True Energy Trust announces year end 2007 financial results



    TSX: TUI.UN

    CALGARY, March 6 /CNW/ - (TSX: TUI.UN) True Energy Trust ("True" or the
"Trust") announces its financial and operating results for the year ended
December 31, 2007. Highlights from the fourth quarter and year ended
December 31, 2007 include:

    
    -   In the fourth quarter of 2007, monthly distributions of $0.08 per
        unit were declared and paid on November 15, 2007, December 17, 2007
        and January 15, 2008 resulting in annual cash distributions paid of
        $0.96 per unit. The Board has announced it has set a distribution
        policy for the first quarter of 2008 at a monthly rate of $0.04 per
        unit, subject to monthly confirmation, based on current commodity
        prices, hedging program, production volumes and market conditions.
        True anticipates that this reduction will allow the Trust's
        distributions to be sustainable in the current gas price, foreign
        exchange rate and cost environment.

    -   True generated average sales volumes for the year of 16,139 boe/d as
        compared to 13,861 boe/d in 2006, representing a 16% increase.
        Average sales volumes for the fourth quarter of 2007 were
        14,937 boe/d as compared to 19,747 boe/d for the same period in 2006,
        representing a 24% decrease. This decrease in average sales volumes
        from fourth quarter 2006 to 2007 was due to natural production
        declines, decreased production due to property dispositions during
        2007, the delay of tie-in and completion of certain third party first
        quarter drilled wells until late in 2007, and the impact of slowly
        increasing production for the capital intensive Kerrobert SAGD
        expansion project, which will continue to advance into 2008. Sales
        volumes in the fourth quarter were up 6% from the third quarter 2007
        volumes. The increase in sales volumes from the third to fourth
        quarter of 2007 takes into account the resumption of certain
        production following plant turnarounds and other operational
        challenges in the third quarter.

    -   Funds flow from operations (*) for 2007 was $101.2 million on gross
        sales of $258.5 million compared to funds flow from operations of
        $90.4 million on gross sales of $220.9 million for 2006. The increase
        in funds flow for the 2007 year was primarily the result of higher
        sales volumes, offset by marginally lower overall commodity prices
        and operating netbacks for 2007. Funds flow from operations for the
        fourth quarter was $19.5 million on gross sales of $61.8 million
        compared to funds flow from operations of $31.8 million on gross
        sales of $77.2 million for the same period in 2006. This is primarily
        reflective of reduced sales volumes in fourth quarter 2007 compared
        to the same period in 2006, offset by an overall increase in
        commodity prices between those periods.

    -   The net loss for 2007 was $24.3 million compared to a net loss of
        $233.6 million for 2006. The net loss for the 2007 fourth quarter was
        $0.4 million compared to a net loss of $250.7 million in the same
        period in 2006. The 2006 year included fourth quarter non-cash
        charges for the ceiling test write-down of property, plant and
        equipment of $110.0 million and goodwill impairment of
        $169.8 million.

    -   During 2007, True achieved a 98% success rate in drilling or
        participation in 40 (27.3 net) working interest wells, resulting in
        20 (10.4 net) gas wells, 17 (14.4 net) oil wells, 2 (2.0 net)
        stratagraphic test wells and 1 (0.5 net) dry hole.

    -   On December 17, 2007 the Trust announced its intention to divest of
        its Saskatchewan assets as part of a new strategic direction. Bids
        were received on March 4, 2008 and are presently being evaluated by
        the Trust with the assistance of its financial advisor, Scotia
        Waterous Inc.

    -   After giving recognition to property sales, True replaced
        approximately 99% of its production with 2007 year end working
        interest gross proved plus probable reserves of 45.4 mmboe.

    -   The Trust recorded all-in annual Finding, Development and Acquisition
        ("FD&A") cost of $21.60 per barrel of oil equivalent ("boe") in 2007
        before consideration of future development capital ("FDC") for proved
        plus probable reserves category. This is a 12 percent reduction from
        the $24.60 per boe FD&A cost realized in 2006. Including FDC, the
        FD&A cost was $21.10 per boe. The three year average FD&A cost is
        $26.30 per boe for the proved plus probable category before FDC;
        including FDC, the three year average FD&A cost is $28.60 per boe.
        For additional information please refer to the reserves news release
        dated March 6, 2008 (posted on www.sedar.com).

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

    True's 2007 financial report is presented below.


                                 HIGHLIGHTS
    -------------------------------------------------------------------------
                                                     Years ended December 31
                                                           2007         2006
    -------------------------------------------------------------------------
    FINANCIAL
    (CDN $000s except unit and per unit amounts)
    Revenue (before royalties and hedging(1))           258,490      220,913
    Funds flow from operations(2)                       101,172       90,391
      Per basic trust unit                                $1.33        $1.91
      Per diluted trust unit                              $1.33        $1.87
    Net loss                                            (24,267)    (233,564)
      Per basic trust unit                               $(0.32)      $(4.95)
      Per diluted trust unit                             $(0.32)      $(4.95)
    Distributions paid                                   73,451      124,355
      Per unit                                            $0.96        $2.64
    -------------------------------------------------------------------------
    Exploration and development                          87,397       98,690
    Corporate and property acquisitions                   1,505       17,322
    -------------------------------------------------------------------------
    Capital expenditures - cash                          88,902      116,012
    Property dispositions - cash                        (31,808)     (24,514)
    Corporate acquisitions and other - non-cash             270      487,698
    -------------------------------------------------------------------------
    Total capital expenditures - net                     57,364      579,196
    -------------------------------------------------------------------------
    Long-term debt                                      168,475      157,904
    Convertible debentures(3)                            79,407       81,551
    Working capital deficiency(3)                         3,281       36,361
    -------------------------------------------------------------------------
    Total net debt(3)                                   251,163      275,816
    -------------------------------------------------------------------------
    Total assets                                        880,252    1,016,658
    Unitholders' equity                                 462,780      505,096
    -------------------------------------------------------------------------
    OPERATING
    Daily sales volumes
      Crude oil and NGLs                      (bbls/d)    5,330        5,317
      Natural gas                              (mcf/d)   64,853       51,264
      Total oil equivalent                     (boe/d)   16,139       13,861
    Average prices
      Crude oil and NGLs                       ($/bbl)    48.71        48.00
      Crude oil and NGLs
       (including hedging(1))                  ($/bbl)    41.88        47.54
      Natural gas                              ($/mcf)     6.73         6.75
      Natural gas (including hedging(1))       ($/mcf)     7.13         6.93
      Total oil equivalent                     ($/boe)    43.13        43.36
       Total oil equivalent
        (including hedging(1))                 ($/boe)    42.47        43.88
    Statistics
      Operating netback(4)                     ($/boe)    22.21        22.60
      Operating netback
       (including hedging(1))(4)               ($/boe)    21.55        23.12
      Production expenses                      ($/boe)    11.59         9.23
      General & administrative                 ($/boe)     3.09         2.94
      Royalties as a % of sales
       after transportation                                 19%          24%

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



    -------------------------------------------------------------------------
                                                     Years ended December 31
                                                           2007         2006
    -------------------------------------------------------------------------
    TRUST UNITS
    Trust units outstanding                          79,216,046   70,275,703
    Trust unit incentive rights outstanding           5,931,997    5,429,831
    Units issuable for exchangeable shares              335,793      286,942
    Units issuable for convertible debentures         5,390,625    5,390,625
    -------------------------------------------------------------------------
    Diluted trust units outstanding                  90,874,461   81,383,101
    Diluted weighted average trust units(5)          75,792,488   47,217,258

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

    TRUST UNIT TRADING STATISTICS

    (CDN$, except volumes) based on intra-day trading
    High                                                   7.47        21.30
    Low                                                    2.76         7.25
    Close                                                  3.35         7.49
    Average daily volume                                492,004      412,447
    -------------------------------------------------------------------------

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

    (2) The highlights section contains the term "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 transportation,
        royalties and operating costs from revenues.

    (5) In computing weighted average diluted earnings per trust unit for the
        year ended December 31, 2007 a total of 335,793 (2006: 286,942)
        exchangeable shares, 5,931,997 (2006: 5,429,831) trust incentive
        units and 5,390,625 (2006: 5,390,625) trust units issuable pursuant
        to conversion of convertible debentures were excluded from the
        calculation of diluted earnings per trust unit for the year ended
        December 31, 2007 and 2006 as they were not dilutive. To calculate
        weighted average diluted funds flow from operations for the year
        ended December 31, 2007, 335,793 exchangeable shares were added to
        the denominator, resulting in diluted weighted average trust units of
        76,128,281 under this calculation. To calculate weighted average
        diluted funds flow from operations for the year ended December 31,
        2006, a total of $4.0 million for interest accretion expense was
        added to the numerator and 286,942 exchangeable shares and 2,953,757
        trust units were added to the denominator for units issuable on
        conversion of convertible debentures, resulting in diluted weighted
        average trust units of 50,457,967 and funds flow from operations per
        diluted trust unit of $1.87 under this calculation.



                            REPORT TO UNITHOLDERS
    

    Natural gas prices continue to be highly volatile, largely due to
uncertainty regarding weather and its effect on natural gas demand and storage
and global factors including LNG shipments to North America. True continues to
be cautious in its outlook with respect to near term natural gas prices and is
actively managing its forward gas price exposure to mitigate risks.
    Accomplishments for the fourth quarter and year ended December 31, 2007
include:

    Distributions

    In the fourth quarter of 2007, monthly distributions of $0.08 per unit
were declared and paid on November 15, 2007, December 17, 2007 and January 15,
2008 resulting in annual cash distributions paid of $0.96 per unit.
    On December 17, 2007, the Trust announced that the Board has set the
distribution policy for the first 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 that this reduction
will allow the Trust's distributions to be sustainable in the current gas
price, foreign exchange rate and cost environment.

    Production

    For the 2007 year, sales volumes averaged 16,139 boe/d as compared to
13,861 boe/d for the same period in 2006. This reflects the full integration
of additional production from the closing of the acquisitions of Shellbridge
Oil & Gas, Inc. on June 23, 2006 and Prairie Schooner Petroleum Ltd. on
September 22, 2006, in addition to the impact from drilling and operational
activity in 2007.
    2007 fourth quarter sales volumes averaged 14,937 boe/d as compared to
19,747 boe/d for the same period in 2006, representing a 24% decrease. This
decrease in average sales volumes from fourth quarter 2006 to 2007 was due to
natural production declines, decreased production due to property dispositions
during 2007, the delay of tie-in and completion of certain third party first
quarter drilled wells until late in 2007, and the impact of slowly increasing
production for the capital intensive Kerrobert SAGD expansion project, which
will continue to advance into 2008. Sales volumes in the fourth quarter were
up 6% from the third quarter 2007 volumes. The increase in sales volumes from
the third to fourth quarter takes into account the resumption of certain
production following plant turnarounds and other operational challenges in the
third quarter. However, production for fourth quarter 2007 was lower than
anticipated due to somewhat slower than anticipated SAGD response at
Kerrobert.
    Field production estimates for the first quarter of 2008 are expected to
average approximately 13,200 boe/d. Field production was adversely impacted by
the extreme weather experienced in January and February of 2008. In addition,
an unplanned third party plant outage impacted production in west central
Alberta for February 2008. Work is underway to deal with a well servicing and
equipment repair backlog.

    Drilling

    During the 2007 year, True achieved a 98% success rate in drilling or
participation in 40 (27.3 net) working interest wells, resulting in 20
(10.4 net) gas wells, 17 (14.4 net) oil wells, 2 (2.0 net) stratagraphic test
wells and 1 (0.5 net) dry hole.
    Only 6 (3.3 net) wells were drilled subsequent to the first quarter 2007
including 3 (1.0 net) third party operated wells in the fourth quarter of
2007. The Trust currently plans to drill 2 (2.0 net) operated exploration
wells late in the first quarter of 2008.

    Kerrobert

    Advancement of the Kerrobert SAGD project continues. During the first
quarter of 2008, True has increased steam rates to the 4 new steam injectors
to near maximum levels. Wellhead injection pressures have uniformly increased
indicating a re-pressurization of the reservoir. Further evidence of re-
pressurization has been seen through the consistent increase of wellbore fluid
levels and downhole pump inlet pressures. Production well temperatures have
remained at near initial reservoir levels indicating even heating is underway
and that no random, premature, breakthrough has occurred - a positive
indicator of overall project conformance. Based on the recovery responses of
the original 1996 pilot project, estimated oil rate increases on the current
project should occur 4 to 6 months after start-up. As we approach the midpoint
of the 4 to 6 month timing range it is clear there will not be an "early"
response, however all technical parameters continue to point to a very
positive project.

    Financial

    Funds flow from operations for the 2007 year was $101.2 million on gross
sales of $258.5 million compared to funds flow from operations of
$90.4 million on gross sales of $220.9 million for 2006. The increase in funds
flow for the 2007 year was primarily the result of higher sales volumes,
offset by marginally lower overall commodity prices and operating netbacks for
2007.
    Funds flow from operations for the fourth quarter was $19.5 million on
gross sales of $61.8 million compared to funds flow from operations of
$31.8 million on gross sales of $77.2 million for the same period in 2006.
This is primarily reflective of reduced sales volumes in fourth quarter 2007
compared to the same period in 2006, offset by an overall increase in
commodity prices between those periods.
    The net loss for the 2007 year was $24.3 million compared to a net loss
of $233.6 million for 2006. The net loss for the 2007 fourth quarter was
$0.4 million compared to a net loss of $250.7 million in the same period in
2006. The 2006 year included fourth quarter non-cash charges for the ceiling
test write-down of property, plant and equipment of $110.0 million and
goodwill impairment of $169.8 million.

    Dispositions

    During 2007, True identified certain small non-core property disposition
opportunities, which were in keeping with its principles of core areas for
future development and operating high working interest production. For the
2007 year, True closed on various property dispositions for total net proceeds
after adjustments of $31.8 million. The proceeds from all property
dispositions were used to pay down bank debt. In the fourth quarter of 2007,
True closed on a minor Alberta property disposition for total net proceeds of
$0.5 million.

    Liquidity

    True's net debt, excluding unrealized commodity contract assets and
liabilities, future income taxes and ARO, as at December 31, 2007 was
$251.2 million, representing $168.5 million outstanding on the credit
facility, $79.4 million in convertible debentures (liability component) and
the balance a working capital deficiency.
    On May 31, 2007, the Trust completed its offering, including an
over-allotment option, for an aggregate of 9,430,000 trust units for gross
proceeds of $57.5 million. The net proceeds of $54.4 million, after deducting
unit issue costs, was used to pay down debt.
    The existing credit facility consists of a $15 million demand operating
facility provided by one Canadian bank and a $175 million extendible revolving
term credit facility syndicated by two Canadian chartered banks, a U.S. bank,
a Canadian financial institution and one institutional lender. As at
December 31, 2007, there is approximately $22 million not drawn under these
lending facilities.
    True does not hold any non-bank Asset-Backed Commercial Paper
investments.
    The revolving period on the term credit facility ends on June 30, 2008,
unless extended for a further 364 day period. The borrowing base was renewed
effective August 31, 2007 and is currently scheduled for renewal on March 31,
2008.
    In August 2007, True received Toronto Stock Exchange approval for its
normal course issuer bid ("NCIB") for the repurchase of its trust units from
August 28, 2007 to August 27, 2008, entitling the Trust to purchase up to
approximately 7.8 million of its outstanding trust units. 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.
    True has continued its active commodity price risk management program.
Further to our press release dated February 19, 2008, True has recently
entered into seven additional fixed natural gas management contracts. With the
addition of these contracts, approximately 33% of current natural gas
production is hedged through the first quarter of 2008. Assuming the
previously announced sale of the Trust's Saskatchewan assets is completed at
the end of Q1 2008, approximately 53% of estimated natural gas production is
hedged through the balance of 2008 and approximately 23% is hedged through the
first half of 2009. The Trust will continue its hedging strategies focusing on
maintaining sufficient cash flow to fund True's unitholder distributions and
the capital program.

