proceeds of $39.3 million, after closing
adjustments. The net proceeds were used to pay down bank indebtedness. True
continuously reviews and optimizes its portfolio, divesting of non-core and
high cost properties.

    Commitments

    As at March 31, 2008, the Trust had committed to drill a total of 2 wells
in Alberta with varying commitment dates up to end of the third quarter of
2008 pursuant to various farm-in agreements with oil and gas companies. True
expects to satisfy these various drilling commitments at an estimated cost for
True's interest of approximately $2.8 million.

    Off-Balance Sheet Arrangements

    The Trust has certain lease agreements, including primarily office space
leases, which were entered into in the normal course of operations. All leases
have been treated as operating leases whereby the lease payments are included
in operating expenses or G&A expenses depending on the nature of the lease. No
asset or liability value has been assigned to these leases in the balance
sheet as of March 31, 2008.

    Business Prospects and 2008 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.
    The Kerrobert SAGD project continues to show positive response to the
ongoing reservoir heating. Temperatures of up to 140 degrees Celsius are being
observed in the new thermal producing wells as compared to initial reservoir
temperatures of approximately 30 degrees Celsius. Fluid levels and reservoir
pressure continue to build however withdrawal rates are being carefully
restricted to control development of the steam chamber and ensure uniform
heating and conformance along the entire length of the horizontal producers.
True's goal is to maximize the long term success of the project and avoid
issues experienced in earlier projects by other operators such as collapsing
the steam chamber or pulling in cold bottom water by drawing on the producers
too hard, too early in the process.
    True anticipates the US$/Cdn.$ exchange rate to average 1.00 through the
2008 year.
    The Trust continues to maintain a large undeveloped land base of
approximately 749,100 (503,200 net) acres containing a significant multi-year
drilling inventory.
    True's first quarter 2008 capital program of approximately $8.7 million
compares to a front end loaded 2007 capital program of approximately
$46 million in first quarter 2007. True plans to continue to take a balanced
approach to the priority use of cash flow between level of distributions and
size of its 2008 capital program. True's 2008 capital expenditure program is
currently planned at $40 million. Given the nature of True's lands and their
inherent advantage of year round access, True plans to spread its 2008 capital
program more evenly through the full year of 2008 to take advantage of reduced
service costs during non-peak times. True plans to focus on increasing its
farm-out activity in non-core areas. As the 2008 outlook for commodity prices
improves, True may look to increase its capital spending in the latter part of
2008.

    Financial Reporting Update

    Capital disclosures

    The CICA issued a new accounting standard, Section 1535 "Capital
Disclosures", which requires the disclosure of both qualitative and
quantitative information that provides users of financial statements with
information to evaluate the entity's objective, policies and processes for
managing capital. This new section is effective for the Trust beginning
January 1, 2008. Refer to note 15 of the financial statements for additional
disclosure for this new section.

    Financial instruments

    Two new accounting standards were issued by the CICA, Section 3862
"Financial Instruments - Disclosures", and Section 3863 "Financial Instruments
- Presentation". These sections will replace Section 3861 "Financial
Instruments - Disclosure and Presentation" once adopted. The objective of
Section 3862 is to provide users with information to evaluate the significance
of the financial instruments on the entity's financial position and
performance, the nature and extent of risks arising from financial
instruments, and how the entity manages those risks. The provisions of Section
3863 deal with the classification of financial instruments, related interest,
dividends, losses and gains, and the circumstances in which financial assets
and financial liabilities are offset. These new sections are effective for the
Trust beginning January 1, 2008. The additional disclosures required under
these sections are included in note 15 of the financial statements.

    International Financial Reporting Standards ("IFRS")

    In September 2007, the Accounting Standards Board ("AcSB") issued a
bulletin relating to the transition to IFRS from Canadian GAAP and based on
work undertaken to date, no significant impediments to adopting IFRS by the
proposed transition date have been identified. True is monitoring industry
discussion regarding the replacement of the CICA's Accounting Guideline 16
with IFRS 6, which is expected to have major implications for True's current
full cost accounting policies. In February 2008, the AcSB confirmed the
transition date for adopting IFRS will be January 1, 2011.

    Business Risks and Uncertainties

    The reader is advised that True continues to be subject to various types
of business risks and uncertainties as described in the Management Discussion
and Analysis for the year ended December 31, 2007 or the Trust's Annual
Information Form. In addition, the Trust is also subject to the following
business risks and uncertainties:

    Environmental Regulations and Risks

    All phases of the oil and natural gas business present environmental
risks and hazards and are subject to environmental regulation pursuant to a
variety of federal, provincial and local laws and regulations. Compliance with
such legislation can require significant expenditures and a breach may result
in the imposition of fines and penalties, some of which may be material.
Environmental legislation is evolving in a manner expected to result in
stricter standards and enforcement, larger fines and liability and potentially
increased capital expenditures and operating costs. In 2002, the Government of
Canada ratified the Kyoto Protocol (the "Protocol"), which calls for Canada to
reduce its greenhouse gas emissions to specified levels. The Federal
government has introduced legislation aimed at reducing greenhouse gas
emissions using a "intensity based" approach, the specifics of which have yet
to be determined. Bill C-288, which is intended to ensure that Canada meets
its global climate change obligations under the Kyoto Protocol, was passed by
the House of Commons on February 14, 2007. There has been much public debate
with respect to Canada's ability to meet these targets and the Government's
strategy or alternative strategies with respect to climate change and the
control of greenhouse gases. Implementation of strategies for reducing
greenhouse gases whether to meet the limits required by the Protocol or as
otherwise determined could have a material impact on the nature of oil and
natural gas operations, including those of the Trust.
    In Alberta, the reduction emission guidelines outlined the Climate Change
and Emissions Management Amendment Act (the "Act") came into effect July 1,
2007. Alberta facilities emitting more than 100,000 tonnes of greenhouse gases
a year must reduce their emissions intensity by 12 per cent. Industries have
three options to choose from in order to meet the reduction requirements
outlined in the Act, and these are: (a) by making improvement to operations
that result in reductions; (b) by purchasing emission credits from other
sectors or facilities that have emissions below the 100,000 tonne threshold
and are voluntarily reducing their emissions; or (c) by contributing to the
Climate Change and Emissions Management Fund. Industries can either choose one
of these options or a combination thereof. On April 26, 2007, the Federal
Government released its Action Plan to Reduce Greenhouse Gases and Air
Pollution (the "Action Plan"), also known as ecoACTION which includes the
Regulatory Framework for Air Emissions. This Action Plan covers not-only large
industry, but regulates the fuel efficiency of vehicles and the strengthening
of energy standards for a number of energy-using products.
    In January 24, 2008, the Alberta Government announced a new climate
change action plan that will cut Alberta's projected 400 million tonnes of
emissions in half by 2050. This plan is based on three areas: (i) carbon
capture and storage, which will be mandatory for in situ oil sand facilities
that use heavy fuels for steam generation; (ii) energy conservation and
efficiency; and (iii) greening production through increased investment in
clean energy technology, including supporting research on new oil sands
extraction processes, as well as the funding of projects that reduce the cost
of separating CO(2) from other emissions supporting carbon capture and
storage.
    The Government of Canada and the Province of Alberta released on
January 31, 2008 the final report of the Canada-Alberta ecoENERGY Carbon
Capture and Storage Task Force, which recommends among others: (i)
incorporating carbon capture and storage into Canada's clean air regulations;
(ii) allocating new funding into projects through competitive process; and
targeting research to lower the cost of technology.
    On March 10, 2008, the Government of Canada released "Turning the Corner
- Taking Action to Fight Climate Change" (the "Updated Action Plan") which
provides some additional guidance with respect to the Government's plan to
reduce greenhouse gas emissions by 20% by 2020 and by 60% to 70% by 2050.
Details of the Updated Action Plan are provided in the Trust's Annual
Information Form for the year ended December 31, 2007.
    Given the evolving nature of the debate related to climate change and the
control of greenhouse gases and resulting requirements, it is not currently
possible to predict either the nature of those requirements or the impact on
the Trust and its operations and financial condition.

