True Energy Trust announces 2006 year end financial results



    TSX: TUI.UN

    CALGARY, March 1 /CNW/ - (TSX: TUI.UN) True Energy Trust ("True" or the
"Trust") is pleased to announce its financial and operating results for the
year ended December 31, 2006. Highlights from the fourth quarter and year
ended December 31, 2006 include:

    
    -   True generated record average sales volumes for the year of
        13,861 boe per day, a 60% increase from 8,672 boe per day in 2005.
        Average sales volumes for the fourth quarter of 2006 were 19,747 boe
        per day, compared to 13,248 boe per day in the third quarter of 2006.

    -   Cash flow from operations(*) for 2006 was $90.4 million on gross
        sales of $220.9 million compared to cash flow from operations(*) of
        $87.1 million on gross sales of $161.7 million in 2005. For the
        fourth quarter of 2006, cash flow from operations(*) was
        $31.8 million compared to $32.9 million for the same period in 2005.
        The increase in cash flow for the 2006 year was the result of higher
        production volumes offset by lower natural gas prices. True's
        realized natural gas prices in 2006 averaged $6.75/mcf compared to
        $9.41/mcf in 2005.

    -   Total capital expenditures for 2006, excluding corporate and property
        acquisitions and dispositions, were $99.2 million compared to
        $115.5 million in 2005. This decrease reflects the adjustment of
        capital expenditures while operating as a trust.

    -   Shellbridge Oil & Gas, Inc. and Prairie Schooner Petroleum Ltd. were
        acquired for an aggregate of $413 million in 2006. Late in the third
        quarter of 2006, True completed the purchase of a steam assisted
        gravity drainage ("SAGD") facility at Kerrobert, Saskatchewan. First
        phase implementation of the SAGD project on the Kerrobert field will
        occur during the first to third quarters of 2007 and is expected to
        provide a material production impact late in 2007 and significantly
        enhance ultimate recovery of reserves.

    -   True had a very active drilling and development program in 2006,
        drilling 98 (61.5 net) working interest wells with a 98% success
        rate. In the fourth quarter of 2006, True drilled 21 (10.1 net)
        working interest wells with a 95% success rate.

    -   True put in place a new $225 million banking facility effective
        October 2, 2006. As at December 31, 2006, there was approximately
        $67 million available under this facility.

    -   True has currently hedged approximately 33% of current natural gas
        production for the first quarter of 2007 and approximately 31% is
        hedged through to October 31, 2007.

    -   As at December 31, 2006, True had total tax pools of approximately
        $498 million comprised of $478 million tax pools in True's
        subsidiaries that are available to shelter future taxable income and
        $20 million of tax pools of the Trust as at December 31, 2006. True's
        exploration and development activities will continue to add to these
        available tax pools in 2007.

    -   Net loss for 2006 was $233.6 million compared to net earnings of
        $13.9 million in 2005. This primarily reflects fourth quarter 2006
        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.

    -   True maintains a large undeveloped land base of 1.1 million
        (0.7 million net) acres.

    -   The Trust replaced 4.6 times its production through capital
        development program and acquisition activities.

    -   At December 31, 2006, True's proved plus probable reserves stood at
        48.7 mmboe, compared to 30.2 mmboe at December 31, 2005. The Trust's
        reserve life index on fourth quarter 2006 annualized production is
        6.8 years.
    

    On January 15, 2007, the Trust announced its intention to convert to a
growth oriented, dividend paying intermediate exploration and production
company (the "Reorganization"), pursuant to which holders of trust units of
the Trust would receive an equal number of common shares from the newly formed
corporation which will hold the assets previously held directly or indirectly
by the Trust. The exchangeable shares will also be exchanged for common shares
of the newly formed corporation based on the conversion ratio thereof. An
Information Circular and Proxy Statement in connection with the Annual and
Special Meeting will be mailed to securityholders on or about March 5, 2007,
in advance of the March 30, 2007 meeting date. The Reorganization will be
subject to all required regulatory approvals and securityholder approval by at
least 66 2/3% of the votes cast by securityholders of the Trust and holders of
the exchangeable shares.

    
    (*) Refer to note (1) in the highlights section of the financial report
        in respect of the term "cash flow from operations".

    True's 2006 financial report is presented below.