    International Opportunity

    The formal signing of the License Contract (the "Agreement") for the
exploration and exploitation of hydrocarbons in Block 126, Peru (the "Block")
occurred on October 23, 2007 in Lima, Peru. The ceremony included the Minister
of Energy and Mines of Peru, senior members of Petroperu and roughly 150
invited guests. A wholly owned subsidiary of True is the operator of the
project in a partnership with Veraz Petroleum Ltd. (the "Partnership"). Veraz
Petroleum Ltd. ("Veraz") is a junior international oil and gas exploration
company based in western Canada and listed on the Canadian Trading and
Quotation System Inc. (CNQ).
    The Agreement provides the exclusive right to the Partnership to explore
for and develop hydrocarbons on the 2.5 million acre Block located in Ucayali
province, east central Peru and entitles True to a 10% working interest and
Veraz to a 90% working interest subject to standard royalties payable to the
Government of Peru. The Partnership intends to begin exploration and
development activities as soon as possible. To date, previous partnership
groups have drilled only three wells on the Block. The focus of any
preliminary work will be on the previous exploration work completed on the
Block in the 1980's, which confirmed the presence of hydrocarbons.
    Pursuant to the Agreement, the Partnership has been issued a seven year,
four phase exploration permit to be followed by an exploitation phase in the
event of a commercial discovery. Each phase has commitments that the
Partnership must meet before the next phase can be undertaken. At the end of
each phase the operator elects whether or not the Partnership continues into
the subsequent phase. In the first phase, the Partnership will reprocess
approximately 1,000 km of existing 2D seismic data. Much of this data, which
was primarily acquired in the mid to late 1980's, has not been re-evaluated
using contemporary processing techniques.
    The first exploration phase of the Agreement is for one year commencing
December 21, 2007 and requires a minimum work period commitment by the
Partnership of US$200,000 (True's 10% share is US$20,000). If the Partnership
continues into the second phase, a further US$2.5 million minimum commitment
by the Partnership (True's 10% share is US$250,000) would be required. If the
Partnership continues with the third and fourth phases of the Agreement an
additional US$1.25 million minimum commitment would be required by the
Partnership for each additional phase. Should the Partnership proceed through
all four exploration phases the minimum work commitment by the Partnership
would total US$5.2 million (True's 10% share is US$520,000).

    Regulatory Changes

    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 currently available
public information, 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. 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
new Alberta royalty regime, 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 New Alberta Royalty Framework will impact future
drilling decisions in order for the Trust to maintain acceptable rates of
return on its capital deployed. The Alberta Government has stated that they
are reviewing with industry the proposed royalty changes to ensure that there
are no unintended consequences resulting from the royalty changes. It is not
known at this time whether any further revisions to the proposals will be made
nor what their impact may be.
    On October 30, 2007, the Finance Minister announced, as part of the 2007
Economic Statement, changes to the tax system including reduction of the
corporate income tax rate from 22.1 per cent to 15 per cent by 2012. The
reductions will be phased in between 2008 and 2012. Legislation enacting the
measures announced in the Economic Statement received Royal Assent on
December 14, 2007. The reduction in the general corporate tax rate will also
apply to the taxation of income trusts, reducing the combined federal and
deemed provincial tax rate for distributions to 28 per cent in 2012.

    Finding, Development and Acquisition Costs

    After giving recognition to property sales, True replaced approximately
99% of its production with 2007 year end working interest gross proved plus
probable reserves of 45.4 mmboe.
    The Trust recorded all-in annual Finding, Development and Acquisition
("FD&A") cost of $21.60 per barrel of oil equivalent ("boe") in 2007 before
consideration of future development capital ("FDC") for proved plus probable
reserves category. This is a 12 percent reduction from the $24.60 per boe FD&A
cost realized in 2006. Including FDC, the FD&A cost was $21.10 per boe. The
three year average FD&A cost is $26.30 per boe for the proved plus probable
category before FDC; including FDC, the three year average FD&A cost is
$28.60 per boe. For additional information please refer to the reserves news
release dated March 6, 2008 (posted on www.sedar.com).

    Announcement of Saskatchewan Assets Divestiture Program

    On December 17, 2007, True announced its intention to divest of its
Saskatchewan assets as part of a new strategic direction for the Trust.
Further to this announcement, True intends to divest its oil and natural gas
assets in Saskatchewan including Kerrobert's SAGD project, and properties at
Smiley, Coleville, Dodsland and Mantario. December 2007 average production
from the Saskatchewan assets was approximately 5,600 boe/d, weighted 62% to
oil (97% heavy oil, 3% light oil). The assets include 18.8 mmboe of reserves
and approximately 250,000 net acres of land. True anticipates significant
proceeds from the disposition of its Saskatchewan properties in a time of
historically high oil prices and the current favorable royalty regime in
Saskatchewan. Any proceeds from the proposed divestiture will be utilized to
eliminate True's bank indebtedness and to provide additional financial
resources to develop its Alberta light oil and natural gas plays. Scotia
Waterous Inc. ("Scotia Waterous") has been selected to act as True's exclusive
advisor in this process. Bids were received on March 4, 2008 and are presently
being evaluated by the Trust with the assistance of Scotia Waterous. Assuming
True's acceptance of satisfactory bid(s), the asset divestiture is currently
anticipated to close at the end of the first quarter of 2008.

    2008 True Capex Budget

    Gas prices continue to show volatility with uncertainty regarding weather
and its effect on natural gas demand and storage and global factors including
LNG shipments to North America. Given the natural gas price outlook, coming
into the winter drilling season, True plans to reduce its first quarter 2008
winter drilling activity compared to the first quarter of 2007. True's first
quarter 2008 capital program will not exceed $10 million which compares to a
front end loaded 2007 capital program of approximately $50 million in first
quarter 2007. True will continue to take a balanced approach to the priority
use of cash flow between level of distributions and size of its 2008 capital
program. After completion of the proposed asset divestiture, True's 2008
capital expenditure program would be increased from the currently planned
$40 million to approximately $60 million. Given the nature of True's lands and
their inherent advantage of year round access, True will spread its 2008
capital program more evenly through the full year of 2008 to take advantage of
reduced service costs during non-peak times. True will focus on increasing its
farm-out activity in non-core areas. If the 2008 outlook for commodity prices
improves, True would plan to increase its capital spending in third and fourth
quarters of 2008.
    A conference call to discuss True's annual financial and reserves results
will be held on March 6, 2008 at 2:00 PM MST/4:00 PM EST. To participate,
please call toll-free 1-800-587-1893 or 416-644-3428. The conference call will
also be recorded and available by calling 1-877-289-8525 or 416-640-1917 and
entering passcode 21264766 followed by the pound sign.
    True's annual 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
    March 6, 2008



    
                    MANAGEMENT'S DISCUSSION AND ANALYSIS
    

    March 6, 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 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
March 6, 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, impact of, and timing of certain projects, timing of and
effects of drilling, tie-in and completion of wells, the effect of government
announcements, proposals and legislation, plans regarding hedging, wells to be
drilled, expected or anticipated production rates, timing of expected
production increases, the weighting of production between different
commodities, expected commodity prices, exchange rates, production expenses,
transportation costs and other costs and expenses, planned disposition of
Saskatchewan assets and use of proceeds and timing thereof, 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. The reader is cautioned not to place undue reliance on this forward
looking information. As a consequence, actual results may differ materially
from those anticipated in the forward-looking statements. Readers are
cautioned that the foregoing list of factors is not exhaustive. Additional
information on these and other factors that could effect True's operations and
financial results are included in reports on file with Canadian securities
regulatory authorities and may be accessed through the SEDAR website
(www.sedar.com), at True's website (www.trueenergytrust.com). Furthermore, the
forward-looking statements contained herein are made as at the date hereof and
True does not undertake any obligation to update publicly or to revise any of
the included forward-looking statements, whether as a result of new
information, future events or otherwise, except as may be required by
applicable securities laws.
    The reader is further cautioned that the preparation of financial
statements in accordance with GAAP requires management to make certain
judgments and estimates that affect the reported amounts of assets,
liabilities, revenues and expenses. Estimating reserves is also critical to
several accounting estimates and requires judgments and decisions based upon
available geological, geophysical, engineering and economic data. These
estimates may change, having either a negative or positive effect on net
earnings as further information becomes available, and as the economic
environment changes.

    Fourth Quarter 2007

    Funds flow from operations during the fourth quarter of 2007 was
$19.5 million, a decrease of 39% compared to $31.8 million for the fourth
quarter of 2006. This is primarily reflective of reduced sales volumes in
fourth quarter 2007 compared to the same period in 2006, offset partially by
an overall increase in commodity prices between those periods. By comparison,
in the last quarter of 2007, True had a net loss of $0.4 million compared to a
net loss of $250.7 million in the fourth quarter of 2006. During the fourth
quarter of 2007, a $9.3 million future income tax recovery was recorded to
reflect the tax rate changes which were enacted by the Government of Canada
during the period. The net loss during the fourth quarter of 2006 included
non- cash charges of a ceiling test write down of $110 million and a goodwill
impairment charge of $169.8 million.
    Sales volumes for the three months ended December 31, 2007 averaged
14,937 boe/d, down 24% from the 19,747 boe/d produced in the fourth quarter of
2006. Production during the last quarter of 2006 included the additional
volumes derived from the Shellbridge Oil & Gas, Inc. ("Shellbridge") and
Prairie Schooner Petroleum Ltd. ("Prairie Schooner") acquisitions as well as
drilling activity during 2006. Fourth quarter 2007 sales volumes were lower
than the same period in 2006 due to natural production declines, decreased
production due to property dispositions during 2007, the delay of tie-in and
completion of certain third party first quarter drilled wells until late in
2007, and the impact of slowly increasing production for the Kerrobert SAGD
expansion project, which will continue to advance into 2008. The SAGD response
on the Kerrobert project was slower than estimated, however, advancement of
the project continues. Four (1.0 net) third party operated wells from first
quarter 2007 drilling in the Ferrier area were completed and tied in during
the fourth quarter of 2007. Current production from these wells total
approximately 85 boe/d net.
    In the fourth quarter of 2007, average sales volumes increased 6% from
the third quarter 2007 average volumes of 14,096 boe/d as a result of the
resumption of certain production following plant turnarounds and other
challenges experienced in the third quarter of 2007. Fourth quarter 2007
volumes were also lower than anticipated due to non-operated well and facility
downtime, certain shut-in production for facility modifications, and the
impact of cold weather on operations late in the fourth quarter. Natural gas
sales averaged 57.4 Mmcf/d during the last quarter of 2007, compared to
64.9 Mmcf/d in the fourth quarter of 2006. The weighting toward natural gas
averaged 64% in the fourth quarter, compared to 62% in the corresponding
period of 2006. In the last quarter of 2007, True's natural gas exploration
efforts focused on drilling 3 (1.0 net) non-operated natural gas wells in the
Ferrier, Alberta area. Crude oil, condensate and NGL sales volumes averaged
5,370 bbls/d in the fourth quarter compared to 7,440 bbls/d during the same
period of 2006. During the fourth quarter of 2007, True invested $15.5 million
on capital projects, excluding corporate and asset acquisitions and
dispositions, compared to $25.5 million in 2006.
    During the fourth quarter of 2007, True experienced an overall increase
in commodity prices, based on increases in crude oil, condensate and NGL
pricing, as compared to the same period in 2006. The average Alberta Spot
price for natural gas during this quarter was 11% lower than in the same
period in 2006. For the three months ending December 31, 2007, True received
an average natural gas price, before transportation and hedging, of $6.40/Mcf,
8% less than $6.98/Mcf in the same period in 2006 and 18% higher than
$5.44/Mcf in the third quarter of 2007. For heavy crude oil, True received an
average price before transportation of $39.72/bbl during the fourth quarter of
2007, 14% more than $34.82/bbl in the same period in 2006 and 6% less than
$42.30/bbl in the third quarter of 2007. In comparison, the average reference
price for Hardisty Heavy crude in the fourth quarter of 2007 was 22% more than
the average 2006 price in the same period. For light oil, condensate and NGLs,
True received an average price of $78.42/bbl before hedging during the last
quarter of 2007, 30% more than the average price of $60.34/bbl received in the
same period of 2006, compared to a 34% increase in the Edmonton par reference
price. The average price for light oil, condensate and NGLs for True was 3%
lower than the $76.37/bbl for the third quarter of 2007. During the fourth
quarter of 2007, pre-transportation revenue of $60.4 million was 21% less than
the corresponding 2006 period.
    In the fourth quarter of 2007, the Trust paid $12.6 million in royalties,
compared to $18.5 million in the same period in 2006. As a percentage of pre-
hedge sales (after transportation costs), royalties were 22% in the fourth
quarter of 2007 compared to 25% in the same period in 2006. In this same
period of 2007, operating costs totaled $16.5 million, compared to
$17.7 million recorded in the same period of 2006. During the fourth quarter
of 2007, operating costs averaged $12.01/boe, up from the $9.76/boe incurred
during the fourth quarter of 2006, primarily reflecting the fixed component of
operating costs combined with the reduced sales volumes between comparable
periods. In comparison, operating costs for the third quarter of 2007 averaged
$13.13/boe. True is forecasting operating costs of approximately $11.75/boe in
2008. During the fourth quarter of 2007, company field operating netbacks
decreased by 3% to $20.51/boe compared to 2006, driven primarily by increased
operating costs, offset partially by increased overall commodity prices and
decreased royalties. In comparison, the company field operating netback for
the third quarter of 2007 was $15.76/boe. Field operating netbacks for natural
gas before hedging during the fourth quarter of 2007 of $2.78/Mcf were 27%
less than the 2006 netbacks, reflecting a significantly lower gas price,
increases in transportation and operating expenses, offset partially by a
reduction in royalties. In comparison, the field operating netback for natural
gas for the third quarter of 2007 was $2.05/Mcf. Field operating netbacks
before hedging for crude oil and NGLs during the fourth quarter of 2007
averaged $27.34/bbl, up from $18.34/bbl during the fourth quarter of 2006,
primarily as a result of a significant increase in the overall commodity price
received, partially offset by higher operating costs and royalties. In
comparison, the field operating netback for crude oil and NGLs for the third
quarter of 2007 was $24.71/bbl.
    In the fourth quarter of 2007, the net cost of general and administrative
expenses was $4.7 million, compared to $5.9 million in the comparable 2006
period reflecting a reduction of the number of salaried personnel on staff and
other efforts to reduce costs.
    Depletion, depreciation and accretion expense for the fourth quarter of
2007 was $39.8 million, compared to $53.1 million in 2006, which reflects
reduced carrying costs in 2007, combined with lower production volumes in
fourth quarter 2007 versus 2006.

    Net Income (Loss) and Funds Flow from Operations

    True generated funds flow from operations of $101.2 million ($1.33 per
diluted unit) for the year ended December 31, 2007, up 12% from the
$90.4 million ($1.87 per diluted unit) for the 2006 year. The increase in
funds flow from operations for the 2007 year was primarily the result of
higher sales volumes, offset by marginally lower overall commodity prices and
operating netbacks for 2007.
    The net loss for the 2007 year was $24.3 million compared to a net loss
of $233.6 million in 2006. The 2006 year included fourth quarter non-cash
charges for the ceiling test write-down of property, plant and equipment of
$110.0 million and goodwill impairment of $169.8 million.

    
    Funds Flow From Operations and Net Income
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($000s, except per unit amounts)                       2007         2006
    -------------------------------------------------------------------------
    Funds flow from operations                          101,172       90,391
      Basic ($/unit)                                       1.33         1.91
      Diluted ($/unit)                                     1.33         1.87

    Net income (loss)                                   (24,267)    (233,564)
      Basic ($/unit)                                      (0.32)       (4.95)
      Diluted ($/unit)                                    (0.32)       (4.95)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    Reconciliation of Funds Flow from Operations and Cash Flow from Operating
    Activities
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($000s, except per unit amounts)                       2007         2006
    -------------------------------------------------------------------------
    Funds flow from operations                          101,172       90,391
    Asset retirement costs incurred                        (835)        (516)
    Change in non-cash working capital                  (18,131)      36,925
    -------------------------------------------------------------------------
    Cash flow from operating activities                  82,206      126,800
    -------------------------------------------------------------------------

    Sales Volumes

    Sales volumes for the year ended December 31, 2007 averaged 16,139 boe/d
as compared to 13,861 boe/d for the 2006 year, representing a 16% increase.
    This reflects the timing of additional production from the closing of the
acquisitions of Shellbridge on June 23, 2006 and Prairie Schooner on
September 22, 2006, in addition to the impact from drilling and operational
activity in 2007.