    Alberta Royalty and Tax Regime

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

    Critical Accounting Estimates

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

    Legal, Environmental Remediation and Other Contingent Matters

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

    Controls and Procedures

    Disclosure Controls and Procedures

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

    Internal Controls over Financial Reporting

    The Trust's Chief Executive Officer and Chief Financial Officer have
designed or caused to be designed under their supervision internal controls
over financial reporting to provide reasonable assurance regarding the
reliability of the Trust's financial reporting and the preparation of
financial statements for external purposes in accordance with the Canadian
GAAP.
    The Trust's Chief Executive Officer and Chief Financial Officer are
required to cause the Trust to disclose herein any change in the Trust's
internal control over financial reporting that occurred during the Trust's
most recent interim period that has materially affected, or is reasonably
likely to materially affect, the Trust's internal control over financial
reporting. No material changes in the Trust's internal control over financial
reporting were identified during the three months ended March 31, 2008, that
has materially affected, or are reasonably likely to materially affect, the
Trust's internal control over financial reporting.
    It should be noted that a control system, including the Trust's
disclosure and internal controls and procedures, no matter how well conceived,
can provide only reasonable, but not absolute, assurance that the objectives
of the control system will be met and it should not be expected that the
disclosure and internal controls and procedures will prevent all errors or
fraud.

    Standardized Distributable Cash

    The Canadian Securities Administrators recently revised and re-issued
National Policy 41-201 "Income Trusts and Other Indirect Offerings", which
includes disclosures regarding distributable cash for Income Trusts. Further,
the Canadian Institute of Chartered Accountants ("CICA") issued the
Interpretive Release "Standardized Distributable Cash in Income Trusts and
Other Flow-Through Entities: Guidance on Preparation and Disclosure" (the
"Release") in July 2007, which is required for the third quarter of 2007
forward. In the new guidance, sustainability concepts are discussed and
standardized distributable cash is defined as cash flow from operating
activities less adjustments for productive capacity maintenance, long-term
unfunded contractual obligations and the effect of any foreseeable financing
matters, related to debt covenants, which could impair True's ability to pay
distributions or maintain productive capacity. This Management Discussion and
Analysis is in all material respects in accordance with the recommendations
provided in CICA's Release and NP 41-201.-------------------------------------------------------------------------
    ($000s, except per unit amounts              Three months ended March 31,
     and percentages)                                     2008          2007
    -------------------------------------------------------------------------
    Net loss                                           (18,621)       (8,571)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Cash flow from operating activities                 17,843        39,959
    Productive capacity maintenance(1)                  (8,021)      (45,653)
    -------------------------------------------------------------------------
    Standardized distributable cash                      9,822        (5,694)
    Proceeds on sale of property, plant and equipment    5,788        18,443
    Corporate and property acquisition and other
     capital expenditures                                 (629)         (705)
    Bank borrowings (debt repayment) and working
     capital changes and other                          (5,474)        4,822
    -------------------------------------------------------------------------
    Cash Distributions declared                          9,507        16,866
    Accumulated distributions, beginning of period     215,167       141,716
    -------------------------------------------------------------------------
    Accumulated distributions, end of period           224,674       158,582
    -------------------------------------------------------------------------
    Standardized distributable cash  per unit
     - basic                                       $      0.12   $     (0.08)
    Standardized distributable cash  per unit
     - diluted                                     $      0.12   $     (0.08)
    -------------------------------------------------------------------------
    Standardized distributable cash payout ratio(2)       0.96           N/A
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Distributions declared per unit for
     outstanding units in the year                 $      0.12   $      0.24
    Accumulated distributions per unit,
     beginning of year                                    4.08          3.12
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Accumulated distributions per unit,
     end of year                                   $      4.20   $      3.36
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Excess (shortfall) of net income over cash
     distributions declared                            (28,123)      (25,437)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Excess of cash flow from operating activities
     over cash distributions declared                    8,336        23,093
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Please refer to the discussion of productive capacity maintenance
        below
    (2) Represents cash distributions declared divided by standardized
        distributable cashTrue strives to fund both distributions and maintenance capital primarily
from funds flow from operations. True's 2007 capital budget was initially set
at approximately 40% to 50% of annual funds flow. Property dispositions,
equity issues or additional borrowings may be required from time to time to
fund a portion of the distributions and/or capital expenditures to maintain or
increase productive capacity may be required based on forecast levels of cash
flow, capital efficiency and debt levels.
    Productive capacity is the amount of capital funds required in a period
for an enterprise to maintain its ability to generate future cash flow from
operating activities at a constant level. As commodity prices can be volatile
and short-term variations in production levels are often experienced in the
oil and gas industry, True defines production capacity as production on a
barrel of oil equivalent basis. A quantifiable measure for these short-term
variations is not objectively determinable or verifiable due to various
factors including the inability to distinguish natural production declines
from the effect of production additions resulting from capital and
optimization programs, and the effect of temporary production interruptions.
As a result, the adjustment for productive capacity maintenance in True's
calculation of standardized distributable cash is True's capital expenditures
excluding the cost of any asset acquisition, corporate asset acquisitions or
proceeds of any asset disposition. True believes that its capital programs
based on 40% to 50% of forecasted funds flow including its current view of
True's assets and opportunities and True's outlook for commodity prices and
industry conditions in the medium term, should be sufficient to maintain
True's productive capacity in the medium term. True sets its hurdle rates for
evaluating potential development and optimization projects according to these
parameters. Due to the risks inherent in the oil and natural gas industry,
particularly True's exploration and development activities and inherent
variations in commodity prices, there can be no assurance that capital
programs, whether limited to excess of cash flow over distributions or not,
will be sufficient to maintain or increase True's production levels or cash
flow from operating activities. True's capital expenditures and production can
be impacted by the timing of the capital program and spring break up
associated with certain operating areas of its properties. As True strives to
maintain sufficient credit facilities and appropriate levels of bank debt,
this seasonality is not expected to influence True's distribution policies.
    True's calculation of standardized distributable cash has no adjustment
for long-term unfunded contractual obligations. True's only long-term unfunded
contractual obligation at this time is for asset retirement obligations.
True's abandonment obligations are being funded on an annual basis with cash
flow from operating activities. Cash flow from operating actitivies, used in
our standardized distributable cash calculation, includes a deduction for
abandonment expenditures incurred in the year. True currently has no financing
restrictions on distributions arising from compliance with its debt covenants.
True regularly monitors its current forecast debt levels to ensure debt
covenants are not exceeded.
    Distributions typically exceed net income as a result of non-cash items
such as unit-based compensation, depletion, depreciation and accretion,
unrealized loss (gain) on commodity contracts, and future income tax expense
(recovery). These non-cash items generally result in a reduction to net
income, with no impact to cash flow from operating activities. Therefore,
distributions will exceed net income in most periods. In the event
distributions exceed cash flow from operating activities and the requirements
of True's capital program, the shortfall will typically be funded by a
combination of available bank facilities, equity or debt issues, or the sale
proceeds from non-core assets.
    The board of directors and management regularly review the level of
distributions. The board considers a number of factors, including expectations
of future current commodity prices, hedge positions, production volumes,
capital expenditure requirements, market conditions, the availability of debt
and equity capital and other factors. As a result of the volatility in
commodity prices, changes in production levels and capital expenditure
requirements, there can be no certainty that True will be able to maintain
current levels of distributions and distributions can and may fluctuate in the
future.-------------------------------------------------------------------------
    ($000s, except ratios)                                 To March 31, 2008
    -------------------------------------------------------------------------
    Cumulative distributable cash from operations(1)                  34,120
    Proceeds on sale of property, plant and equipment                 62,110
    Corporate and property acquisitions and other capital
     expenditures                                                    (20,512)
    Net proceeds from issue of trust units                            54,375
    Proceeds from issue of convertible debentures, net of
     issue costs                                                      82,261
    Repurchase of trust units under normal course issuer bid          (1,658)
    Funding from DRIP                                                 42,909
    Bank borrowings (debt repayment) and working capital changes
     and other                                                       (28,931)
    -------------------------------------------------------------------------
    Cumulative cash distributions declared(1)                        224,674
    -------------------------------------------------------------------------
    Standardized distributable cash payout ratio(2)                     6.58
    -------------------------------------------------------------------------
    (1) Subsequent to the November 2, 2005 reverse takeover of
        TKE Energy Trust
    (2) Represents cumulative distributions declared divided by cumulative
        standardized distributable cashSensitivity Analysis

    The table below shows sensitivities to funds flow as a result of product
price and operational changes. This is based on actual prices received for the
first quarter of 2008 and average production volumes of 13,552 boe/d during
that period, as well as the same level of debt outstanding at March 31, 2008.
Diluted weighted average trust units is based upon the first quarter of 2008.
These sensitivities are approximations only, and not necessarily valid under
other significantly different production levels or product mixes. Hedging
activities can significantly affect these sensitivities. Changes in any of
these parameters will affect cash flow as shown in the table below:-------------------------------------------------------------------------
                                                                       Funds
                                                                   Flow from
                                               Funds Flow from    Operations
                                                    Operations   Per Diluted
                                                   (annualized)         Unit
    -------------------------------------------------------------------------
    Sensitivity Analysis                                ($000s)           ($)
    -------------------------------------------------------------------------
    Change of US $1/bbl WTI                              1,400          0.02
    Change of $0.10/ mcf                                 1,400          0.02
    Change of US $0.01 Cdn/ US exchange rate             1,000          0.01
    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

    -------------------------------------------------------------------------
    2008 - Quarter ended (unaudited)
    ($000s, except per unit amounts)  March 31
    -------------------------------------------------------------------------
    Revenues before royalties and
     hedging                            70,033
    Funds flow from operations(1)       24,233
    Funds flow from operations per
     unit(1)
      Basic                              $0.31
      Diluted                            $0.30
    Net income (loss)                  (18,621)
    Net income (loss) per unit
      Basic                             $(0.24)
      Diluted                           $(0.24)
    Net capital expenditures (cash)      2,862
    Distributions declared               9,507
    Distributions per unit               $0.12
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

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

    -------------------------------------------------------------------------
    2006 - Quarter ended (unaudited)
    ($000s, except per unit amounts)  March 31   June 30  Sept. 30   Dec. 31
    -------------------------------------------------------------------------
    Revenues before royalties and
     hedging                            46,396    43,004    54,263    77,250
    Funds flow from operations(1)       18,995    16,386    23,225    31,785
    Funds flow from operations per
     unit(1)
      Basic                              $0.52     $0.44     $0.52     $0.45
      Diluted                            $0.52     $0.42     $0.50     $0.44
    Net income (loss)                    3,259    12,243     1,652  (250,718)
    Net income (loss) per unit
      Basic                              $0.09     $0.43     $0.04    $(3.58)
      Diluted                            $0.09     $0.42     $0.04    $(3.58)
    Net capital expenditures (cash)     22,561    (7,080)   46,095    29,922
    Distributions declared              26,150    27,771    36,846    33,588
    Distributions per unit               $0.72     $0.72     $0.72     $0.48
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) refer to "Non-GAAP Measures" in respect of the term "funds flow from
        operations" and "funds flow from operations per unit".