    Sales Volumes
    -------------------------------------------------------------------------
                                                     Years ended December 31,
                                                           2007         2006
    -------------------------------------------------------------------------
    Natural gas                                (mcf/d)   64,853       51,264
    -------------------------------------------------------------------------
    Heavy oil                                 (bbls/d)    3,450        3,612
    Light oil and condensate                  (bbls/d)    1,289        1,285
    NGLs                                      (bbls/d)      591          420
    -------------------------------------------------------------------------
    Total crude oil and NGLs                  (bbls/d)    5,330        5,317
    -------------------------------------------------------------------------
    Total boe/d                                  (6:1)   16,139       13,861
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Field production estimates for the first quarter of 2008 are expected to
average approximately 13,200 boe/d. Field production was adversely impacted by
the extreme weather experienced in January and February of 2008. In addition,
an unplanned third party plant outage impacted production in west central
Alberta for February 2008. Work is underway to deal with a well servicing and
equipment repair backlog.
    During the 2007 year, True achieved a 98% success rate in drilling or
participation in 40 (27.3 net) working interest wells, resulting in 20
(10.4 net) gas wells, 17 (14.4 net) oil wells, 2 (2.0 net) stratagraphic test
oil wells and 1 (0.5 net) dry hole.
    Only 6 (3.3 net) wells were drilled subsequent to the first quarter 2007
including 3 (1.0 net) third party operated wells in the fourth quarter of
2007. The Trust currently plans to drill 2 (2.0 net) operated exploration
wells late in the first quarter of 2008.
    Advancement of the Kerrobert SAGD project continues. During the first
quarter of 2008, True has increased steam rates to the 4 new steam injectors
to near maximum levels. Wellhead injection pressures have uniformly increased
indicating a re-pressurization of the reservoir. Further evidence of re-
pressurization has been seen through the consistent increase of wellbore fluid
levels and downhole pump inlet pressures. Production well temperatures have
remained at near initial reservoir levels indicating even heating is underway
and that no random, premature, breakthrough has occurred - a positive
indicator of overall project conformance. Based on the recovery responses of
the original 1996 pilot project, estimated oil rate increases on the current
project should occur 4 to 6 months after start-up. As we approach the midpoint
of the 4 to 6 month timing range it is clear there will not be an "early"
response, however all technical parameters continue to point to a very
positive project.
    For the year ended December 31, 2007, the weighting towards natural gas
sales averaged 67% compared to 62% in the same period in 2006. Heavy oil sales
made up 21% of total production for the 2007 year compared to 26% in 2006. The
September 2006 acquisition of Prairie Schooner added significant natural gas
volumes which has increased the natural gas production weighting since that
date.
    Sales of natural gas averaged 64.9 mmcf/d for 2007, compared to
51.3 mmcf/d in 2006, an increase of 27%. Crude oil and NGL sales for 2007
averaged 5,330 bbls/d, compared to 2006 average sales of 5,317 bbls/d.

    
    Commodity Prices

    Average Commodity Prices
    -------------------------------------------------------------------------
                                        Years ended December 31,
                                              2007         2006     % change
    -------------------------------------------------------------------------
    Exchange rate (US$/Cdn$)                0.9390       0.8817            7

    Natural gas:
    NYMEX (US$/mmbtu)                         7.14         6.99            2
    Alberta spot ($/mcf)                      6.43         6.50           (1)
    True's average price ($/mcf)              6.73         6.75            -
    True's average price
     (including hedging)($/mcf)               7.13         6.93            3

    Crude oil:
    WTI (US$/bbl)                            74.25        66.23           12
    Edmonton par - light oil ($/bbl)         77.06        73.30            5
    Bow River - medium/heavy oil ($/bbl)     53.16        51.54            3
    Hardisty Heavy - heavy oil ($/bbl)       44.77        43.32            3
    True's average prices ($/bbl)
      Light crude oil, condensate and NGLs   64.60        62.46            3
      Light crude oil, condensate and NGLs
       (including hedging)                   45.22        61.03          (26)
      Heavy crude oil                        40.05        41.17           (3)
      Total crude oil and NGLs               48.71        48.00            1
      Total crude oil and NGLs
       (including hedging)                   41.88        47.54          (12)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    True's natural gas is primarily sold on the daily spot market. During
2007, the AECO Spot reference price decreased by 1% compared to 2006.
Similarly, True's average sales price before transportation and hedging for
2007 averaged $6.73/mcf for its natural gas, only 0.1% less than the $6.75/mcf
received in 2006.
    For heavy crude oil, True received an average price before transportation
of $40.05/bbl during 2007, a decrease of 3% over 2006 prices. The Bow River
reference price increased by 3% and the Hardisty Heavy reference price
increased by 3% 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. The primary reason for the relative decrease in True's
heavy oil price received for 2006 to 2007, compared to a small increase in the
Hardisty Heavy reference price is the timing of True's heavy oil sales
experienced in 2007 - a weighting of higher sales volumes in the first and
fourth quarters of 2007 where lower commodity prices were experienced.
    For light oil, condensate and NGLs, True recorded an average $64.60/bbl
before hedging during 2007, 3% higher than the average price received in 2006.
During this same period, the Edmonton par price increased by 5%. The average
WTI crude oil US dollar based price increased 12% from 2006 to 2007. Despite a
more robust global crude oil environment in 2007, much of the positive impact
in WTI crude oil pricing was offset by a strengthening Canadian dollar.

    Revenue

    Revenue before other income for the year ended December 31, 2007 was
$254.0 million, 16% greater than the $219.4 million in 2006. The higher
revenue for 2007 was the result of higher natural gas, crude oil, condensate
and NGL sales volumes, despite marginally lower overall commodity prices.

    
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($000s)                                                2007         2006
    -------------------------------------------------------------------------
    Light crude oil, condensate and NGLs                 44,325       38,876
    Heavy oil                                            50,436       54,278
    -------------------------------------------------------------------------
    Crude oil and NGLs                                   94,761       93,154
    Natural gas                                         159,278      126,216
    -------------------------------------------------------------------------
    Total revenue before other                          254,039      219,370
    Other(1)                                              4,451        1,543
    -------------------------------------------------------------------------
    Total revenue before royalties and hedging          258,490      220,913
    Gain (loss) on commodity contracts                   (3,852)       2,639
    -------------------------------------------------------------------------
    Total revenue before royalties                      254,638      223,552
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (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 March 6, 2008 is shown in the following tables (see Note 20
to the consolidated financial statements for a detailed disclosure of all
commodity contracts in place as at March 6, 2008):

    
    Crude oil and liquids     Average Volumes (bbls/d)
    -------------------------------------------------------------------------
                              Q1 2008  Q2-Q3 2008  Q4 2008  Q1 2009  Q2 2009
    -------------------------------------------------------------------------
    Costless collars            2,000       2,000    2,000        -        -
    -------------------------------------------------------------------------
    Total bbls/d                2,000       2,000    2,000        -        -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    Average Price (US$/bbl WTI)
    -------------------------------------------------------------------------
                              Q1 2008  Q2-Q3 2008  Q4 2008  Q1 2009  Q2 2009
    -------------------------------------------------------------------------
    Collar ceiling price        75.00       82.00    82.00        -        -
    Collar floor price          65.00       65.00    65.00        -        -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    Natural gas               Average Volumes (GJ/d)
    -------------------------------------------------------------------------
                              Q1 2008  Q2-Q3 2008  Q4 2008  Q1 2009  Q2 2009
    -------------------------------------------------------------------------
    Costless collars            5,000           -        -        -        -
    Fixed                      15,551      24,326   24,326   10,550   10,550
    -------------------------------------------------------------------------
    Total GJ/d                 20,551      24,326   24,326   10,550   10,550
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    Average Price ($/GJ AECO C)
    -------------------------------------------------------------------------
                              Q1 2008  Q2-Q3 2008  Q4 2008  Q1 2009  Q2 2009
    -------------------------------------------------------------------------
    Collar ceiling price         9.05           -        -        -        -
    Collar floor price           8.00           -        -        -        -
    Fixed                        6.65        6.68     6.89     7.74     7.01
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The following is a summary of the gain (loss) on commodity contracts for
the years ended December 31, 2007 and 2006:

    Commodity contracts
    -------------------------------------------------------------------------
                                                Crude Oil   Natural     2007
    ($000s)                                     & Liquids       Gas    Total
    -------------------------------------------------------------------------
    Realized cash gain (loss) on contracts(1)      (1,891)    8,382    6,491
    Unrealized gain (loss) on contracts           (11,404)    1,061  (10,343)
    -------------------------------------------------------------------------
    Total gain (loss) on commodity contracts      (13,295)    9,443   (3,852)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



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

                                                Crude Oil   Natural     2006
    ($000s)                                     & Liquids       Gas    Total
    -------------------------------------------------------------------------
    Realized cash gain (loss) on contracts(2)        (890)    3,529    2,639
    Unrealized gain (loss) on contracts                 -         -        -
    -------------------------------------------------------------------------
    Total gain (loss) on commodity contracts         (890)    3,529    2,639
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Includes crude oil and natural gas commodity contract premiums
        expensed in the year and the amortization of prior year crude oil and
        natural gas commodity contract premiums of a total $3.7 million for
        year ended December 31, 2007.

    (2) Includes the amortization of crude oil and natural gas commodity
        contract premiums of a total $1.8 million for the year ended
        December 31, 2006.
    

    Effective January 1, 2007, new accounting standards were implemented
relating to financial instruments. The impacts of adopting the new standards
are reflected in the Trust's results for the year ended December 31, 2007.
Prior year comparative financial statements have not been restated. For a
description of the new accounting standards and the impact on the Trust's
financial statements of adopting such rules, including the impact on the
Trust's prepaid expenses, deferred financing charges, long-term debt,
convertible debentures and unrealized gains on commodity contracts, refer to
note 3 of the consolidated financial statements of the Trust for year ended
December 31, 2007.

    Royalties

    For the year ended December 31, 2007, total royalties were $47.0 million,
compared to $51.8 million incurred in 2006. Overall royalties as a percentage
of revenue (after transportation costs) in 2007 were 19%, compared with 24% in
2006. Royalties for 2007 include the impact of the reversal of certain over
accruals for heavy crude oil and natural gas royalties from periods prior to
2007 of approximately $5.5 million, including adjustments primarily recognized
in the second quarter of 2007. Based upon the latest and most up-to-date
information and experience, it was determined that certain prior period
royalty accrual estimates were overstated by approximately 2% per month on
average as a percentage of revenue after transportation costs.

    
    -------------------------------------------------------------------------
    Royalties by Commodity Type                      Years ended December 31,
    ($000s, except where noted)                            2007         2006
    -------------------------------------------------------------------------
    Light crude oil, condensate and NGLs                  9,772        6,707
      $/bbl                                               14.24        10.77
      Average light crude oil, condensate,
       and NGLs royalty rate (%)                             22           18

    Heavy Oil                                             6,867       14,395
      $/bbl                                                5.45        10.91
      Average heavy oil royalty rate (%)                     14           28

    Natural Gas                                          30,365       30,714
      $/mcf                                                1.28         1.64
      Average natural gas royalty rate (%)                   20           25

    -------------------------------------------------------------------------
    Total                                                47,004       51,816
    -------------------------------------------------------------------------
      $/boe                                                7.98        10.24
    -------------------------------------------------------------------------
      Average total royalty rate (%)                         19           24
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    Royalties, by Type
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($000s)                                                2007         2006
    -------------------------------------------------------------------------
    Crown royalties, net of ARTC                         20,799       32,243
    Indian Oil and Gas Canada royalties                   5,927        2,948
    Freehold & GORR                                      20,278       16,625
    -------------------------------------------------------------------------
    Total                                                47,004       51,816
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    Expenses
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($000s)                                                2007         2006
    -------------------------------------------------------------------------
    Production                                           68,282       46,685
    Transportation                                        7,938        6,517
    General and administrative                           18,186       14,896
    Interest and financing charges                       18,108       10,665
    Unit-based compensation                                 901        6,597
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    Expenses per boe
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($ per boe)                                            2007         2006
    -------------------------------------------------------------------------
    Production                                            11.59         9.23
    Transportation                                         1.35         1.29
    General and administrative                             3.09         2.94
    Interest and financing charges                         3.07         2.11
    Unit-based compensation                                0.15         1.30
    -------------------------------------------------------------------------
    

    Production Expenses

    For the year ended December 31, 2007, production expenses totaled
$68.3 million, compared to $46.6 million recorded in 2006. During 2007,
production expenses averaged $11.59/boe, compared to $9.23/boe over the same
period in 2006. The increase in 2007 costs on a boe basis was mainly due to a
significant fixed component of production expenses and the combination of
substantially reduced production volumes primarily in the third and fourth
quarters of 2007. Production expenses for 2007 also include approximately
$4.4 million ($0.76/boe) of costs related to 2006, including primarily
additional costs recognized in the second quarter of 2007; excluding this
impact, production expenses for 2007 would have been approximately $10.83/boe.
    Production expenses are expected to increase in the first quarter of 2008
as additional natural gas input costs continue to be required to operate the
Kerrobert SAGD facility after startup in late 2007. To mitigate expected
increases in natural gas fuel costs through the first quarter of 2008, True
has negotiated fixed price fuel purchase contracts, with contract remaining of
2,000 GJ/day of natural gas for $6.415/GJ for the months of November 2007 to
March 2008.

    
    Production Expenses, by Commodity Type
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($000s, except where noted)                            2007         2006
    -------------------------------------------------------------------------
    Light crude oil, condensate and NGLs                  9,906        7,873
      $/bbl                                               14.44        12.65

    Heavy oil                                            18,301       13,754
      $/bbl                                               14.53        10.43

    Natural gas                                          40,075       25,058
      $/mcf                                                1.69         1.34

    -------------------------------------------------------------------------
    Total                                                68,282       46,685
    -------------------------------------------------------------------------
      $/boe                                               11.59         9.23
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Total                                                68,282       46,685
    Processing and other third party income(1)           (4,402)      (1,336)
    -------------------------------------------------------------------------
    Total after deducting processing and other
     third party income                                  63,880       45,349
    -------------------------------------------------------------------------
      $/boe                                               10.84         8.96
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Processing and other third party income is included within petroleum
        and natural gas sales on the statement of income.

    Transportation

    Transportation costs continue to be approximately 2 to 3% of gross
revenues for the years ended December 31, 2007 and 2006.

    Operating Netback

    For the 2007, corporate field operating netback (before hedging) was
$22.21/boe compared to $22.60/boe in 2006. This was the result of marginally
reduced overall commodity prices, higher operating costs experienced in the
year, offset by reduced average royalties. After including hedging activities,
the corporate field operating netback for 2007 was $21.55/boe compared to
$23.12/boe in 2006.

    Field Operating Netback - Corporate (before hedging)
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($/boe)                                                2007         2006
    -------------------------------------------------------------------------
    Sales                                                 43.13        43.36
    Transportation                                        (1.35)       (1.29)
    Royalties                                             (7.98)      (10.24)
    Production expense                                   (11.59)       (9.23)
    -------------------------------------------------------------------------
    Field operating netback                               22.21        22.60
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Field operating netback for natural gas for 2007 decreased 3% to
$3.47/mcf, compared to $3.59/mcf for 2006, reflecting the marginally weaker
natural gas prices experienced, in addition to higher production costs, the
effects of which were partially offset by lower royalties. After including
hedging activities, field operating netback for natural gas for 2007 was
$3.87/mcf compared to $3.77/mcf in 2006.

    Field Operating Netback - Natural Gas (before hedging)
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($/mcf)                                                2007         2006
    -------------------------------------------------------------------------
    Sales                                                  6.73         6.75
    Transportation                                        (0.29)       (0.18)
    Royalties                                             (1.28)       (1.64)
    Production expense                                    (1.69)       (1.34)
    -------------------------------------------------------------------------
    Field operating netback                                3.47         3.59
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Field operating netback for crude oil and NGLs averaged $25.01/bbl for
2007, up 3% compared to $24.36/bbl for 2006, compared to a 1% increase in the
crude oil and NGLs sales price. After including hedging activities, field
operating netback for crude oil and NGLs for 2007 was $18.17/boe compared to
$23.90/boe in 2006; the loss on commodity contracts for 2007 includes
$11.4 million of unrealized crude oil hedging losses valued at December 31,
2007.

    Field Operating Netback - Crude Oil and NGLs (before hedging)
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($/bbl)                                                2007         2006
    -------------------------------------------------------------------------
    Sales                                                 48.71        48.00
    Transportation                                        (0.65)       (1.63)
    Royalties                                             (8.55)      (10.87)
    Production expense                                   (14.50)      (11.14)
    -------------------------------------------------------------------------
    Field operating netback                               25.01        24.36
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    General and Administrative

    Net general and administrative ("G&A") expenses for 2007 were
$18.2 million compared to $14.9 million for 2006. The increase in the G&A
expense from 2006 to 2007 is consistent with the increase in staffing levels,
higher compensation and other administrative costs as a result of two
acquisitions completed in 2006. G&A for 2007 includes severance costs of
approximately $1.1 million. On a per boe basis, G&A expenses were $3.09/boe
for 2007 compared to $2.94/boe for 2006. The increase in G&A on a per boe
basis is consistent with reduced sales volumes experienced during the third
and fourth quarters of 2007 compared to earlier in 2007 and the fourth quarter
of 2006.

    General and Administrative Expenses
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($000s, except where noted)                            2007         2006
    -------------------------------------------------------------------------
    Gross expenses                                       24,191       19,702
    Capitalized                                          (3,881)      (2,640)
    Recoveries                                           (2,124)      (2,166)
    -------------------------------------------------------------------------
    Net expenses                                         18,186       14,896
    -------------------------------------------------------------------------
    Net expenses, per unit ($/boe)                         3.09         2.94
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    G&A expenses for the year ended December 31, 2007 do not include the costs
of the March 30, 2007 Annual and Special Meeting, which are presented
separately on the statement of income and discussed in the Special Meeting
Costs section of this report.