    TRUE ENERGY TRUST
    CONSOLIDATED BALANCE SHEETS

    As at March 31 and December 31 (unaudited)
    -------------------------------------------------------------------------

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

    ASSETS
    Current assets
      Accounts receivable                          $    57,701   $    48,522
      Deposits and prepaid expenses                      6,477         6,096
      Capital taxes recoverable                            621           626
      Commodity contract asset (note 15)                     -         1,061
      Future income taxes (note 12)                      8,428         3,116
                                                   --------------------------
                                                        73,227        59,421
    Property, plant and equipment (note 4)             788,342       820,831
                                                   --------------------------
    Total assets                                   $   861,569   $   880,252
                                                   --------------------------
                                                   --------------------------


    LIABILITIES
    Current liabilities
      Accounts payable and accrued liabilities     $    50,261   $    52,188
      Distribution payable to unitholders                3,169         6,337
      Commodity contract liability (note 15)            28,030        11,404
                                                   --------------------------
                                                        81,460        69,929
    Long-term debt (note 5)                            171,850       168,475
    Convertible debentures (note 6)                     79,837        79,407
    Asset retirement obligations (note 7)               28,521        28,373
    Future income taxes (note 12)                       60,990        67,366
                                                   --------------------------
    Total liabilities                                  422,658       413,550
                                                   --------------------------

    NON-CONTROLLING INTEREST
      Exchangeable shares of subsidiary (note 8)         3,679         3,922

    UNITHOLDERS' EQUITY
      Unitholders' capital (note 9)                    925,735       925,573
      Equity component of convertible debentures
       (note 6)                                          5,119         5,119
      Contributed surplus (note 10)                     19,872        19,454
      Deficit                                         (515,494)     (487,366)
                                                   --------------------------
    Total unitholders' equity                          435,232       462,780
                                                   --------------------------
    Total liabilities and unitholders' equity      $   861,569   $   880,252
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    SUBSEQUENT EVENT (note 16)

    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)                                               2008          2007
    -------------------------------------------------------------------------

    REVENUES
      Petroleum and natural gas sales              $    70,033   $    71,196
      Royalties                                        (15,500)      (14,894)
      Gain (loss) on commodity contracts (note 15)     (21,829)          679
                                                   --------------------------
                                                        32,704        56,981

    EXPENSES
      Production                                        16,996        14,972
      Transportation                                       843           689
      General and administrative                         3,770         4,904
      Interest and financing charges                     4,516         4,547
      Unit-based compensation (notes 9 and 10)             269         1,112
      Depletion, depreciation and accretion             36,303        47,458
      Special meeting costs (note 13)                        -         3,805
                                                   --------------------------
                                                        62,697        77,487

    LOSS BEFORE TAXES                                  (29,993)      (20,506)

    TAXES (note 12)
      Capital taxes                                        463           932
      Future income tax recovery                       (11,754)      (12,829)
                                                   --------------------------
                                                       (11,291)      (11,897)

    NET LOSS BEFORE NON-CONTROLLING INTEREST           (18,702)       (8,609)
      Non-controlling interest (note 8)                    (81)          (38)
                                                   --------------------------
                                                   --------------------------

    NET LOSS                                           (18,621)       (8,571)
                                                   --------------------------

    Net changes in cash flow hedges (net of tax of
     $1.8 million for the 2007 period)                       -        (3,156)
                                                   --------------------------

    COMPREHENSIVE LOSS                             $   (18,621)  $   (11,727)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Net loss per trust unit
      Basic and diluted                            $     (0.24)  $     (0.12)

    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)                                               2008          2007
    -------------------------------------------------------------------------
    UNITHOLDERS' CAPITAL
      Balance, beginning of period                 $   925,573   $   876,904
      Exchangeable shares converted                        162            16
                                                   --------------------------
      Balance, end of period                           925,735       876,920
                                                   --------------------------


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

    CONTRIBUTED SURPLUS
      Balance, beginning of period                      19,454        12,818
      Unit-based compensation expense (note 10)            603         1,182
      Reversal of prior year unit-based compensation
       expense for forfeitures of unvested incentive
       units                                              (185)            -
                                                   --------------------------
      Balance, end of period                            19,872        14,000
                                                   --------------------------

    DEFICIT
      Balance, beginning of period                    (487,366)     (389,745)
      Net loss                                         (18,621)       (8,571)
      Impact of changes in accounting policy for
       financial instruments on January 1, 2007
       (net of tax of $0.05 million)                         -            97
      Distributions declared                            (9,507)      (16,866)
                                                   --------------------------
      Balance, end of period                          (515,494)     (415,085)
                                                   --------------------------

    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)(1)                                   -         3,749
      Reclassification to earnings of net hedging
       gains on commodity contracts (net of tax of
       $1.6 million)                                         -        (3,156)
                                                   --------------------------
      Balance, end of year                                   -           593
                                                   --------------------------

    -------------------------------------------------------------------------
    TOTAL UNITHOLDERS' EQUITY                      $   435,232   $   481,547
    -------------------------------------------------------------------------

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

    See accompanying selected notes to the consolidated financial statements.


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

    ($000s)                                               2008          2007
    -------------------------------------------------------------------------
    Cash provided by (used in):
    CASH FLOW FROM OPERATING ACTIVITIES
    Net loss                                       $   (18,621)  $    (8,571)
    Items not involving cash:
      Non-controlling interest (note 8)                    (81)          (38)
      Depletion, depreciation and accretion             36,303        47,458
      Unit-based compensation (notes 9 and 10)             269         1,112
      Unrealized loss on commodity contracts
       (note 15)                                        17,687         2,465
      Accretion on convertible debentures (note 6)         430           391
      Future income taxes (recovery) (note 12)         (11,754)      (12,829)
                                                   --------------------------
                                                        24,233        29,988
      Asset retirement costs incurred                     (589)         (188)
      Change in non-cash working capital (note 11)      (5,801)       10,159
                                                   --------------------------
                                                        17,843        39,959
    CASH FLOW FROM (USED IN) FINANCING ACTIVITIES
      Increase in bank debt                              3,375        21,495
      Obligations under capital lease                        -           (82)
      Distributions declared                            (9,507)      (16,866)
                                                   --------------------------
                                                        (6,132)        4,547
      Change in non-cash working capital (note 11)      (3,160)       (8,376)
                                                   --------------------------
                                                        (9,292)       (3,829)
    CASH FLOW FROM (USED IN) INVESTING ACTIVITIES
      Additions to property, plant and equipment        (8,650)      (46,358)
      Proceeds on sale of property, plant and equipment  5,788        18,443
                                                   --------------------------
                                                        (2,862)      (27,915)
      Change in non-cash working capital (note 11)      (5,689)       (8,215)
                                                   --------------------------
                                                        (8,551)      (36,130)

      Change in cash                                         -             -

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

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

    See accompanying selected notes to the consolidated financial statements.