    Interest and Financing Charges

    True recorded $18.1 million of interest and financing charges in the year
ended December 31, 2007 compared to $10.7 million in 2006. The increase in
interest and financing charges for 2007 compared to 2006 is consistent with
the increase in bank debt. True's net debt at December 31, 2007 of
$251.2 million includes the $79.4 million liability portion of convertible
debentures, $168.5 million of bank debt and the balance a working capital
deficiency.

    Interest and Financing Charges
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($000s, except where noted)                            2007         2006
    -------------------------------------------------------------------------
    Interest and financing charges                       18,108       10,665
    Interest and financing charges ($/boe)                 3.07         2.11

    Net debt(1)including convertible debentures at
     quarter end                                        251,163      275,816
    Debt to periods funds flow from operations
     ratio annualized(2)                                   3.2x         2.1x

    Net debt excluding convertible debentures at
     quarter end                                        171,756      194,265
    Debt to periods funds flow from operations
     ratio annualized(2)                                   2.2x         1.5x
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (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
        fourth quarter funds flow from operations annualized.
    

    Unit-Based Compensation

    Non-cash unit-based compensation expense for the year ended December 31,
2007 was $2.0 million compared to $6.6 million in 2006. The decrease in the
2007 expense reflects a reduction in the estimated weighted average fair value
of incentive rights granted for more recent options, a reduction to the 2007
expense of $1.8 million for a reversal of prior year unit-based compensation
expense for 2007 forfeitures of unvested incentive rights and slightly reduced
incentive rights being granted in 2007 compared to 2006.

    Capital Expenditures

    True invested $87.4 million on exploration and development activities
during 2007, compared to $98.7 million in 2006. True reduced its 2007 capital
program in Western Canada in response to high costs and weaker commodity
prices. Following the execution of True's extensive Q1 2007 drilling program
of 34 (24.0 net) wells, the main focus for the second, third and fourth
quarters of 2007 was on completions and tie-ins of first quarter drills and
further upgrades to the Kerrobert SAGD facility. During the 2007 year, True
achieved a 98% success rate in drilling or participation in 40 (27.3 net)
working interest wells, resulting in 20 (10.4 net) gas wells, 17 (14.4 net)
oil wells, 2 (2 net) stratagraphic test wells and 1 (0.5 net) dry hole. During
the fourth quarter of 2007, True successfully drilled 3 (1.0 net) natural gas
wells in the Ferrier area of Alberta.

    
    Capital Expenditures(1)
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($000s)                                                2007         2006
    -------------------------------------------------------------------------
    Lease acquisitions and retention                      2,084        9,056
    Geological and geophysical                            4,275        2,399
    Drilling and completion costs                        64,688       68,702
    Facilities and equipment                             15,294       18,533
    Other capital(2)                                      1,056            -
    -------------------------------------------------------------------------
      Exploration and development                        87,397       98,690
    Corporate and property acquisitions                   1,505       17,322
    -------------------------------------------------------------------------
      Total capital expenditures - cash                  88,902      116,012
    Property dispositions - cash                        (31,808)     (24,514)
    -------------------------------------------------------------------------
      Total net capital expenditures - cash              57,094       91,498
    -------------------------------------------------------------------------
    Corporate acquisitions - non-cash                         -      482,875
    Property acquisitions - non-cash(3)                       -        1,817
    Other - non-cash(4)                                     270        3,006
    -------------------------------------------------------------------------
    Corporate acquisitions and other                        270      487,698
    -------------------------------------------------------------------------
      Total capital expenditures                         57,364      579,196
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Excludes capitalized costs related to asset retirement obligation
        expenditures incurred during the year.
    (2) Other capital for 2007 include natural gas input costs incurred
        during the initial "warm-up" phase at the Kerrobert SAGD expansion
        project.
    (3) Includes consideration paid for the acquisition of a property
        interest by issue of trust units.
    (4) Other includes current period's asset retirement obligations and unit
        based compensation capitalized.
    

    Approximately 31 percent of the $88.9 million capital program was
financed with funds flow from operations compared to nil in 2006. The
remainder of the program was financed through a combination of property
dispositions and debt and equity financings.
    True holds an extensive land base. At December 31, 2007, True had
approximately 537,800 net undeveloped acres of land of its total developed and
undeveloped net acreage position of 936,400 net acres in Saskatchewan,
Alberta, and British Columbia.
    Dispositions during 2007 consist of seven separate oil and gas property
sales involving areas outside of the Trust's core areas for future
development. The net proceeds received on these property sales after
adjustments was an aggregate of $31.8 million.
    At the end of the fourth quarter of 2007, the Trust had committed to
drill a total of 2 wells in Alberta with varying commitment dates up to the
end of the 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 2007 was $171.5 million
($29.11/boe), compared to the $138.9 million ($27.45/boe) in 2006, reflecting
the acquisition of Prairie Schooner in September 2006 in conjunction with
increased production volumes and True's active drilling program over 2006 and
2007.
    For the year ended December 31, 2007, True has included $56.6 million for
future development costs in the depletion calculation and excluded from the
depletion calculation $37.8 million for undeveloped land and $47.6 million for
estimated salvage.

    
    Depletion, Depreciation and Accretion Costs
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($000s, except where noted)                            2007         2006
    -------------------------------------------------------------------------
    Depletion and Depreciation                          169,347      137,810
    Accretion                                             2,137        1,065
    -------------------------------------------------------------------------
      Total                                             171,484      138,875
    -------------------------------------------------------------------------
    Per unit ($/boe)                                      29.11        27.45
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    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 December 31, 2007
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
December 31, 2007.
    The ceiling test calculation will be updated in 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. The closing of the proposed
Saskatchewan asset divestiture will impact the determination of reserves for
purposes of the calculation of depletion, a potential gain (loss) on disposal
of petroleum and natural gas properties and the ceiling test. Estimating
reserves is very complex, requiring many judgments based on available
geological, geophysical, engineering and economic data. Changes in these
judgments could have a material impact on the estimated reserves. These
estimates may change, having either a negative or positive effect on net
earnings as further information becomes available and as the economic
environment changes. Changes in these judgments and estimates and other
variables associated with the closing of the proposed Saskatchewan asset
divestiture could have a material impact on the calculations of depletion, a
potential gain (loss) on disposal of petroleum and natural gas properties and
the ceiling test.
    In 2006, as a result of performing this test, a ceiling test impairment
of $110.0 million was recorded as a write-down of petroleum and natural gas
properties in the consolidated statements of operations and was included in
accumulated depletion.

    Goodwill

    Goodwill represents the excess of total consideration paid plus the
future income tax liability less the fair value of the net identifiable assets
acquired in each acquisition transaction. Accounting standards require that
the goodwill balance be assessed for impairment at least annually or more
frequently if events or changes in circumstances indicate that the balance
might be impaired.
    The Trust reviewed the valuation of goodwill as of December 31, 2006
based upon the latest available data. Based upon this review, an impairment of
all remaining goodwill in the amount of $169.8 million was recorded as a non-
cash charge to income as of December 31, 2006.

    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 year ended December 31, 2007.

    Asset Retirement Obligations

    As at December 31, 2007, the Trust has recorded an Asset Retirement
Obligation ("ARO") of $28.4 million, compared to $26.6 million at December 31,
2006, for future abandonment and reclamation of the Trust's properties. For
the year ended December 31, 2007, the ARO increased by $1.8 million total as a
result of accretion expense of $2.1 million, and $1.4 million net changes in
estimates and liabilities incurred on development activities, offset by
$0.9 million of liabilities released on dispositions and $0.8 million of
liabilities settled during the year.

    Income Taxes

    For the year ended December 31, 2007, the Trust has recorded capital tax
expense of $2.0 million compared to $3.2 million expensed in 2006. Capital
taxes are based on debt and equity levels of the Trust at the end of the year
in addition to a resource surcharge component of provincial taxes calculated
as a percentage of revenues. In the second quarter of 2006, the federal
government enacted legislation that eliminates federal capital tax,
retroactive to January 1, 2006. As a result, 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 year ended December 31,
2007, the Trust recognized a future income tax recovery of $59.8 million
compared to a recovery of $101.1 million in 2006. On April 10, 2006 the
Alberta government enacted a decrease of 1.5 percent to the provincial
corporate tax rate. 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, reducing the
combined federal and deemed provincial tax rate for distributions to
28 percent in 2012. During the fourth quarter of 2007, a $9.3 million future
income tax recovery was recorded to reflect these substantively enacted tax
rates.
    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
basis. Until 2011, under the terms of its trust indenture, the Trust is
required to distribute amounts equal to at least its taxable income. In the
event that the Trust has undistributed taxable income in a taxation year
(prior to 2011), an additional special taxable distribution, subject to
certain withholding taxes, would be required by the terms of its trust
indenture.
    The estimate of future taxes is based on the current tax status of the
Trust. Future events, which could materially affect future income taxes such
as acquisitions and dispositions and modifications to the distribution policy,
are not reflected under Canadian GAAP until the events occur and the related
legal requirements have been fulfilled. As a result, future changes to the tax
legislation could lead to a material change in the recorded amount of future
income taxes.
    The new legislation is not expected to directly affect our cash flow
levels and distribution policies until 2011 at the earliest.

    Enactment of the Tax on Income Trusts

    On June 12, 2007, the legislation implementing the new tax (the "SIFT
tax") on publicly traded income trusts and limited partnerships, referred to
as "Specified investment flow-through" ("SIFTs") entities (Bill C-52) received
third reading in the House of Commons and on June 22, 2007, Bill C-52 received
Royal assent. As a result, the 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 Trust currently
has a significant tax pool base and expects to increase its tax pool base
until 2011, it is expected that the Trust could shelter its taxable income for
a period after the effective date of the SIFT tax. 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 in Alberta, where the provincial tax rate in
2011 is expected to be 10%. Taxable distributions that are not allocated to
any province would instead be subject to a 10% rate constituting the
provincial component. 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 trust 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 29.5 percent in 2011
        and 28.0 percent in 2012 and beyond. For U.S. investors, the
        distribution yield net of the SIFT and withholding taxes would fall
        by an estimated 25.1 percent in 2011 and 23.8 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.
        Further, as the SIFT tax rate exceeds the corporate income tax rate
        that would be applicable to True, some corporate tax might be paid
        resulting in all or a portion of distributions being paid on a return
        of capital basis at a lower payout ratio.

    The Trust is reviewing all organizational structures and alternatives to
minimize the impact of the SIFT tax on our unitholders. While there can be no
assurance that the negative effect of the tax can be minimized or eliminated,
True and its advisors will continue to work diligently on these issues.
    As at December 31, 2007, the operating subsidiaries and the Trust itself
have a total future income tax liability balance of $64.3 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 December 31, 2007 the Trust and operating subsidiaries of the Trust had
approximately $531 million, net of partnership deferrals, in tax pools
available for deduction against future income as follows:

    -------------------------------------------------------------------------
                                                      Operating
    ($000s)                                 Trust  subsidiaries        Total
    -------------------------------------------------------------------------
    Intangible resource pools              15,000       328,000      343,000
    Undepreciated capital cost                  -       143,000      143,000
    Loss carryforwards
     (expire through 2027)                      -        35,000       35,000
    Unit issue costs                        6,000         4,000       10,000
    -------------------------------------------------------------------------
                                           21,000       510,000      531,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Distributions

    Trust unitholders who held their trust units throughout 2007 received
distributions of $0.96 per unit.  For the year ended December 31, 2007 the
Trust declared $73.5 million in total distributions as follows:

    -------------------------------------------------------------------------
    ($000s, except per unit amount)                Distribution
    Year ended December 31, 2007                       Per Unit        Total
    -------------------------------------------------------------------------

    Distributions declared                           $     0.96   $   73,451
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Distribution Paid History(1)

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

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

                                     Distributions      Taxable    Return of
    Calendar Year                         per unit      Portion      Capital
    -------------------------------------------------------------------------

    2005 (two months)(2)                $    0.480   $    0.456   $    0.024
    2006                                     2.640        2.033        0.607
    -------------------------------------------------------------------------
    Cumulative to Dec. 31, 2006         $    3.120   $    2.489   $    0.631
    -------------------------------------------------------------------------
    2007 year(3)                             0.960        0.960            -
    -------------------------------------------------------------------------
    Cumulative to Dec. 31, 2007         $    4.080   $    3.449   $    0.631
    -------------------------------------------------------------------------
    2008 year to date (two months)(4)        0.080
    -----------------------------------------------
    Cumulative to Feb. 29, 2008         $    4.160
    -----------------------------------------------

    (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) For Canadian tax purposes, 2007 distributions were determined to be
        100% taxable.

        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.

    (4) 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.

    Monthly Distributions

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

                                                                Distribution
    Ex-distribution Date   Record Date          Payment Date        per unit
    -------------------------------------------------------------------------

    December 27, 2006      December 31, 2006    January 15, 2007      $ 0.12
    January 29, 2007       January 31, 2007     February 15, 2007       0.12
    February 26, 2007      February 28, 2007    March 15, 2007          0.12
    April 26, 2007         April 30, 2007       May 15, 2007            0.08
    May 29, 2007           May 31, 2007         June 15, 2007           0.08
    June 27, 2007          June 29, 2007        July 16, 2007           0.08
    July 27, 2007          July 31, 2007        August 15, 2007         0.08
    August 29, 2007        August 31, 2007      September 17, 2007      0.08
    September 26, 2007     September 28, 2007   October 15, 2007        0.08
    October 29, 2007       October 31, 2007     November 15, 2007       0.08
    November 28, 2007      November 30, 2007    December 17, 2007       0.08
    December 27, 2007      December 31, 2007    January 15, 2008        0.08
    -------------------------------------------------------------------------
    

    During 2007, the distributions were funded directly from funds flow from
operations.
    On January 15, 2007, the Trust announced its intention to convert to a
growth oriented, dividend paying intermediate exploration and production
company (the "Reorganization"), which was voted upon by securityholders at an
Annual and Special Meeting (the "Meeting") held on March 30, 2007. Further as
announced on February 15, 2007, the Board of True determined that no
distribution would be declared for the month of March 2007, which would
normally have been paid on April 16, 2007 to unitholders of record as at
March 30, 2007, pending the consideration of the Reorganization at the
Meeting. As a result of the outcome of the Meeting, wherein the Reorganization
was not approved, True remains a trust.
    In the second, third, and fourth quarters of 2007, monthly distributions
of $0.08 per unit were declared and paid. On December 17, 2007, the Trust
announced that the Board has set the distribution policy for the first 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 that this reduction will allow the Trust's distributions to be
sustainable in the current gas price, foreign exchange rate and cost
environment.
    The Premium Distribution(TM) Reinvestment, Distribution Reinvestment and
Optional Trust Unit Purchase Plan ("DRIP") was implemented effective March 27,
2006. Funds reinvested in the Trust through this plan were available to fund
capital and other expenditures. On November 16, 2006, the Trust announced the
suspension of equity available for reinvestment under DRIP until further
notice.

    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
February 21, 2008 approximately 29 percent of unitholders are non-Canadian
residents with the remaining 71 percent being Canadian residents. True's trust
indenture provides that not more than 40 percent of its trust units can be
held by non-Canadian residents.

    Liquidity and Capital Resources

    True's net debt as at December 31, 2007 was $251.2 million, representing
$168.5 million outstanding on the credit facility, $79.4 million in
convertible debentures (liability component) and the balance a working capital
deficiency.
    During the year ended December 31, 2007, the Trust has reduced its net
debt by approximately $24.7 million. As at December 31, 2007, working capital
was a $3.3 million deficiency compared to a working capital deficiency of
$36.4 million at December 31, 2006. This was achieved as a result of many
factors including the proceeds received from the Trust's May 31, 2007 equity
offering, proceeds received from seven property dispositions, maintaining
reasonable distributions compared to funds flow from operations for the year
and capital expenditure requirements in the period and continued execution of
the Trust's hedging program. 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.
    On May 31, 2007, the Trust completed its offering, including an
over-allotment option, for an aggregate of 9,430,000 trust units for gross
proceeds of $57.5 million. The net proceeds of $54.4 million, after deducting
unit issue costs, was used to pay down debt.
    The current credit facility consists of a $15 million demand operating
facility provided by one Canadian bank and a $175 million extendible revolving
term credit facility syndicated by two Canadian chartered banks, a U.S. bank,
a Canadian financial institution and one institutional lender. The revolving
period on the revolving term credit facility ends on June 29, 2008, unless
extended for a further 364 day period. Should the facilities not be renewed
they convert to 366 day non-revolving term facilities on the renewal date. The
borrowing base was renewed effective August 31, 2007 and is currently
scheduled for renewal on March 31, 2008. Further details of the credit
facilities are disclosed in note 8 of the consolidated financial statements.
As at December 31, 2007, there is approximately $22 million undrawn under
these lending facilities.
    The Trust does not hold any non-bank 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 February 22, 2008, the Trust had outstanding a total of 5,388,498
incentive units exercisable at an average exercise price of $8.62 per unit,
382,075 exchangeable shares (convertible, as at February 22, 2008 into an
aggregate of 341,151 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 79,222,715 trust units.
    As announced, True intends to divest of its Saskatchewan assets as part
of a new strategic direction for the Trust. Further to this announcement, True
intends to divest its oil and natural gas assets in Saskatchewan including
Kerrobert's SAGD project, and properties at Smiley, Coleville, Dodsland and
Mantario. December 2007 average production from the Saskatchewan assets was
approximately 5,600 boe/d, weighted 62% to oil (97% heavy oil, 3% light oil).
The assets include 18.8 mmboe of reserves and approximately 250,000 net acres
of land. True anticipates significant proceeds from the disposition of its
Saskatchewan properties in a time of historically high oil prices and the
current favorable royalty regime in Saskatchewan. It is anticipated that any
proceeds from the disposition of the Trust's Saskatchewan assets, currently
anticipated to close at the end of the first quarter of 2008, will be utilized
to eliminate True's bank indebtedness and to provide additional financial
resources to develop its Alberta light oil and natural gas plays.

    Commitments

    As at December 31, 2007, 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.
    The Trust has further committed to various corporate sponsorships
extending to June 2011 at an estimated combined cost of up to $332,000.

    Off-Balance Sheet Arrangements

    The Trust has certain lease agreements, of which the office space leases
are reflected in the table below, 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 December 31, 2007.
    The Trust is committed to payments under operating leases for office
space as follows:

    
    -------------------------------------------------------------------------
    ($000s)                                            Expected
    Year                              Gross Amount   Recoveries   Net amount
    -------------------------------------------------------------------------
    2008                                   $ 1,685      $   297      $ 1,388
    2009                                     1,893          297        1,596
    2010                                     2,118          297        1,821
    2011                                     2,161            -        2,161
    2012                                     2,190            -        2,190
    -------------------------------------------------------------------------
    

    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.
    Following the results of the Special and Annual Meeting held on March 30,
2007, True remains a trust. Therefore, the focus will continue to be
maintaining sufficient cash flow to provide a balance between unitholder
distributions and funding of the Trust's capital program.
    Advancement of the Kerrobert SAGD project continues. During the first
quarter of 2008, True has increased steam rates to the 4 new steam injectors
to near maximum levels. Wellhead injection pressures have uniformly increased
indicating a re-pressurization of the reservoir. Further evidence of re-
pressurization has been seen through the consistent increase of wellbore fluid
levels and downhole pump inlet pressures. Production well temperatures have
remained at near initial reservoir levels indicating even heating is underway
and that no random, premature, breakthrough has occurred - a positive
indicator of overall project conformance. Based on the recovery responses of
the original 1996 pilot project, estimated oil rate increases on the current
project should occur 4 to 6 months after start-up. As we approach the midpoint
of the 4 to 6 month timing range it is clear there will not be an "early"
response, however all technical parameters continue to point to a very
positive project.
    Field production estimates for the first quarter of 2008 are expected to
average approximately 13,200 boe/d. Field production was adversely impacted by
the extreme weather experienced in January and February of 2008. In addition,
an unplanned third party plant outage impacted production in west central
Alberta for February 2008. Work is underway to deal with a well servicing and
equipment repair backlog.
    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 800,100 (537,800 net) acres and has identified a multi-year
drilling inventory of over 375 net locations.
    Gas prices continue to show volatility with uncertainty regarding weather
and its effect on natural gas demand and storage and global factors including
LNG shipments to North America. Given the natural gas price outlook, coming
into the winter drilling season, True plans to reduce its first quarter 2008
winter drilling activity compared to the first quarter of 2007. True's first
quarter 2008 capital program will not exceed $10 million which compares to a
front end loaded 2007 capital program of approximately $50 million in first
quarter 2007. True will continue to take a balanced approach to the priority
use of cash flow between level of distributions and size of its 2008 capital
program. Given the nature of True's lands and their inherent advantage of year
round access, True will spread its 2008 capital program more evenly through
the full year of 2008 to take advantage of reduced service costs during non-
peak times. True will focus on increasing its farm-out activity in non-core
areas. If the 2008 outlook for commodity prices improves, True would plan to
increase its capital spending in third and fourth quarters of 2008.
Additionally, any proceeds from the expected closing of True's proposed
Saskatchewan asset divestiture, currently anticipated to close at the end of
the first quarter of 2008, are intended to be used to pay down debt related to
True's existing bank facility and fund an expanded 2008 capital program of
$60 million. True's 2008 capital program, post-asset disposition, is
anticipated to focus on operated core properties in West Central and Northern
Alberta.

    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.

    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.

    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

    True's production and exploration activities are concentrated in the
Western Canadian Sedimentary Basin, where activity is highly competitive and
includes a variety of different sized companies ranging from smaller junior
producers to the much larger integrated petroleum companies.

    True is subject to the various types of business risks and uncertainties
including:

    
    -   Finding and developing oil and natural gas reserves at economic
        costs;

    -   Production of oil and natural gas in commercial quantities; and

    -   Marketability of oil and natural gas produced.
    

    In order to reduce exploration risk, the Trust strives to employ highly
qualified and motivated professional employees with a demonstrated ability to
generate quality proprietary geological and geophysical prospects. To help
maximize drilling success, True combines exploration in areas that afford
multi-zone prospect potential, targeting a range of low to moderate risk
prospects with some exposure to select high-risk with high-reward
opportunities. True also explores in areas where the Trust has significant
drilling experience.
    The Trust mitigates its risk related to producing hydrocarbons through
the utilization of the most appropriate technology and information systems
managed by qualified personnel. In addition, True seeks to maintain
operational control of the majority of its prospects.
    Oil and gas exploration and production can involve environmental risks
such as pollution of the environment and destruction of natural habitat, as
well as safety risks such as personal injury. In order to mitigate such risks,
True conducts its operations at high standards and follows safety procedures
intended to reduce the potential for personal injury to employees, contractors
and the public at large. The Trust maintains current insurance coverage for
general and comprehensive liability as well as limited pollution liability.
The amount and terms of this insurance are reviewed on an ongoing basis and
adjusted as necessary to reflect changing corporate requirements, as well as
industry standards and government regulations. True may periodically use
financial or physical delivery hedges to reduce its exposure against the
potential adverse impact of commodity price volatility, as governed by formal
policies approved by senior management subject to controls established by the
Board.
    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.
    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.
    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 currently available
public information, 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. 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
new Alberta royalty regime, 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 New Alberta Royalty Framework will impact future
drilling decisions in order for the Trust to maintain acceptable rates of
return on its capital deployed. The Alberta Government has stated that they
are reviewing with industry the proposed royalty changes to ensure that there
are no unintended consequences resulting from the royalty changes. It is not
known at this time whether any further revisions to the proposals will be made
nor what their impact may be.
    True is continuing to assess the impact on its ongoing Alberta
operations. While the Trust cannot determine the full potential impact of
these changes to the royalty rate on its operations at this time, it is
anticipated that the impact will not be material to True given True's
production in Alberta being primarily in shallow natural gas wells. True's
proposed divestiture of its Saskatchewan assets will impact True's weighting
of production in Alberta, subject to the New Royalty Framework.

    Critical Accounting Estimates

    The reader is advised that the critical accounting estimates, policies,
and practices as described in the Trust's Management's Discussion and Analysis
continue to be critical in determining True's financial results.
    The reader is 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. The following discussion outlines accounting policies and
practices that are critical to determining True's financial results.
    The Trust uses the full cost method of accounting for oil and gas
properties. Generally, all costs of exploring and developing oil and natural
gas reserves are capitalized and depleted against associated oil and natural
gas production using the unit-of-production method based on the estimated
proved reserves using forecast pricing. Estimating reserves is also critical
to several accounting estimates and requires judgments and decisions based
upon available geological, geophysical, engineering and economic data.
Estimated reserves are also utilized by True's bank in determining credit
facilities. Reserves affect net income through depletion and the ceiling test
calculation. Estimating reserves is very complex, requiring many judgments
based on available geological, geophysical, engineering and economic data.
Changes in these judgments could have a material impact on the estimated
reserves. These estimates may change, having either a negative or positive
effect on net earnings as further information becomes available, and as the
economic environment changes. Changes in these judgments and estimates could
have a material impact on the financial results and financial condition.
    The discounted, expected future cost of statutory, contractual or legal
obligations to retire long-lived assets are recorded as an Asset Retirement
Obligation ("ARO") liability with a corresponding increase to the carrying
amount of the related asset. The recorded ARO liability increases over time to
its future amount through accretion charges to earnings. Revisions to the
estimated amount or timing of the obligations are reflected as increases or
decreases to the ARO liability. Amounts capitalized to the related assets are
amortized to income consistent with the depletion or depreciation of the
underlying asset.
    In following the liability method of accounting for income taxes, related
assets and liabilities are recognized for the estimated tax consequences
between amounts included in the financial statements and their tax base using
substantively enacted future income tax rates. Timing of future revenue
streams and future capital spending changes can affect the timing of any
temporary differences, and accordingly affect the amount of the future income
tax liability calculated at a point in time. These differences could
materially impact earnings.
    The Trust is involved in various claims and litigation arising in the
normal course of business. While the outcome of these matters is uncertain and
there can be no assurance that such matters will be resolved in the Trust's
favor, the Trust does not currently believe that the outcome of adverse
decisions in any pending or threatened proceeding related to these and other
matters or any amount which it may be required to pay by reason thereof would
have a material adverse impact on its financial position or results of
operations.
    With the above risks and uncertainties the reader is cautioned that
future events and results may vary substantially from that which True
currently foresees.

    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. True's Chief Executive Officer and Chief Financial Officer
have concluded, based on their evaluation as of the end of the period covered
by the annual filings, that True's disclosure controls and procedures as of
the end of such period are effective to provide reasonable assurance that
material information relating to True, including its consolidated
subsidiaries, is made known to them by others within those entities,
particularly during the period in which the annual filings are being prepared.

    Internal Controls over Financial Reporting

    The Trust's Chief Executive Officer and Chief Financial Officer have
designed or caused to be designed under their supervision internal controls
over financial reporting to provide reasonable assurance regarding the
reliability of the Trust's financial reporting and the preparation of
financial statements for external purposes in accordance with the Canadian
GAAP.
    The Trust's Chief Executive Officer and Chief Financial Officer are
required to cause the Trust to disclose herein any change in the Trust's
internal control over financial reporting that occurred during the Trust's
most recent interim period that has materially affected, or is reasonably
likely to materially affect, the Trust's internal control over financial
reporting. No material changes in the Trust's internal control over financial
reporting were identified during the three months ended December 31, 2007,
that has materially affected, or are reasonably likely to materially affect,
the Trust's internal control over financial reporting.
    It should be noted that a control system, including the Trust's
disclosure and internal controls and procedures, no matter how well conceived,
can provide only reasonable, but not absolute, assurance that the objectives
of the control system will be met and it should not be expected that the
disclosure and internal controls and procedures will prevent all errors or
fraud.

    Standardized Distributable Cash

    The Canadian Securities Administrators recently revised and re-issued
National Policy 41-201 "Income Trusts and Other Indirect Offerings", which
includes disclosures regarding distributable cash for Income Trusts. Further,
the Canadian Institute of Chartered Accountants ("CICA") issued the
Interpretive Release "Standardized Distributable Cash in Income Trusts and
Other Flow-Through Entities: Guidance on Preparation and Disclosure" (the
"Release") in July 2007, which is required for the third quarter of 2007
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 and              Years ended December 31,
     percentages)                                          2007         2006
    -------------------------------------------------------------------------

    Net loss                                            (24,267)    (233,564)
    -------------------------------------------------------------------------

    Cash flow from operating activities                  82,206      126,800
    Productive capacity maintenance(1)                  (86,341)     (98,690)
    -------------------------------------------------------------------------
    Standardized distributable cash                      (4,135)      28,110

    Proceeds on sale of property, plant and
     equipment                                           31,808       24,514
    Corporate and property acquisition and other
     capital expenditures                                (2,561)     (17,322)
    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                                         -       42,608
    Bank borrowings (debt repayment) and working
     capital changes and other                           (4,378)     (35,816)
    -------------------------------------------------------------------------
    Cash Distributions declared                          73,451      124,355
    Accumulated distributions, beginning of period      141,716       17,361
    -------------------------------------------------------------------------
    Accumulated distributions, end of period            215,167      141,716
    -------------------------------------------------------------------------
    Standardized distributable cash  per unit
     - basic                                             $(0.05)       $0.60
    Standardized distributable cash  per unit
     - diluted                                           $(0.05)       $0.60
    -------------------------------------------------------------------------
    Standardized distributable cash payout ratio(2)         N/A          4.4
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Distributions declared per unit for outstanding
     units in the year                                    $0.96        $2.64

    Accumulated distributions per unit, beginning of
     year                                                  3.12         0.48
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Accumulated distributions per unit, end of year       $4.08        $3.12
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Excess (shortfall) of net income over cash
     distributions declared                             (97,718)    (357,919)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Excess of cash flow from operating activities
     over cash distributions declared                     8,755        2,445
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Please refer to the discussion of productive capacity maintenance
        below
    (2) Represents cash distributions declared divided by standardized
        distributable cash
    

    True strives to fund both distributions and maintenance capital primarily
from funds flow from operations. True's 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 December 31, 2007
    -------------------------------------------------------------------------
    Cumulative distributable cash from operations(1)                  24,298
    Proceeds on sale of property, plant and equipment                 56,322
    Corporate and property acquisitions and other
     capital expenditures                                            (19,883)
    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                                       (23,457)
    -------------------------------------------------------------------------
    Cumulative cash distributions declared(1)                        215,167
    -------------------------------------------------------------------------
    Standardized distributable cash payout ratio(2)                     8.85
    -------------------------------------------------------------------------

    (1) Subsequent to the November 2, 2005 reverse takeover of TKE Energy
        Trust
    (2) Represents cumulative distributions declared divided by cumulative
        standardized distributable cash

    Sensitivity Analysis

    The table below shows sensitivities to funds flow as a result of product
price and operational changes. This is based on actual 2007 prices received
for the fourth quarter of 2007 and average production volumes of 14,937 boe/d
during that period, as well as the same level of debt outstanding at
December 31, 2007. Diluted weighted average trust units is based upon the
fourth quarter of 2007. These sensitivities are approximations only, and not
necessarily valid under other significantly different production levels or
product mixes. Hedging activities can significantly affect these
sensitivities. Changes in any of these parameters will affect cash flow as
shown in the table below:

    -------------------------------------------------------------------------
                                                                  Funds Flow
                                                     Funds Flow         from
                                                           from   Operations
                                                     Operations  Per Diluted
                                                    (annualized)        Unit
    -------------------------------------------------------------------------
    Sensitivity Analysis                                 ($000s)          ($)
    -------------------------------------------------------------------------
    Change of US $1/bbl WTI                               1,500         0.02
    Change of $0.10/ mcf                                  1,600         0.02
    Change of US $0.01 Cdn/ US exchange rate                800         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 eight most recently completed quarters at the end of
2007.

    -------------------------------------------------------------------------
    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 flows from operations per unit".
    

    The quarterly results as presented for 2006 and 2007 varied significantly
for two main reasons: 1) the timing of acquisitions 2006 and 2) changes in
commodity prices over those periods.
    True completed the acquisitions of Shellbridge and Prairie Schooner on
June 23, 2006 and September 22, 2006, respectively. True's revenue, net
income, and cash flow from operations in 2006 and 2007 has reflected its
production base after considering the timing of the above noted acquisitions,
the results of ongoing drilling activities, and the timing of plant
turnarounds and other operational challenges, as well as the changes in
commodity prices, primarily that for natural gas. Beginning in 2005 and
continuing into the first quarter of 2006, natural gas prices were gradually
increasing; from second and third quarters of 2006, natural gas prices were on
the decline; from the fourth quarter of 2006 through to the second quarter of
2007, natural gas prices were increasing; and after a decline in natural gas
prices for the third quarter of 2007, natural gas prices for the fourth
quarter were again on the rise. The increase or decrease in natural gas prices
over these periods resulted in a corresponding increase or decrease in the
Trust's petroleum and natural gas revenue, net income and cash flow from
operations in the respective periods. Variations in the prices received for
crude oil, condensate and NGLs during these periods also has contributed to
the fluctuations in the Trust's revenue, net income and cash flow from
operations in the respective periods. Certain adjustments to royalties and
production expenses were recorded in 2007 for amounts related to pre-2007 as
discussed earlier in those respective sections.
    Net income also reflects an increase in DD&A rates since primarily since
the November 2005 reverse takeover of TKE Energy Trust offset by future tax
recoveries beginning in the same period. The increase in the Trust's DD&A rate
for 2006 was due to an increase in its depletable base as a result of the
acquisitions and further capital spending. Future tax recoveries recognized
since December 2005 result from additional interest deductions associated with
True's new Trust structure as well as reductions in rates for both federal and
provincial taxes which were enacted during 2006 and 2007. Net income for the
fourth quarter of 2006 is also reflective of a ceiling test write-down of
$110.0 million and a goodwill impairment charge of $169.8 million.