    SELECTED NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

    March 31, 2008 and 2007 (unaudited)
    ------------------------------------------------------------------------

    1.  STRUCTURE OF THE TRUST

        True Energy Trust ("True" or the "Trust") is an open-ended,
        unincorporated investment trust governed by the laws of the Province
        of Alberta. Pursuant to a Plan of Arrangement (the "TKE Arrangement")
        that became effective on November 2, 2005, True Energy Inc. and TKE
        Energy Trust ("TKE") entered into a business combination whereby
        True Energy Inc. acquired TKE in a reverse takeover, thus creating
        True Energy Trust and a publicly listed exploration focused company,
        Vero Energy Inc.

        The purpose of the Trust is to indirectly explore for, develop and
        hold interests in petroleum and natural gas properties, through
        investments in securities of subsidiaries and net profits interests
        in oil and natural gas properties. The business of the Trust is
        carried on by True Energy Inc. and its indirect wholly owned
        subsidiary True Energy Peru S.A.C. The Trust owns, directly and
        indirectly, 100% of the common shares, (excluding the exchangeable
        shares - see note 8) of True Energy Inc. and True Energy Peru S.A.C.
        The activities of True Energy Inc. are financed through interest
        bearing notes from the Trust and third party debt as described in the
        notes to the financial statements.

    2.  SIGNIFICANT ACCOUNTING POLICIES

        The interim consolidated financial statements of the Trust have been
        prepared by management in accordance with generally accepted
        accounting policies in Canada. The unaudited interim consolidated
        financial statements have been prepared following the same accounting
        policies and methods of computation as the consolidated financial
        statement for the fiscal year ended December 31, 2007, except as
        described in note 3. The interim consolidated financial statement
        note disclosures do not include all of those required by Canadian
        generally accepted accounting principles ("GAAP") applicable for
        annual financial statements. Accordingly, the interim consolidated
        financial statements should be read in conjunction with the
        consolidated financial statements and the notes thereto contain in
        the Trust's financial report for the year ended December 31, 2007.

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

    3.  CHANGES IN ACCOUNTING POLICIES

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

        a. Capital disclosures

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

        b. Financial instruments

           Two new accounting standards were issued by the CICA, Section 3862
           "Financial Instruments - Disclosures", and Section 3863 "Financial
           Instruments - Presentation. These sections replace Section 3861
           "Financial Instruments - Disclosure and Presentation" and are
           effective for the Trust beginning January 1, 2008. The objective
           of Section 3862 is to provide users with information to evaluate
           the significance of the financial instruments on the entity's
           financial position and performance, the nature and extent of risks
           arising from financial instruments, and how the entity manages
           those risks. The provisions of Section 3863 deal with the
           classification of financial instruments, related interest,
           dividends, losses and gains, and the circumstances in which
           financial assets and financial liabilities are offset. The
           additional disclosures required under these sections are included
           in note 15.

    4.  PROPERTY, PLANT AND EQUIPMENT

        ($000s)
        ---------------------------------------------------------------------
                                                   Accumulated
                                                 depletion and      Net book
        March 31, 2008                      Cost  depreciation         value
        ---------------------------------------------------------------------
        Petroleum and natural gas
         properties                  $ 1,374,582   $   588,528   $   786,054
        Office furniture and equipment     3,839         1,551         2,288
        ---------------------------------------------------------------------
                                     $ 1,378,421   $   590,079   $   788,342
        ---------------------------------------------------------------------

        December 31, 2007
        ---------------------------------------------------------------------
        Petroleum and natural gas
         properties                  $ 1,371,069   $   552,899   $   818,170
        Office furniture and equipment     4,092         1,431         2,661
        ---------------------------------------------------------------------
                                     $ 1,375,161   $   554,330   $   820,831
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The Trust has included $54.2 million for future development costs and
        excluded, $35.2 million for undeveloped land and $45.9 million for
        estimated salvage from the depletion calculation during the three
        month period ended March 31, 2008.

        For the three month period ended March 31, 2008, the Trust
        capitalized $0.5 million of general and administrative expenses and
        $0.2 million, including the future tax effect thereon of
        $0.07 million, of unit-based compensation expense directly related to
        exploration and development activities.

    5.  LONG-TERM DEBT

        As at March 31, 2008, the Trust has a $15 million demand operating
        facility provided by one Canadian bank and $175 million extendible
        revolving term credit facility syndicated by two Canadian chartered
        banks, a U.S. bank, a Canadian financial institution and one
        institutional lender. Amounts borrowed under the credit facility bear
        interest at a floating rate based on the applicable Canadian prime
        rate, U.S. base rates, LIBOR rates, plus between 0% and 1.95%,
        depending on the types of borrowings and the Trust's debt to cash
        flow ratio. Security is provided by a $400 million debenture
        containing a first ranking security interest on all of the Trust's
        assets. The credit facility is secured against all the assets of True
        Energy Inc., the Trust and all material subsidiaries. True has
        provided a negative pledge and undertaking to provide fixed charges
        over major petroleum and natural gas reserves in certain
        circumstances. A standby fee is charged on between 0.125% and 0.400%
        on the undrawn portion of the facility, depending on the Trust's debt
        to cash flow ratio.

        As at March 31, 2008, there was $7.9 million outstanding under the
        operating facility and $164 million outstanding under the revolving
        term credit facility. As at March 31, 2008, there is approximately
        $18.1 million not drawn under the existing facility.

        On March 31, 2008, True's borrowing base redetermination was re-
        scheduled for renewal on or before June 2, 2008, while the
        Saskatchewan asset divestiture was being finalized. To reflect the
        recent dispositions in True's borrowing base, True's borrowing base
        was reduced from $190 million as at March 31, 2008 to $164.5 million
        effective as at April 30, 2008. As at April 30, 2008, there is
        approximately $40 million not drawn on these facilities. Further
        borrowing base reductions are scheduled to occur on June 2, 2008 and
        June 30, 2008, which will bring True's borrowing base to $152 million
        as at June 30, 2008.

        The revolving period on the new revolving term credit facility ends
        on June 28, 2008, unless extended for a further 364 day period.
        Should the facilities not be renewed they convert to 366 day non-
        revolving term facilities on the renewal date. Payment will not be
        required under the revolving term facility for more than 365 days
        from the balance sheet date and as at March 31, 2008 there is
        sufficient availability under the revolving term credit facility to
        also cover the operating facility and, as such, the entire credit
        facility has been classified as long-term.