    
    Selected Annual Information

    -------------------------------------------------------------------------
    Years ended December 31,
    ($000s, except per unit amounts)            2007        2006        2005
    -------------------------------------------------------------------------
    Revenues before royalties and hedging    258,490     220,913     161,670
    Funds flow from operations(1)            101,172      90,391      87,137
    Funds flow from operations per unit(1)
      Basic                                    $1.33       $1.91       $3.53
      Diluted                                  $1.33       $1.87       $3.47
    Net income (loss)                        (24,267)   (233,564)     13,890
    Net income (loss) per unit
      Basic                                   $(0.32)     $(4.95)      $0.56
      Diluted                                 $(0.32)     $(4.95)      $0.55
    Net capital expenditures (cash)           57,094      91,498     115,920
    Total assets                             880,252   1,016,658     731,129
    Total net debt(2)                        251,163     275,816     111,129
    Long-term financial liabilities
      Obligations under capital lease              -           -          54
      Capital taxes payable                        -           -       1,700
      Future income taxes                     67,366     123,861     146,729
      Asset retirement obligations            28,373      26,605      10,457
      Exchangeable shares of Subsidiary        3,922       4,153       9,709
    Production (boe/d)                        16,139      13,861       8,672
    Distributions declared                    73,451     124,355      17,361
    Distributions per unit(3)                  $0.96       $2.64       $0.48
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) refer to "Non-GAAP Measures" in respect of the term "funds flow from
        operations" and "funds flows from operations per unit".
    (2) 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.
    (3) restated for changes in accounting policies and to reflect the
        consolidation of units effective November 2, 2005.



    TRUE ENERGY TRUST
    CONSOLIDATED BALANCE SHEETS
    As at December 31
    -------------------------------------------------------------------------
    ($000s)                                                 2007        2006
    -------------------------------------------------------------------------
    ASSETS
    Current assets
      Accounts receivable                             $   48,522  $   73,199
      Deposits and prepaid expenses                        6,096       7,928
      Capital taxes recoverable                              626           -
      Commodity contract asset (note 20)                   1,061           -
      Future income taxes (note 15)                        3,116
                                                      -----------------------
                                                          59,421      81,127
    Property, plant and equipment (note 6)               820,831     931,979
    Deferred financing charges (note 9)                        -       3,552
                                                      -----------------------
    Total assets                                      $  880,252  $1,016,658
                                                      -----------------------
                                                      -----------------------

    LIABILITIES
    Current liabilities
      Accounts payable and accrued liabilities        $   52,188  $  107,431
      Distribution payable to unitholders                  6,337       8,433
      Capital taxes payable                                    -       1,513
      Current portion of obligations under
       capital lease                                           -         111
      Commodity contract liability  (note 20)             11,404           -
                                                      -----------------------
                                                          69,929     117,488
    Long-term debt (note 8)                              168,475     157,904
    Convertible debentures (note 9)                       79,407      81,551
    Asset retirement obligations (note 10)                28,373      26,605
    Future income taxes (note 15)                         67,366     123,861
                                                      -----------------------
    Total liabilities                                    413,550     507,409
                                                      -----------------------

    NON-CONTROLLING INTEREST
      Exchangeable shares of subsidiary (note 11)          3,922       4,153

    UNITHOLDERS' EQUITY
      Unitholders' capital (note 12)                     925,573     876,904
      Equity component of convertible
       debentures (note 9)                                 5,119       5,119
      Contributed surplus (note 13)                       19,454      12,818
      Deficit                                           (487,366)   (389,745)
                                                      -----------------------
    Total unitholders' equity                            462,780     505,096
                                                      -----------------------
    Total liabilities and unitholders' equity         $  880,252  $1,016,658
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    COMMITMENTS (note 19)

    See accompanying notes to the consolidated financial statements.



    TRUE ENERGY TRUST
    CONSOLIDATED STATEMENTS OF INCOME  AND COMPREHENSIVE INCOME
    For the years ended December 31

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

    REVENUES
      Petroleum and natural gas sales                 $  258,490  $  220,913
      Royalties                                          (47,004)    (51,816)
      Gain (loss) on commodity contracts (note 20)        (3,852)      2,639
                                                      -----------------------
                                                         207,634     171,736

    EXPENSES
      Production                                          68,282      46,685
      Transportation                                       7,938       6,517
      General and administrative                          18,186      14,896
      Interest and financing charges                      18,108      10,665
      Unit-based compensation (notes 12 and 13)            2,001       6,597
      Depletion, depreciation and accretion              171,484     138,875
      Write-down of petroleum and natural
       gas properties (note 6)                                 -     110,000
      Goodwill impairment (note 7)                             -     169,768
      Special meeting costs (note 16)                      3,805           -
                                                      -----------------------
                                                         289,804     504,003

    LOSS BEFORE TAXES                                    (82,170)   (332,267)

    TAXES (note 15)
      Capital taxes                                        2,039       3,245
      Future income tax recovery                         (59,847)   (101,145)
                                                      -----------------------
                                                         (57,808)    (97,900)

    NET LOSS BEFORE NON-CONTROLLING INTEREST             (24,362)   (234,367)

      Non-controlling interest (note 11)                     (95)       (803)
                                                      -----------------------
                                                      -----------------------

    NET LOSS                                             (24,267)   (233,564)
                                                      -----------------------

    Net changes in cash flow hedges
     (net of tax of $1.8 million)                         (3,749)          -
                                                      -----------------------

    COMPREHENSIVE LOSS                                $  (28,016) $ (233,564)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Net loss per trust unit
      Basic                                           $    (0.32) $    (4.95)
      Diluted                                         $    (0.32) $    (4.95)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    See accompanying notes to the consolidated financial statements.



    TRUE ENERGY TRUST
    CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY
    For the years ended December 31

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

    UNITHOLDERS' CAPITAL
      Balance, beginning of year                      $  876,904  $  418,968
      Issued for cash (net of issue costs
       of $3.1 million)                                   54,375           -
      Issued to acquire Prairie Schooner (net of
       issue costs of $1.6 million)                            -     341,089
      Issued to acquire Shellbridge (net of issue
       costs of $0.6 million                                   -      67,669
      Units issued pursuant to DRIP                            -      42,608
      Issued to acquire property interest                      -       1,817
      Repurchased under normal course issuer bid          (5,842)          -
      Exchangeable shares converted                          136       4,753
                                                      -----------------------
      Balance, end of year                               925,573     876,904
                                                      -----------------------

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

    CONTRIBUTED SURPLUS
      Balance, beginning of year                          12,818       5,127
      Unit-based compensation expense (note 13)            4,249       7,691
      Reversal of prior year unit-based
       compensation expense for forfeitures of
       unvested incentive units                           (1,797)          -
      Adjustment for repurchase of units under
       normal course issuer bid                            4,184           -
                                                      -----------------------
      Balance, end of year                                19,454      12,818

    DEFICIT
      Balance, beginning of year                        (389,745)    (31,826)
      Net loss                                           (24,267)   (233,564)
      Impact of changes in accounting policy for
       financial instruments on January 1, 2007
       (net of tax of $0.05 million) (note 3)                 97           -
      Distributions declared                             (73,451)   (124,355)
                                                      -----------------------
      Balance, end of year                              (487,366)   (389,745)

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

    -------------------------------------------------------------------------
    TOTAL UNITHOLDERS' EQUITY                         $  462,780  $  505,096
    -------------------------------------------------------------------------

    See accompanying notes to the consolidated financial statements.



    TRUE ENERGY TRUST
    CONSOLIDATED STATEMENTS OF CASH FLOWS
    For the years ended December 31

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

    Cash provided by (used in):
    CASH FLOW FROM OPERATING ACTIVITIES
    Net loss                                          $  (24,267) $ (233,564)
    Items not involving cash:
      Non-controlling interest (note 11)                     (95)       (803)
      Depletion, depreciation and accretion              171,484     138,875
      Write-down of petroleum and natural
       gas properties (note 6)                                 -     110,000
      Goodwill impairment (note 7)                             -     169,768
      Unit-based compensation (notes 12 and 13)            2,001       6,597
      Unrealized loss (gain) on commodity
       contracts (note 20)                                10,343           -
      Amortization of deferred financing charges
       (note 9)                                                -         437
      Accretion on convertible debentures (note 9)         1,553         420
      Future income taxes (recovery) (note 15)           (59,847)   (101,145)
      Capital taxes                                            -        (194)
                                                     ------------------------
                                                         101,172      90,391
      Asset retirement costs incurred                       (835)       (516)
      Change in non-cash working capital (note 14)       (18,131)     36,925
                                                     ------------------------
                                                          82,206     126,800
    CASH FLOW FROM (USED IN) FINANCING ACTIVITIES
      Increase in bank debt                               11,591      19,166
      Obligations under capital lease                       (111)       (201)
      Issuance of convertible debentures                       -      86,250
      Deferred financing charges                               -      (3,989)
      Issue of trust units for cash                       57,523           -
      Unit issue costs                                    (3,148)     (2,410)
      Repurchase of trust units under normal
       course issuer bid                                  (1,658)          -
      Distributions declared (net of DRIP)               (73,451)    (81,747)
                                                     ------------------------
                                                          (9,254)     17,069
      Change in non-cash working capital (note 14)        (2,060)       (101)
                                                     ------------------------
                                                         (11,314)     16,968
    CASH FLOW FROM (USED IN) INVESTING ACTIVITIES
      Additions to property, plant and equipment         (88,902)   (116,012)
      Proceeds on sale of property, plant and
       equipment                                          31,808      24,514
      Corporate transaction costs                              -      (2,083)
                                                     ------------------------
                                                         (57,094)    (93,581)
      Change in non-cash working capital (note 14)       (13,798)    (55,405)
                                                     ------------------------
                                                         (70,892)   (148,986)

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

      Change in cash                                           -           -

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

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

    See accompanying notes to the consolidated financial statements.



    NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

    Years ended December 31, 2007 and 2006
    -------------------------------------------------------------------------

    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 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 10)
        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.

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

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

    2.  SIGNIFICANT ACCOUNTING POLICIES

        The consolidated financial statements of the Trust have been prepared
        by management in accordance with generally accepted accounting
        principles in Canada. The preparation of consolidated financial
        statements in conformity with generally accepted accounting
        principles requires management to make estimates and assumptions that
        affect the amounts reported in the consolidated financial statements
        and accompanying notes. Amounts recorded for depreciation, depletion
        and amortization, asset retirement costs and obligations and amounts
        used for ceiling test and impairment calculations are based on
        estimates of natural gas, and crude oil reserves and future costs
        required to develop those reserves. Actual results could differ from
        those estimates. The consolidated financial statements have, in
        management's opinion, been properly prepared using careful judgment
        and reasonable limits of materiality and within the framework of the
        significant policies summarized below.

        a. Principles of Consolidation

           The consolidated financial statements include the accounts of the
           Trust and its subsidiaries. Any reference to the "Trust"
           throughout these consolidated financial statements refers to the
           Trust and its subsidiaries. All inter-entity transactions have
           been eliminated.

        b. Revenue Recognition

           Revenues from the sale of petroleum and natural gas are recorded
           when title to the products transfers to the purchasers based on
           volumes delivered and contracted delivery points and prices.

        c. Joint Interests

           A significant portion of the Trust's exploration and development
           activities are conducted jointly with others and, accordingly, the
           financial statements reflect only the Trust's proportionate
           interest in such activities.

        d. Petroleum and Natural Gas Properties

           The Trust follows the full cost method of accounting for petroleum
           and natural gas operations whereby all costs related to the
           exploration and development of petroleum and natural gas reserves
           are capitalized. These costs include land acquisition costs,
           geological and geophysical expenses, the costs of drilling both
           productive and non-productive wells, directly related overhead and
           estimated abandonment costs. Proceeds from the disposal of
           properties are deducted from the full cost pool without
           recognition of a gain or loss unless such a sale would
           significantly alter the rate of depletion and depreciation.

        e. Depletion and Depreciation

           Depletion of petroleum and natural gas properties is provided
           using the unit-of-production method based on production volumes
           before royalties in relation to total estimated proved reserves as
           determined by independent engineers and calculated in accordance
           with National Instrument 51-101. Natural gas reserves and
           production are converted at the energy equivalent of six thousand
           cubic feet to one barrel of oil.

           Calculations for depletion and depreciation of production
           equipment are based on total capitalized costs plus estimated
           future development costs of proved undeveloped reserves less the
           estimated net realizable value of production equipment and
           facilities after the proved reserves are fully produced. The costs
           of acquiring and evaluating unproved properties are excluded from
           depletion calculations. These properties are assessed periodically
           to ascertain whether impairment has occurred. When the property is
           considered to be impaired, the cost of the property or the amount
           of the impairment is added to costs subject to depletion.

           Depreciation of office furniture and equipment is provided for on
           a 20% declining balance basis.

        f. Ceiling Test

           The Trust applies a two-stage ceiling test on the aggregate
           carrying value of its capitalized costs, which may be amortized
           against revenues of future periods. The first stage of this
           process is to ensure that such costs do not exceed the
           undiscounted future cash flows from production of proved reserves.
           Undiscounted future cash flows are calculated based on
           management's best estimate of forward indexed prices applied to
           estimated future production of proved reserves plus the carrying
           cost of undeveloped properties, less estimated future operating
           costs, royalties, future development costs and abandonment costs.
           When the carrying amount of a cost centre is not recoverable, the
           second stage of the process will determine the impairment whereby
           the cost centre would be written down to its fair value. The
           second stage requires the calculation of discounted future cash
           flows from proved plus probable reserves plus the carrying cost of
           undeveloped properties net of any impairment allowance. The fair
           value of proved and probable reserves is estimated using accepted
           present value techniques, which incorporate risks and other
           uncertainties when determining expected cash flows.

           The cost of undeveloped properties is excluded from the impairment
           test described above and subject to a separate impairment test.

        g. Goodwill

           Goodwill is recognized on acquisitions when the total purchase
           price exceeds the fair value of the net identifiable assets of the
           acquired company. The carrying value of goodwill is assessed for
           impairment annually at year-end, or more frequently if events
           occur that could result in an impairment. Impairment is verified
           by comparing the carrying amount of the goodwill for the reporting
           entity to the excess of the Trust's fair value of its publicly
           traded trust units over the related book value. If the fair value
           of the Trust's equity is less than the book value, impairment is
           measured by allocating the fair value of the Trust to its
           identifiable assets and liabilities at their fair values. The
           excess of this allocation represents the fair value of goodwill.
           The excess of the book value of goodwill over this implied fair
           value is then recognized through the statement of income as an
           impairment. Impairment is charged to income in the period in which
           it occurs. Goodwill is stated at cost less impairment and is not
           amortized.

        h. Asset Retirement Obligations

           The Trust recognizes a liability for the future retirement
           obligations associated with the Trust's property, plant, and
           equipment. The fair value of the asset retirement obligation is
           recorded on a discounted basis. This amount is also capitalized as
           part of the cost of the related asset and amortized to expense
           over its useful life. The liability accretes until the Trust
           settles the obligation.

        i. Unit-based Compensation Plan

           The Trust accounts for its Trust Unit Incentive Plan issued to
           employees and the Board of Directors using the fair value method.
           The fair value of each trust unit incentive is estimated on the
           date of the grant using the Black-Scholes options pricing model
           and charged to earnings over the vesting period with a
           corresponding increase to contributed surplus.

        j. Income Taxes

           Income taxes are recorded using the liability method of tax
           allocation. Future income tax assets and liabilities are
           determined based on "temporary differences" and are measured using
           the current, or substantively enacted, tax rates and laws expected
           to apply when these differences reverse. A valuation allowance is
           recorded against any future income tax assets if it is more likely
           than not that the asset will not be realized.

           The Trust is a taxable entity under the Income Tax Act (Canada)
           and is taxable only on income that is not distributed or
           distributable to the unitholders.

        k. Exchangeable Shares of Subsidiary

           The exchangeable shares can be traded privately, thereby allowing
           holders of the exchangeable shares to dispose of them without
           having to exchange them for trust units, and consequently, they
           must be classified as a non-controlling interest outside of
           Unitholders' Equity.

        l. Financial Instruments

           All financial instruments, including all derivatives, are
           recognized on the balance sheet initially at fair value.
           Subsequent measurement of all financial assets and liabilities
           except those held-for-trading and available for sale are measured
           at amortized cost determined using the effective interest rate
           method. Held-for-trading financial assets are measured at fair
           value with changes in fair value recognized in income. Available-
           for-sale financial assets are measured at fair value with changes
           in fair value recognized in comprehensive income and reclassified
           to income when derecognized or impaired.

           The Trust continues to utilize financial derivatives and non-
           financial derivatives, such as commodity sales contracts requiring
           physical delivery, to manage the price risk attributable to
           anticipated sale of petroleum and natural gas production. The
           Trust does not enter into derivative financial instruments for
           trading or speculative purposes.

           The Trust uses derivative financial instruments from time to time
           to hedge its exposure to commodity price and foreign exchange
           fluctuations. The derivative financial instruments are initiated
           within the guidelines of the Trust's risk management policy. This
           includes linking all derivatives to specific assets and
           liabilities on the balance sheet or to specific firm commitments
           or forecasted transactions.

           The Trust has elected to account for its commodity sales and
           purchase contracts, which were entered into and continue to be
           held for the purpose of receipt or delivery of non-financial items
           in accordance with its expected purchase, sale or usage
           requirements as executory contracts on an accrual basis rather
           than as derivatives.

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

        m. Basic and Diluted per Trust Unit Calculations

           Basic per trust unit amounts are calculated using the weighted
           average number of trust units outstanding during the period. The
           Trust uses the treasury stock method to determine the dilutive
           effect of trust incentive units. Under the treasury stock method,
           only "in the money" dilutive instruments impact the diluted
           calculations in computing diluted per unit amounts. The Trust uses
           the "if-converted" method to determine the dilutive effect of
           exchangeable shares and convertible debentures.

        n. Measurement Uncertainty

           The amounts recorded for depletion, depreciation and accretion
           expense, asset retirement obligations and amounts used in the
           impairment tests for goodwill and property, plant and equipment
           are based on estimates. These estimates include petroleum and
           natural gas reserves, future petroleum and natural gas prices,
           future interest rates and future costs required to develop those
           reserves as well as other fair value assumptions. By their nature,
           these estimates are subject to measurement uncertainty and the
           effect on the financial statements of changes in such estimates in
           future periods could be material.

        o. Financial Presentation and Disclosure

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

    3.  CHANGES IN ACCOUNTING POLICIES

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

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

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

        a. Financial instruments - recognition and measurement

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

        b. Derivatives

           The Trust continues to utilize financial derivatives and non-
           financial derivatives, such as commodity sales contracts requiring
           physical delivery, to manage the price risk attributable to
           anticipated sale of petroleum and natural gas production. Refer to
           note 20 to for additional disclosure on the Trust's risk
           management objectives and policies.

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

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

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

        c. Embedded derivatives

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

        d. Other comprehensive income

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

        e. Effective interest rate method

           Transaction costs attributable to financial instruments classified
           as other than held-for-trading are included in the recognized
           amount of the related financial instrument and recognized over the
           life of the resulting financial instrument. Prior to January 1,
           2007, transaction costs were recorded as deferred charges and
           recognized in net earnings on a straight-line basis over the life
           of the financial instrument. On adoption, transaction costs are
           recognized as if the effective interest rate method had always
           been applied whereby the amount recognized varies over the life of
           the financial instrument based on principal outstanding. For the
           Trust, this adoption required adjustments to prepaid expenses and
           long-term debt as disclosed in note 8 and to deferred financing
           costs and the debt component of convertible debentures as
           disclosed in note 9.

    4.  FUTURE CHANGES IN ACCOUNTING POLICIES

        a. Capital disclosures

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

        b. Financial instruments

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

    5.  ACQUISITIONS

        a. Acquisition of Prairie Schooner Petroleum Ltd.

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

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

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

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

        b. Acquisition of Shellbridge Oil & Gas, Inc.

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

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

           The purchase price equation is as follows:

           ($000's)
           ------------------------------------------------------------------
           Cost of acquisition:
             Trust units issued                                     $ 68,299
             True transaction costs                                      520
           ------------------------------------------------------------------
                                                                    $ 68,819
           ------------------------------------------------------------------

           Allocated at estimated fair values:
             Cash                                                    $ 5,218
             Accounts receivable                                      10,005
             Deposits and prepaid expenses                               161
             Property, plant and equipment                            47,529
             Goodwill                                                 24,017
             Accounts payable and accrued liabilities                (13,485)
             Future income taxes                                      (3,330)
             Asset retirement obligations                             (1,296)
           ------------------------------------------------------------------
                                                                    $ 68,819
           ------------------------------------------------------------------
           ------------------------------------------------------------------

     6. PROPERTY, PLANT AND EQUIPMENT

        ($000s)
        ---------------------------------------------------------------------
                                                     Accumulated
                                                       depletion
                                                             and    Net book
        December 31, 2007                     Cost  depreciation       value
        ---------------------------------------------------------------------
        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
        ---------------------------------------------------------------------

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

        The Trust has included $56.6 million (2006 - $63.0 million) for
        future development costs and excluded $nil million (2006 -
        $99.2 million) for undeveloped properties, $37.8 million (2006 -
        $49.3 million) for undeveloped land and $47.6 million (2006 -
        $49.9 million) for estimated salvage from the depletion calculation
        during the year ended December 31, 2007.

        For the year ended December 31, 2007, the Trust capitalized
        $3.9 million (2006 - $2.6 million) of general and administrative
        expenses and $0.7 million (2006 - $1.1 million), including the future
        tax effect thereon of $0.2 million, of unit-based compensation
        expense directly related to exploration and development activities.

        The Trust performed a ceiling test calculation at December 31, 2007
        resulting in undiscounted cash flows from proved reserves plus the
        carrying cost less impairment allowance of unproved properties not
        exceeding the carrying value of oil and gas assets. Consequently,
        True performed stage two of the ceiling test assessing whether
        discounted future cash flows from the production of proved plus
        probable reserves plus the carrying cost less impairment allowance of
        unproved properties exceeded the carrying value of its petroleum and
        natural gas properties. No impairment in oil and gas assets was
        identified for 2007.

        In 2006, as a result of performing this test, a ceiling test
        impairment loss of $110.0 million was recorded as a write-down of
        petroleum and natural gas properties in the consolidated statements
        of operations and was included in accumulated depletion.

        The prices used in the ceiling test evaluation of the Trust's crude
        oil and natural gas reserves at December 31, 2007 were based on the
        following benchmark price forecasts adjusted for quality and
        transportation differentials:

        ---------------------------------------------------------------------
                        Hardisty Heavy      Edmonton Light      AECO Natural
        Year                 Crude Oil     Sweet Crude Oil               Gas
                                ($/bbl)             ($/bbl)         ($/mmbtu)
        ---------------------------------------------------------------------
        2008                  $  54.66            $  89.42           $  6.48
        2009                     52.41               85.78              7.18
        2010                     50.42               82.82              7.35
        2011                     49.02               80.29              7.35
        2012                     48.68               79.74              7.36
        2013                     48.87               79.52              7.48
        2014                     49.86               80.56              7.67
        2015                     50.89               81.65              7.87
        2016                     51.93               82.72              8.07
        2017                     52.98               84.41              8.27
        2018                     54.03               86.09              8.45
        2019                     55.10               87.81              8.64
        Percentage
         increase each
         year after 2019          2.0%                2.0%              2.0%
        ---------------------------------------------------------------------

        On December 17, 2007, the Trust announced its intention to divest of
        its Saskatchewan portfolio of assets as part of a new strategic
        direction for the Trust. Scotia Waterous Inc. has been selected to
        act as True's exclusive advisor in this process. Bids were received
        on March 4, 2008 and are subject to review and acceptance by the
        Trust.

    7.  GOODWILL

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

        ($000s)                                             2007        2006
        ---------------------------------------------------------------------
        Balance, beginning of year                      $      -    $ 71,970
        Prairie Schooner acquisition (note 3a)                 -      71,601
        Shellbridge acquisition (note 3b)                      -      24,017
        TKE acquisition (note 3c)                              -       2,180
        Goodwill impairment recognized                         -    (169,768)
        ---------------------------------------------------------------------
        Balance, end of year                            $      -    $      -
        ---------------------------------------------------------------------

        The Trust reviewed the valuation of goodwill as of December 31, 2006
        based upon the latest available data. Based upon this review, an
        impairment of goodwill of $169.8 million was recorded as a non-cash
        charge to income as of December 31, 2006.

    8.  LONG-TERM DEBT

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

        As a consequence of adopting new financial instruments standards
        effective January 1, 2007 as described in note 3, the Trust has made
        certain adjustments to the presentation of prepaid interest.
        Previously, this amount was included in deposits and prepaid
        expenses, however, under the new standard effective January 1, 2007
        this amount, being $1.0 million at December 31, 2007, is now netted
        against long-term debt and amortized on the effective interest basis.

        As at December 31, 2007, there was $10.5 million outstanding under
        the operating facility and $158 million outstanding under the
        revolving term credit facility. As at December 31, 2007, there is
        approximately $21.5 million not drawn under the facility.

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

        The revolving period on the new revolving term credit facility ends
        on June 28, 2008, unless extended for a further 364 day period.
        Should the facilities not be renewed they convert to 366 day non-
        revolving term facilities on the renewal date. Payment will not be
        required under the revolving term facility for more than 365 days
        from the balance sheet date and as at December 31, 2007 there is
        sufficient availability under the revolving term credit facility to
        also cover the operating facility and, as such, the entire credit
        facility has been classified as long-term.

    9.  CONVERTIBLE DEBENTURES

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

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

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

        The following table shows the convertible debenture activities for
        the years ended December 31, 2007 and 2006:

        Convertible debentures
        ---------------------------------------------------------------------
                                                            Debt      Equity
                                           Number of   Component   Component
                                          Debentures      ($000s)     ($000s)
        ---------------------------------------------------------------------
        Issued on June 15, 2006               86,250    $ 81,131     $ 5,119
        Accretion                                  -         420           -
        ---------------------------------------------------------------------
        Balance, December 31, 2006            86,250      81,551       5,119
        ---------------------------------------------------------------------
        Impact of change in accounting
         policy for financial instruments
         on January 1, 2007 (note 3)               -      (3,697)          -
        Accretion                                  -       1,553           -
        ---------------------------------------------------------------------
        Balance, December 31, 2007            86,250    $ 79,407     $ 5,119
        ---------------------------------------------------------------------

        The following table shows the deferred financing charges activities
        for the years ended December 31, 2007 and 2006:

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

    10. 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 $75.2 million which will be
        incurred between 2008 and 2053. A credit-adjusted risk-free rate of
        8 percent and an inflation rate of 2 percent were used to calculate
        the fair value of the asset retirement obligation.

        ---------------------------------------------------------------------
        ($000s)                                             2007         2006
        ---------------------------------------------------------------------
        Asset retirement obligation, beginning
         of year                                        $ 26,605    $ 10,457
        Liabilities acquired through corporate
         acquisitions                                          -      13,704
        Liabilities incurred on development
         activities                                          433       1,210
        Changes in prior period estimates                    960       1,326
        Liabilities released on dispositions                (927)       (641)
        Liabilities settled during the year                 (835)       (516)
        Accretion expense                                  2,137       1,065
        ---------------------------------------------------------------------
        Asset retirement obligation, end of year        $ 28,373    $ 26,605
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    11. EXCHANGEABLE SHARES OF SUBSIDIARY/NON-CONTROLLING INTEREST

        Authorized:
           Unlimited number of exchangeable shares, issuable in series of
           which the first series in an unlimited number is designated for
           Series A exchangeable shares

    -------------------------------------------------------------------------
                                       2007                    2006
                                              Amount                  Amount
                                  Number      ($000s)     Number      ($000s)
    -------------------------------------------------------------------------
    Balance, beginning of year   403,536     $ 4,153     788,558     $ 9,709
    Non-controlling interest
     expense (recovery)                -         (95)          -        (803)
    Exchanged for trust units    (13,260)       (136)   (385,022)     (4,753)
    -------------------------------------------------------------------------
    Balance, end of year         390,276     $ 3,922     403,536     $ 4,153
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

        The Series A exchangeable shares are non-voting (but holders are
        entitled to equivalent voting rights in the Trust) and can be
        converted, at the option of the holder into trust units at any time.
        If the number of exchangeable shares outstanding is less than
        180,000, the Trust can elect to redeem the exchangeable shares for
        trust units or an amount in cash equal to the amount determined by
        multiplying the exchangeable ratio on the last business day prior to
        the redemption date by the current market price of a trust unit on
        the last business day prior to such redemption date. The number of
        trust units issued upon conversion is based on the exchange ratio in
        effect on the date of conversion. The exchange ratio is calculated
        monthly based on the five day weighted average trust unit trading
        price preceding the monthly effective date. The exchangeable shares
        are not eligible for cash distributions; however cash distributions
        will increase the exchange ratio.

        As at December 31, 2007, the exchange ratio was 0.8604 (2006 -
        0.71107).

        Retraction of Exchangeable Shares

        Exchangeable shares may be redeemed at any time by delivering the
        share certificates to the Trustee, together with a properly completed
        retraction request. The retraction price will be satisfied with trust
        units equal to the amount determined by multiplying the exchange
        ratio on the last business day prior to the retraction date by the
        number of exchangeable shares redeemed.

        Redemption of Exchangeable Shares

        On January 15, 2010, the exchangeable shares will be redeemed by the
        Trust unless the Board of Directors of True Energy Inc. elects to
        extend the redemption period. The exchangeable shares generally will
        be redeemed issuing units for an amount equivalent to the value of
        the exchangeable shares at the current exchange ratio.

    12. UNITHOLDERS' CAPITAL

        a. Trust Units

           The Trust Indenture provides that an unlimited number of trust
           units may be authorized and issued. Each trust unit is
           transferable, carries the right to one vote and represents an
           equal undivided beneficial interest in any distributions from the
           Trust and in the net assets of the Trust in the event of
           termination or winding-up of the Trust. All trust units are of the
           same class with equal rights and privileges. Trust units are
           redeemable at any time at the lesser of 90% of the market price
           (as determined in accordance with the Trust Indenture) and the
           closing price of the trust units on the date tendered for
           redemption to a maximum, unless waived, of $250,000 per calendar
           month in which case the redemption price is payable by
           distributing notes of the Trust's subsidiary or notes of the
           Trust.

    -------------------------------------------------------------------------
                                       2007                    2006
                                              Amount                  Amount
                                  Number      ($000s)     Number      ($000s)
    -------------------------------------------------------------------------
    Balance, beginning
     of year                  70,275,703   $ 876,904  36,176,196   $ 418,968
    Issued for cash (net of
     issue costs of
     $3.1 million)             9,430,000      54,375           -           -
    Issued to acquire Prairie
     Schooner (net of issue
     costs of $1.8 million)            -           -  25,759,563     341,089
    Issued to acquire
     Shellbridge (net of issue
     costs of $0.6 million)            -           -   4,389,366      67,669
    Units issued pursuant to DRIP      -           -   3,574,185      42,608
    Issued to acquire
     property interest                 -           -     145,358       1,817
    Repurchased under normal
     course issuer bid          (500,000)     (5,842)          -           -
    Exchangeable shares
     converted                    10,343         136     231,035       4,753
    -------------------------------------------------------------------------
    Balance, end of year      79,216,046   $ 925,573  70,275,703   $ 876,904
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

           In August 2007, the Trust announced approval of its normal course
           issuer bid ("NCIB") program to repurchase up to 7.8 million of its
           outstanding trust units during the period August 28, 2007 through
           to August 27, 2008, subject to certain conditions. Starting in the
           fourth quarter and through the end of 2007, 500,000 units were
           repurchased at a total price of $1.7 million. The excess of the
           carrying amount of the units purchased over the purchase price of
           $4.2 million was recorded as an increase to contributed surplus.

        b. Trust Unit Incentive Plan

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

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

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

           The following tables summarize information regarding trust unit
           incentive rights for the years ended December 31, 2007 and 2006.