    6.  CONVERTIBLE DEBENTURES

        The following table shows the convertible debenture activities for
        the three month period ended March 31, 2008 and the year ended
        December 31, 2007:

        Convertible debentures
        ---------------------------------------------------------------------
                                       Number of          Debt        Equity
                                      Debentures     Component     Component
                                                        ($000s)       ($000s)
        Balance, December 31, 2006        86,250   $    81,551   $     5,119
        Impact of change in accounting
         policy for financial
         instruments on January 1, 2007        -        (3,697)            -
        Accretion                              -         1,553             -
        ---------------------------------------------------------------------
        Balance, December 31, 2007        86,250   $    79,407   $     5,119
        ---------------------------------------------------------------------
        Accretion                              -           430             -
        ---------------------------------------------------------------------
        Balance, March 31, 2008           86,250   $    79,837   $     5,119
        ---------------------------------------------------------------------

    7.  ASSET RETIREMENT OBLIGATIONS

        The Trust's asset retirement obligations result from net ownership
        interests in petroleum and natural gas assets including well sites,
        gathering systems and processing facilities. The Trust estimates the
        total undiscounted amount of cash flows required to settle its asset
        retirement obligations is approximately $73.6 million which will be
        incurred between 2008 and 2053. A credit-adjusted risk-free rate of 8
        percent and an inflation rate of 2 percent were used to calculate the
        fair value of the asset retirement obligation.

        ---------------------------------------------------------------------
                                                      March 31,  December 31,
        ($000s)                                           2008          2007
        ---------------------------------------------------------------------
        Asset retirement obligation, beginning of
         period                                    $    28,373   $    26,605
        Liabilities incurred on development
         activities                                         44           433
        Changes in prior period estimates                  581           960
        Liabilities released on dispositions              (442)         (927)
        Liabilities settled during the year               (589)         (835)
        Accretion expense                                  554         2,137
        ---------------------------------------------------------------------
        Asset retirement obligation, end of period $    28,521   $    28,373
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    8.  EXCHANGEABLE SHARES OF SUBSIDIARY/NON-CONTROLLING INTEREST

        ---------------------------------------------------------------------
                                March 31, 2008            December 31, 2007
                            Number        Amount        Number        Amount
                                          ($000s)                     ($000s)
        ---------------------------------------------------------------------
        Balance,
         beginning of
         period            390,276   $     3,922       403,536   $     4,153
        Non-controlling
         interest expense
         (recovery)              -           (81)            -           (95)
        Exchanged for
         trust units       (16,177)         (162)      (13,260)         (136)
        ---------------------------------------------------------------------
        Balance, end of
         period            374,099   $     3,679       390,276   $     3,922
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The exchange ratio is calculated monthly based on the five day
        weighted average trust unit trading price preceding the monthly
        effective date and at March 31, 2008 was 0.90177. The exchangeable
        shares are not eligible for cash distributions; however cash
        distributions will increase the exchange ratio.


    9.  UNITHOLDERS' CAPITAL

        a. Trust Units

           ------------------------------------------------------------------
                                March 31, 2008            December 31, 2007
                            Number        Amount        Number        Amount
                                          ($000s)                     ($000s)
           ------------------------------------------------------------------
           Balance,
            beginning of
            period      79,216,046   $   925,573    70,275,703   $   876,904
           Issued for
            cash (net of
            issue costs
            of $3.1 million)     -             -     9,430,000        54,375
           Repurchased
            under normal
            course issuer
            bid                  -             -      (500,000)       (5,842)
           Exchangeable
            shares
            converted       14,414           162        10,343           136
           ------------------------------------------------------------------
           Balance, end
            of period   79,230,460   $   925,735    79,216,046   $   925,573
           ------------------------------------------------------------------

        b. Trust Unit Incentive Plan

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

           The grant price per Incentive Right ("Grant Price") shall be equal
           to the per Trust Unit closing price on the trading day immediately
           preceding the date of grant, unless otherwise permitted. Under the
           terms of the Incentive Plan, the exercise price of each Incentive
           Right is initially equal to the Grant Price and thereafter is
           reduced pursuant to a formula. This formula provides that the
           exercise price of each Incentive Right is reduced by any decreases
           in the daily closing price on the Toronto Stock Exchange of the
           Trust Units 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.

           Incentive rights, entitling the holder to purchase units from the
           Trust, have been granted to directors, officers, employees and
           service providers of the Trust. One third of the initial grant of
           trust unit incentive rights normally vest on each of the first,
           second, and third anniversary from the date of grant.

           The following tables summarize information regarding trust unit
           incentive rights for the three month period ended March 31, 2008

           Unit Rights Continuity
           ------------------------------------------------------------------
                                              Weighted Average
                                              Exercise Price(a)       Number
           ------------------------------------------------------------------
           Balance, December 31, 2007              $      9.18     5,931,997
           Granted                                 $      3.02        45,000
           Forfeited                               $     12.03      (744,332)
           ------------------------------------------------------------------
           Balance, March 31, 2008                 $      8.54     5,232,665
           ------------------------------------------------------------------

           (a) Exercise prices reflect grant prices less reduction in
               exercise prices.


    Unit Rights Outstanding, March 31, 2008
    -------------------------------------------------------------------------
                                 Outstanding                 Exercisable
                                        Weighted
                                         Average
                                        Exercise  Weighted
    Exercise                               Price   Average           Exercise
    Price         Exercise                Net of Remaining              Price
    Before           Price         At      Price   Contr-       At     Net of
    Price           Net of    Mar. 31,     Redu-   actual  Mar. 31,     Price
    Reductions  Reductions       2008     ctions     Life     2008 Reductions
    -------------------------------------------------------------------------
    $  2.92     $  2.83     2,681,500   $   4.37    4.4          -       N/A
     - $  6.70   - $  5.29

    $10.58      $  9.07       744,165   $   9.41    3.5    249,984  $   9.41
     - $12.53    - $10.92

    $13.74      $11.55        465,500    $ 11.87    3.3    151,831   $ 11.87
     - $14.83    - $12.72

    $15.15      $13.17         52,500    $ 13.70    3.0     35,001   $ 13.70
     - $16.70    - $14.08

    $18.25      $15.07      1,289,000    $ 15.32    2.6  1,289,000   $ 15.32
     - $20.80    - $18.02

    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    $  2.92     $  2.83     5,232,665   $   8.54    3.7  1,725,816   $ 14.12
     - $20.80    - $18.02
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

        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, 2008, the Trust matched $0.1 million under the plan.