           Unit Rights Continuity
                                                Weighted Average
                                                Exercise Price(a)     Number
           ------------------------------------------------------------------
           Balance, December 31, 2005                    $ 17.94   3,159,000
           Granted                                       $ 12.67   3,022,500
           Forfeited                                     $ 14.66    (751,669)
           ------------------------------------------------------------------
           Balance, December 31, 2006                    $ 14.18   5,429,831
           Granted                                       $  5.06   3,181,500
           Forfeited                                     $ 12.50  (2,679,334)
           ------------------------------------------------------------------
           Balance, December 31, 2007                    $  9.18   5,931,997
           ------------------------------------------------------------------



    Unit Rights Outstanding, December 31, 2007
    -------------------------------------------------------------------------
                                              Outstanding
                                                       Weighted
                                                        Average     Weighted
                                                       Exercise      Average
    Exercise            Exercise Price          At    Price Net    Remaining
    Price Before                Net of     Dec. 31,    of Price  Contractual
    Price Reductions        Reductions        2007   Reductions         Life
    -------------------------------------------------------------------------
    $ 2.92 - $ 6.70    $ 2.92 - $ 6.13   2,745,000      $  4.56          4.6
    $10.58 - $12.53    $ 9.27 - $11.12     914,998      $  9.56          3.8
    $13.74 - $14.83    $11.75 - $12.92     527,166      $ 12.11          3.5
    $15.92 - $16.70    $13.37 - $14.28      92,500      $ 13.74          3.3
    $18.25 - $20.98    $15.27 - $18.22   1,652,333      $ 15.46          2.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    $ 2.92 - $20.98    $ 2.92 - $18.22   5,931,997      $  9.18          3.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    ------------------------------------------
                             Exercisable

                                     Exercise
    Exercise                  At    Price Net
    Price Before         Dec. 31,    of Price
    Price Reductions        2007   Reductions
    ------------------------------------------
    $ 2.92 - $ 6.70            -          N/A
    $10.58 - $12.53      361,648      $  9.54
    $13.74 - $14.83      213,497      $ 12.17
    $15.92 - $16.70       48,334      $ 13.80
    $18.25 - $20.98    1,620,665      $ 15.41
    ------------------------------------------
    ------------------------------------------
    $ 2.92 - $20.98    2,244,144      $ 14.12
    ------------------------------------------
    ------------------------------------------



    Unit Rights Outstanding, December 31, 2006
    -------------------------------------------------------------------------
                                              Outstanding
                                                       Weighted
                                                        Average     Weighted
                                                       Exercise      Average
    Exercise            Exercise Price          At    Price Net    Remaining
    Price Before                Net of     Dec. 31,    of Price  Contractual
    Price Reductions        Reductions        2006   Reductions         Life
    -------------------------------------------------------------------------
    $10.58 - $12.53    $10.15 - $12.00   1,539,000      $ 10.40          4.7
    $13.74 - $14.83    $12.63 - $13.80     681,000      $ 13.05          4.5
    $15.92 - $16.70    $14.41 - $15.16     227,500      $ 14.61          4.3
    $18.25 - $20.98    $16.15 - $19.10   2,982,331      $ 16.36          3.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    $10.58 - $20.98    $10.30 - $19.10   5,429,831      $ 14.18          4.2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    ------------------------------------------
                             Exercisable

                                     Exercise
    Exercise                  At    Price Net
    Price Before         Dec. 31,    of Price
    Price Reductions        2006   Reductions
    ------------------------------------------
    $10.58 - $12.53            -          N/A
    $13.74 - $14.83            -          N/A
    $15.92 - $16.70       29,166        14.93
    $18.25 - $20.98    1,919,888        16.27
    ------------------------------------------
    ------------------------------------------
    $10.58 - $20.98    1,949,054        16.25
    ------------------------------------------
    ------------------------------------------

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

        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 year ended
           December 31, 2007, the Trust matched $0.5 million (2006 -
           $0.1 million) under the plan.

    13. CONTRIBUTED SURPLUS

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

        ($000s)                                             2007        2006
        ---------------------------------------------------------------------
        Balance, beginning of year                      $ 12,818    $  5,127
        Unit-based compensation expense                    4,249       7,691
        Reversal of prior year unit-based compensation
         expense for forfeitures of unvested
         incentive units                                  (1,797)          -
        Adjustment for repurchase of units
         under NCIB (note 12)                              4,184           -
        ---------------------------------------------------------------------
        Balance, end of year                            $ 19,454    $ 12,818
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Unit-based Compensation Expense

        During the year ended December 31, 2007, the Trust granted 3,181,500
        (2006 - 3,022,500) unit incentive rights to employees and directors.
        During the year ended December 31, 2007, the Trust recorded unit-
        based compensation of $4.2 million, of which $0.5 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 years ended December 31, 2007 and 2006 and the assumptions
        used in their determination are as noted below.

        ---------------------------------------------------------------------
                                                            2007        2006
        ---------------------------------------------------------------------
        Assumptions:
          Risk free interest rate (%)                          4           4
          Expected life (years)                                5           5
          Expected volatility (%)                          24-26          24
        ---------------------------------------------------------------------
        Results:
          Weighted average fair value of each
           incentive right granted                        $ 1.85      $ 4.27
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    14. SUPPLEMENTAL CASH FLOW INFORMATION

        Cash Interest and Taxes Paid
        ---------------------------------------------------------------------

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

        Cash paid:
          Interest                                     $  16,566   $  10,598
          Taxes (net of refunds)                       $   4,378   $   4,476

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



        Change in Non-cash Working Capital
        ---------------------------------------------------------------------

        ($000s)                                             2007        2006
        ---------------------------------------------------------------------
        Changes in non-cash working capital items:
          Accounts receivable                          $  24,677   $  25,633
          Deposits and prepaid expenses                      812      (4,887)
          Accounts payable and accrued liabilities       (55,243)    (37,449)
          Capital taxes recoverable/payable               (2,139)     (1,634)
          Distribution payable to unitholders             (2,096)       (244)
        ---------------------------------------------------------------------
                                                       $ (33,989)  $ (18,581)
        ---------------------------------------------------------------------

          Changes related to operating activities      $ (18,131)  $  36,925
          Changes related to financing activities         (2,060)       (101)
          Changes related to investing activities        (13,798)    (55,405)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
                                                       $ (33,989)  $ (18,581)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    15. INCOME TAXES

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

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

        As a result of the SIFT tax enactment, the Trust recorded a future
        income tax recovery of $1.2 million to reflect current temporary
        differences between the book and tax basis of assets and liabilities
        expected to be remaining in the Trust in 2011. In accordance with
        generally accepted accounting principles, prior to the enactment, the
        Trust's temporary differences were not recorded as future income
        taxes. As at December 31, 2007, the total "temporary difference" (tax
        basis exceeds accounting basis) in the Trust is $8.1 million. As at
        December 31, 2007, the Trust's subsidiaries have a tax basis of
        approximately $510 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
        $21 million of tax basis.

        The provision for income taxes differs from the expected amount
        calculated by applying the combined Federal and Provincial corporate
        income tax rate of 32.98% (2006: 35.63%) to earnings before income
        taxes. This difference results from the following items:

        ---------------------------------------------------------------------
                                                     Years ended December 31,
        ($000s)                                             2007        2006
        ---------------------------------------------------------------------
        Expected income tax expense (recovery)         $ (27,099) $ (118,645)
        Distributions deducted for tax purposes          (22,857)    (33,757)
        Goodwill impairment                                    -      60,620
        Impact of SIFT legislation                        (1,165)          -
        Crown royalties and charges                            -       5,032
        Resource allowance                                     -      (4,292)
        Unit based compensation expense                      660       2,356
        Change in enacted tax rates                       (9,444)    (11,548)
        Other                                                 58        (911)
        ---------------------------------------------------------------------
        Future income tax expense (recovery)           $ (59,847) $ (101,145)
        ---------------------------------------------------------------------

        The components of the net future income tax liability at December 31
        are as follows:

        ---------------------------------------------------------------------
        ($000s)                                             2007        2006
        ---------------------------------------------------------------------
        Future income tax liabilities:
          Petroleum and natural gas properties         $ (87,564) $ (120,203)
          Partnership deferrals                                -     (16,374)
          Other                                             (565)       (565)
        Future income tax assets:
          Future site restoration/asset
           retirement obligation                           7,682       7,899
          Share issue costs                                1,345       2,207
          Non-capital losses                              10,502       1,856
          Attributed Canadian Royalty Income               1,209       1,209
          Commodity contract asset/liability               3,116           -
          Other                                               25         110
        ---------------------------------------------------------------------
        Net future income tax liability                $ (64,250) $ (123,861)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    16. 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 year ended December 31, 2007.

    17. PER TRUST UNIT AMOUNTS

        ---------------------------------------------------------------------
                                                     Years ended December 31,
                                                            2007        2006
        ---------------------------------------------------------------------
        Basic trust units outstanding                 79,216,046  70,275,703
        Dilutive effect of:
          Trust unit incentive rights outstanding      5,931,997   5,429,831
          Units issuable for exchangeable shares         335,793     286,942
          Units issuable for convertible debentures    5,390,625   5,390,625
        ---------------------------------------------------------------------
        Diluted trust units outstanding               90,874,461  81,383,101
        ---------------------------------------------------------------------
        Weighted average trust units outstanding      75,792,488  47,217,258
        Dilutive effect of exchangeable shares,
         trust unit incentive plan
         and convertible debentures(1)                         -           -
        ---------------------------------------------------------------------
        Diluted weighted average trust
         units outstanding                            75,792,488  47,217,258
        ---------------------------------------------------------------------

        (1) A total of 335,793 (2006: 286,942) exchangeable shares, 5,931,997
            (2006: 5,429,831) trust incentive units and 5,390,625 (2006:
            5,390,625) trust units issuable pursuant to the conversion of
            convertible debentures were excluded from the calculation for the
            year ended December 31, 2007 as they were not dilutive.

    18. RELATED PARTY TRANSACTIONS

        During the year ended December 31, 2007, the Trust paid $1.2 million
        (2006: $1.2 million) for legal services provided by a firm in which a
        current director and corporate secretary is a partner. These payments
        were made in the normal course of operations, on commercial terms,
        and therefore were recorded at the exchange amount.

    19. COMMITMENTS

        As at December 31, 2007, 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.

        The Trust has further committed to various corporate sponsorships
        extending to June 2011 at an estimated combined cost of up to
        $332,000.

        The Trust is committed to payments under operating leases for office
        space as follows:

        ---------------------------------------------------------------------
        ($000s)                                Gross    Expected
        Year                                  Amount  Recoveries  Net amount
        ---------------------------------------------------------------------
        2008                                 $ 1,685       $ 297     $ 1,388
        2009                                   1,893         297       1,596
        2010                                   2,118         297       1,821
        2011                                   2,161           -       2,161
        2012                                   2,190           -       2,190
        ---------------------------------------------------------------------

    20. FINANCIAL INSTRUMENTS

        a. Credit Risk

           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.

        b. Fair Value of Financial Instruments

           At December 31, 2007, the following table provides the carrying
           amount and fair value of the Company's financial instruments:

           ------------------------------------------------------------------
           ($000s)                               Carrying amount  Fair value
           ------------------------------------------------------------------
           Commodity contract asset                      $ 1,061     $ 1,061
           Commodity contract liability                   11,404      11,404
           Long-term debt                                168,475     168,475
           Convertible debentures
           Debt component                     79,407
           Equity component                    5,119
                                         ------------------------
                                                          84,526      79,350
           ------------------------------------------------------------------

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

           The Trust's derivatives are exchange traded or transacted in an
           over-the-counter market. Where available, valuation is determined
           by reference to readily available public data. The carrying value
           of long-term debt approximates fair value due to the cost of
           borrowing being at a floating rate. The fair value of convertible
           debentures is based upon the closing market trading price as at
           December 31, 2007.

        c. Interest Rate Risk

           The Trust is exposed to interest rate risk to the extent that
           changes in market interest rates will impact True's bank debt that
           has a floating interest rate. The trust's convertible debentures
           have a fixed coupon interest rate of 7.5%. The Trust had no
           interest rate swaps or hedges at December 31, 2007.

        d. Commodity Risk

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

           As 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    Oct. 1, 2007 to
                   March 31, 2008   2,000 bbl/d  $ 65.00 US  $ 75.00 US   WTI
    Oil collar   April 1, 2008 to
                  Dec. 31, 2008     1,000 bbl/d  $ 65.00 US  $ 82.00 US   WTI
    Oil collar   April 1, 2008 to
                  Dec. 31, 2008     1,000 bbl/d  $ 65.00 US  $ 82.00 US   WTI
    Natural Gas   Nov. 1, 2007 to
     collar        March 31, 2008  5,000 GJ/day  $ 8.00 CDN  $ 9.05 CDN  AECO
    Natural Gas   Jan. 1, 2008 to
     fixed         Dec. 31, 2008   5,000 GJ/day  $ 6.65 CDN  $ 6.65 CDN  AECO
    Natural Gas   Jan. 1, 2008 to
     fixed         Dec. 31, 2008  10,551 GJ/day  $ 6.65 CDN  $ 6.65 CDN  AECO
    -------------------------------------------------------------------------

           Subsequent to December 31, 2007, the Trust has entered into
           additional commodity price risk management arrangements as
           follows:

    -------------------------------------------------------------------------
                                                      Price      Price
    Type                   Period        Volume       Floor    Ceiling  Index
    -------------------------------------------------------------------------
    Natural Gas  April 1, 2008 to
     fixed        Oct. 31, 2008    5,275 GJ/day  $ 6.64 CDN  $ 6.64 CDN  AECO
    Natural Gas  April 1, 2008 to
     fixed        Oct. 31, 2008    3,500 GJ/day  $ 6.90 CDN  $ 6.90 CDN  AECO
    Natural Gas   Nov. 1, 2008 to
     fixed         Dec. 31, 2008   3,500 GJ/day  $ 7.58 CDN  $ 7.58 CDN  AECO
    Natural Gas   Nov. 1, 2008 to
     fixed         March 31, 2009  5,275 GJ/day  $ 7.61 CDN  $ 7.61 CDN  AECO
    Natural Gas   Jan. 1, 2009 to
     fixed         March 31, 2009  5,275 GJ/day  $ 7.86 CDN  $ 7.86 CDN  AECO
    Natural Gas  April 1, 2009 to
     fixed       June 30, 2009     5,275 GJ/day  $ 7.01 CDN  $ 7.01 CDN  AECO
    Natural Gas  April 1, 2009 to
     fixed       June 30, 2009     5,275 GJ/day $ 7.015 CDN $ 7.015 CDN  AECO
    -------------------------------------------------------------------------

           For the year ended December 31, 2007, the gain (loss) on commodity
           contracts was comprised of the following:

        ---------------------------------------------------------------------
        ($000s)              Activity in  Adjustments
                              the period     for new        2007        2006
                                          standards(1)     Total       Total
        ---------------------------------------------------------------------
        Gain (loss) on
         commodity contracts
          Realized(2)           $  9,801    $ (3,310)   $  6,491     $ 2,639
          Unrealized(3)          (19,248)      8,905     (10,343)          -
        ---------------------------------------------------------------------
                                $ (9,447)   $  5,595    $ (3,852)    $ 2,639
        ---------------------------------------------------------------------

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

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

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

    ADDITIONAL INFORMATION

    Oil and Gas Working Interest(1) Gross Reserves
    -------------------------------------------------------------------------

    Reconciliation of Proved Reserves (2)
    -------------------------------------------------------------------------
                                         Crude oil &     Natural  Equivalent
                                                 NGL         gas       units
                                               (mbbl)      (mmcf)      (mboe)
    -------------------------------------------------------------------------
    December 31, 2006                         11,745     116,038      31,085
    Revision of previous estimates               594       7,881       1,907
    Discoveries, extensions, infill
     drilling and improved recovery            1,061       6,419       2,131
    Dispositions, net of acquisitions           (684)     (5,964)     (1,678)
    Production                                (1,938)    (23,526)     (5,858)
    -------------------------------------------------------------------------
    December 31, 2007                         10,778     100,848      27,587
    -------------------------------------------------------------------------

    Proved plus probable reserves
    December 31, 2007                         18,862     159,264      45,405
    December 31, 2006                         18,553     180,670      48,665
    -------------------------------------------------------------------------

    (1) "Working interest" refers to the Trust's working interest (operated
        or non-operated) share before deduction of royalties and without
        including any royalty interests of the Trust. Also referred to as
        Company Gross under NP 51- 101.

    (2) Forecast prices before royalties.
    

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

    %SEDAR: 00021401E




For further information:

For further information: Wayne M. Chorney, P.Eng., President, CEO & COO,
(403) 750-2420 or Edward J. Brown, CA, Vice President, Finance & CFO, (403)
750-2655 or Sacha Ravelli, Manager, Investor Relations, (403) 750-7085 or
Scott Koyich, Investor Relations, (403) 750-2428 or Troy Winsor, US Investor
Relations, (800) 663-8072; True Energy Trust, 2300, 530 - 8th Avenue SW,
Calgary, Alberta, Canada, T2P 3S8, Phone: (403) 266-8670, Fax: (403) 264-8163,
www.trueenergytrust.com


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