    10. CONTRIBUTED SURPLUS

        ---------------------------------------------------------------------
                                                      March 31,  December 31,
        ($000s)                                           2008          2007
        ---------------------------------------------------------------------
        Balance, beginning of period               $    19,454   $    12,818
        Unit-based compensation expense                    603         4,249
        Reversal of prior year unit-based
         compensation expense for forfeitures of
          unvested incentive units                        (185)       (1,797)
        Adjustment for repurchase of units under NCIB        -         4,184
        ---------------------------------------------------------------------
        Balance, end of period                     $    19,872   $    19,454
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Unit-based Compensation Expense

        During the three months ended March 31, 2008, the Trust granted
        45,000 unit incentive rights to employees and directors. During the
        three months ended March 31, 2008, the Trust recorded unit-based
        compensation of $0.6 million, of which $0.1 million was capitalized
        to property, plant and equipment.

        The fair values of all incentive rights granted are estimated on the
        date of grant using the Black-Scholes option-pricing model. The
        weighted average fair market value of incentive rights granted during
        the three month period ended March 31, 2008 and the assumptions used
        in their determination are as noted below:

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

        ---------------------------------------------------------------------
        Assumptions:
          Risk free interest rate (%)                                      4
          Expected life (years)                                            5
          Expected volatility (%)                                         26
        ---------------------------------------------------------------------
        Results:
          Weighted average fair value of each incentive right
           granted                                               $      0.86
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    11. SUPPLEMENTAL CASH FLOW INFORMATION

        Cash Interest and Taxes Paid
        ---------------------------------------------------------------------
                                                 Three months ended March 31,
        ($000s)                                           2008          2007
        ---------------------------------------------------------------------

        Cash paid:
          Interest                                 $     3,813   $     2,560
          Taxes (net of refunds)                   $       285   $     2,493

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

        Change in Non-cash Working Capital
        ---------------------------------------------------------------------
                                                 Three months ended March 31,
        ($000s)                                           2008          2007
        ---------------------------------------------------------------------
        Changes in non-cash working capital items:
          Accounts receivable                      $    (9,179)  $    10,691
          Deposits and prepaid expenses                   (381)        2,783
          Accounts payable and accrued liabilities      (1,927)       (9,918)
          Capital taxes recoverable                          5        (1,555)
          Distribution payable to unitholders           (3,168)       (8,433)
        ---------------------------------------------------------------------
                                                   $   (14,650)  $    (6,432)
        ---------------------------------------------------------------------

          Changes related to operating activities  $    (5,801)  $    10,159
          Changes related to financing activities       (3,160)       (8,376)
          Changes related to investing activities       (5,689)       (8,215)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
                                                   $   (14,650)  $    (6,432)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    12. INCOME TAXES

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

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

        In accordance with generally accepted accounting principles, prior to
        the enactment, the Trust's temporary differences were not recorded as
        future income taxes. As at March 31, 2008, the total "temporary
        difference" (tax basis exceeds accounting basis) in the Trust is
        $8.6 million. As at March 31, 2008, the Trust's subsidiaries have a
        tax basis of approximately $502 million that is available to shelter
        future taxable income. Included in this tax basis are estimated non-
        capital loss carry forwards of approximately $34.8 million that
        expire in years through 2027. In addition, the Trust itself has
        approximately $919 million of tax basis.

    13. SPECIAL MEETING COSTS

        On January 15, 2007, the Trust announced its proposal to convert into
        an intermediate exploration and production company (the
        "Reorganization"). Pursuant to the Reorganization, it was
        contemplated that holders of trust units of the Trust would receive
        an equal number of common shares of a newly formed corporation that
        will hold the assets previously held directly or indirectly by the
        Trust. The exchangeable shares were also to be exchanged for common
        shares based on the conversion ratio thereof. The Reorganization was
        subject to all required regulatory approvals and securityholder
        approval by at least 66 2/3% of the votes cast by unitholders of the
        Trust and holders of the exchangeable shares. At the Special and
        Annual Meeting held on March 30, 2007, the special resolution related
        to the Reorganization was not approved. As a result, the
        Reorganization was not completed. The Trust incurred $3.8 million in
        costs for legal, financial advisory, accounting, unitholder
        solicitation services, printing, mailing and other expenses that are
        included as special meeting costs within the statement of income for
        the three months ended March 31, 2007.

    14. PER TRUST UNIT AMOUNTS

        ---------------------------------------------------------------------
                                                 Three months ended March 31,
                                                          2008          2007
        ---------------------------------------------------------------------
        Basic trust units outstanding               79,230,460    70,276,890
        Dilutive effect of:
          Trust unit incentive rights outstanding    5,232,665     5,227,333
          Units issuable for exchangeable shares       337,351       303,547
          Units issuable for convertible debentures  5,390,625     5,390,625
        ---------------------------------------------------------------------
        Diluted trust units outstanding             90,191,101    81,198,395
        ---------------------------------------------------------------------
        Weighted average trust units outstanding    79,223,088    70,275,770
        Dilutive effect of exchangeable shares,
         trust unit incentive plan and
         convertible debentures(1)                           -             -
        ---------------------------------------------------------------------
        Diluted weighted average trust units
         outstanding                                79,223,088    70,275,770
        ---------------------------------------------------------------------

        (1) A total of 337,351 (2007: 303,547) exchangeable shares, 5,232,665
            (2007: 5,227,333) trust incentive units and 5,390,625 (2007:
            5,390,625) trust units issuable pursuant to the conversion of
            convertible debentures were excluded from the calculation for the
            three month period ended March 31, 2008 as they were not
            dilutive.

    15. FINANCIAL RISK MANAGEMENT

        a. Overview

        The Trust has exposure to the following risks from its use of
        financial instruments:

        -  Credit risk
        -  Liquidity risk
        -  Market risk

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

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

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

        b. Credit risk

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

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

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

        As at March 31, 2008, accounts receivable was comprised of the
        following:

        ---------------------------------------------------------------------
        ($000s)
        ---------------------------------------------------------------------
        Trade accounts receivable                                     18,657
        Accrued and other accounts receivable                         39,044
        ---------------------------------------------------------------------
                                                                      57,701
        ---------------------------------------------------------------------

        The carrying amount of accounts receivable represents the maximum
        credit exposure. The Trust has an allowance for doubtful accounts as
        at March 31, 2008 of $0.5 million.  As at March 31, 2008 the Trust
        estimates its trade accounts receivables to be aged as follows:

        ---------------------------------------------------------------------
        Aging ($000s)
        ---------------------------------------------------------------------
        Not past due (less than 90 days)                               9,653
        Past due 0-30 days                                               496
        Past due 31-120 days                                           2,330
        Past due more than 120 days                                    6,178
        ---------------------------------------------------------------------
        Total                                                         18,657
        ---------------------------------------------------------------------

        After considering offsetting March 31, 2008 trade accounts payable
        from the same companies and cash receipts received subsequent to
        March 31, 2008, the Trust's trade receivables aged more than 90 days
        of approximately $9.0 million are reduced to a net balance of
        approximately $2.8 million.

        c. Liquidity risk

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

        The Trust prepares annual capital expenditure budgets and confirms
        unitholder distributions on a monthly basis. Capital expenditure
        budgets and levels of monthly unitholder distributions are regularly
        monitored and updated as considered necessary. Further, the Trust
        utilizes authorizations for expenditures on both operated and non-
        operated projects to further manage capital expenditures. To
        facilitate the capital expenditure program, the Trust has a revolving
        reserve based credit facility, as outlined in note 5, which is at
        least reviewed annually by the lender. The Trust also attempts to
        match its payment cycle with collection of petroleum and natural gas
        revenues on the 25th of each month.

        The following are the contractual maturities of financial liabilities
        and associated interest payments as at March 31, 2008:

        ---------------------------------------------------------------------
        Financial       (less than)
        liability ($000s)   1 Year     1-2 Years     2-5 Years    Thereafter
        ---------------------------------------------------------------------
        Accounts payable
         and accrued
         liabilities        50,261             -             -             -
        Distribution
         payables            3,169             -             -             -
        Derivative
         contracts          28,030             -             -             -
        Bank debt -
         principal               -       171,850             -             -
        Convertible
         debentures
          - principal            -             -        86,250             -
        ---------------------------------------------------------------------
        Total               81,460       171,850        86,250             -
        ---------------------------------------------------------------------

        d. Market risk

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

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

        The Trust formal risk management policy permits management to use
        specified price risk management strategies for up to 50% of crude
        oil, natural gas and NGL production including fixed price contracts,
        costless collars and the purchase of floor price options and other
        derivative financial instruments to reduce the impact of price
        volatility and ensure minimum prices for a maximum of eighteen months
        beyond the current date. The program is designed to provide price
        protection on a portion of the Trust's future production in the event
        of adverse commodity price movement, while retaining significant
        exposure to upside price movements. By doing this, the Trust seeks to
        provide a measure of stability to cash distributions, as well as, to
        ensure True realizes positive economic returns from its capital
        developments and acquisition activities.

        Foreign currency exchange rate risk

        Foreign currency exchange rate risk is the risk that the fair value
        or future cash flows will fluctuate as a result of changes in foreign
        exchange rates. Although substantially all of the company's petroleum
        and natural gas sales are denominated in Canadian dollars, the
        underlying market prices in Canada for petroleum and natural gas are
        impacted by changes in the exchange rate between the Canadian and
        United States dollar. As at March 31, 2008, if the Canadian/US dollar
        exchange rate had decreased by US$0.01 with all other variables held
        constant, after tax net earnings for the period would have been
        approximately $0.7 million lower. An equal an opposite impact would
        have occurred to net earnings had the Canadian/US dollar exchange
        rate increased by US$0.01.

        The Trust had no forward exchange rate contracts in place as at or
        during the year ended March 31, 2008.

        Commodity price risk

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

        As at December 31, 2007, the Trust had entered into commodity price
        risk management arrangements as follows:

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

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

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

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

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

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

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

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

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

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

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

        For the three months ended March 31, 2008, the gain (loss) on
        commodity contracts was comprised of the following:

        ---------------------------------------------------------------------
                                                          2008          2007
        ($000s)                                           Total         Total
        ---------------------------------------------------------------------
        Gain (loss) on commodity contracts
          Realized(1)                              $    (4,142)  $     3,144
          Unrealized(2)                                (17,687)       (2,465)
        ---------------------------------------------------------------------
                                                   $   (21,829)  $       679
        ---------------------------------------------------------------------

        (1) Realized gains and losses on commodity contracts represent actual
            cash settlements and other amounts paid under these contracts.
        (2) Unrealized gains and losses on commodity contracts represent non-
            cash adjustments for changes in the fair value of these contracts
            during the period.

        As at March 31, 2008, if oil and natural gas liquids prices had been
        US$1 per barrel and natural gas prices $0.10 per mcf lower, with all
        other variables held constant, after tax net earnings for the period
        would have been $2.0 million lower. An equal an opposite impact would
        have occurred to net earnings had oil and natural gas liquids prices
        been US$1 per barrel and natural gas $0.10 per mcf higher.

        Interest rate risk

        Interest rate risk is the risk that future cash flows will fluctuate
        as a result of changes in market interest rates. The Trust is exposed
        to interest rate fluctuations on its bank debt which bears a floating
        rate of interest. As at March 31, 2008, if interest rates had been 1%
        lower with all other variables held constant, after tax net earnings
        for the period would have been $1.2 million higher, due to lower
        interest expense. An equal an opposite impact would have occurred to
        net earnings had interest rates been 1% higher.

        The Trust had no interest rate swap or financial contracts in place
        as at or during the year ended March 31, 2008.

        e. Capital management

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

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

        As at March 31, 2008, the Trust's ratio of net debt to annualized
        cash flow was 2.5 times, which the Trust projects will decrease
        during the remainder of 2008 as net debt levels are reduced from
        disposal proceeds from its asset divestitures completed in April 2008
        and True takes a balanced approach to the priority use of cash flows
        between levels of distributions and its 2008 capital program. The
        Trust's unitholders' capital is not subject to external restrictions,
        however the bank debt facility is based on petroleum and natural gas
        reserves (see note 5).

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

        f. Fair value of financial instruments

        The Trust's financial instruments as at March 31, 2008 include
        accounts receivable, commodity contract liability, accounts payable
        and accrued liabilities, distributions payable, long-term debt and
        convertible debentures. The fair value of accounts receivable,
        accounts payable and accrued liabilities and distributions payable
        approximate their carrying amounts due to their short-terms to
        maturity.

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

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

        The fair value of the convertible debentures of $82.4 million is
        based on exchange traded values.

    16. SUBSEQUENT EVENT

        On December 17, 2007, True announced its intention to divest of its
        Saskatchewan assets and reduce the distribution level as part of a
        new strategic direction for the Trust. Proceeds from the proposed
        divestiture would be utilized to reduce True's bank indebtedness and
        the reduced distribution level ensured additional financial
        resources.

        The additional cash flow generated though improved pricing has eased
        debt concerns and allowed the Trust to modify the path of the new
        strategic direction. On April 30, 2008 True announced that the sale
        of the Dodsland-Stranraer asset, one of five asset packages
        comprising the Saskatchewan divestiture program, had been
        successfully completed for net proceeds after adjustments of
        $39.3 million. True further announced its decision to not pursue
        further Saskatchewan asset disposition options at this time.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
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