    HIGHLIGHTS
    -------------------------------------------------------------------------
                                                     Years ended December 31
                                                           2006         2005
    -------------------------------------------------------------------------
    FINANCIAL
    (CDN$000s except unit and per unit amounts)
    Revenue (before royalties and hedging)              220,913      161,670
    Cash flow from operations(1)                         90,391       87,137
      Per basic trust unit                                $1.91        $3.53
      Per diluted trust unit(2)                           $1.87        $3.47
    Net earnings (loss)                                (233,564)      13,890
      Per basic trust unit                               $(4.95)       $0.56
      Per diluted trust unit(2)                          $(4.95)       $0.55
    Distributions paid                                  124,355       17,361
      Per unit                                            $2.64        $0.48
    Payout ratio before DRIP(3)(4)                          98%          16%
    Payout ratio after DRIP(3)(4)                           64%          16%
    -------------------------------------------------------------------------
    Exploration and development                          99,206      115,481
    Corporate and property acquisitions                  17,322          490
    -------------------------------------------------------------------------
    Capital expenditures - cash                         116,528      115,971
    Property dispositions - cash                        (24,514)           -
    Corporate acquisitions and other - non-cash         487,698      448,982
    -------------------------------------------------------------------------
    Total capital expenditures - net                    579,712      564,953
    -------------------------------------------------------------------------
    Long-term debt                                      157,904            -
    Convertible debentures                               81,551            -
    Bank debt                                                 -       71,365
    Working capital deficiency                           36,361       39,764
    -------------------------------------------------------------------------
    Total net debt                                      275,816      111,129
    -------------------------------------------------------------------------
    Total assets                                      1,016,658      731,129
    Unitholders' equity                                 505,096      392,269
    -------------------------------------------------------------------------
    OPERATING
    Daily sales volumes
      Crude oil and NGLs           (bbls/d)               5,317        2,958
      Natural gas                   (mcf/d)              51,264       34,287
      Total oil equivalent          (boe/d)              13,861        8,672
    Average prices
      Crude oil and NGLs            ($/bbl)               48.00        40.64
      Crude oil and NGLs
       (including hedging)          ($/bbl)               47.54        40.44
      Natural gas                   ($/mcf)                6.75         9.41
      Natural gas (including
       hedging)                     ($/mcf)                6.93         9.41
      Total oil equivalent          ($/boe)               43.36        51.06
      Total oil equivalent
       (including hedging)          ($/boe)               43.88        50.99
    Statistics
      Operating netback             ($/boe)               22.60        30.34
      Operating netback
       (including hedging)          ($/boe)               23.12        30.28
      Production expenses           ($/boe)                9.23         6.70
      General & administrative      ($/boe)                2.94         1.34
      Royalties as a % of sales
       after transportation                                 24%          26%

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


    -------------------------------------------------------------------------
                                                     Years ended December 31
                                                           2006         2005
    -------------------------------------------------------------------------
    TRUST UNITS
    Trust units outstanding                          70,275,703   36,176,196
    Trust unit incentive rights outstanding           5,429,831    3,159,000
    Units issuable for exchangeable shares              286,942      454,887
    Units issuable for convertible debentures         5,390,625            -
    -------------------------------------------------------------------------
    Diluted trust units outstanding                  81,383,101   39,790,083
    Diluted weighted average trust units(2)          47,217,258   25,133,085

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

    (CDN$, except volumes) based on intra-day trading(2)
    High                                                  21.30        25.88
    Low                                                    7.25        13.60
    Close                                                  7.49        20.80
    Average daily volume                                412,447      183,486
    -------------------------------------------------------------------------
    (1) The Management Discussion and Analysis ("MD&A") contains the term
        "cash flow from operations", which should not be considered an
        alternative to, or more meaningful than cash flow from operating
        activities as determined in accordance with Canadian generally
        accepted accounting principles ("GAAP") as an indicator of the
        Trust's performance. Therefore reference to diluted cash flow from
        operations or cash flow from operations per trust unit may not be
        comparable with the calculation of similar measures for other
        entities. Management uses cash flow from operations to analyze
        operating performance and leverage and considers cash flow from
        operations to be a key measure as it demonstrates the Trust's ability
        to generate the cash necessary to fund future capital investments and
        to repay debt. The reconciliation between cash flow from operations
        and cash flow from operating activities can be found in the MD&A.
        Cash flow from operations per trust unit is calculated using the
        diluted weighted average number of trust units for the period.

    (2) Restated for 2005 to reflect the consolidation of trust units
        effective November 2, 2005. In computing weighted average diluted
        earnings per trust unit for the year ended December 31, 2006 nil
        (2005: 454,887) trust units were added to the
        47,217,258 (2005: 24,678,198 after consolidation) weighted average
        number of trust units outstanding during the year for the dilutive
        effect of exchangeable shares. A total of 286,942 exchangeable shares
        (2005: nil), 5,429,831 (2005: 3,159,000) trust incentive units and
        2,953,767 (2005: nil) 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, 2006 as they
        were not dilutive. To calculate weighted average diluted cash 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 (2005: nil) exchangeable shares and
        2,953,767 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 under this
        calculation.

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

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


                            REPORT TO UNITHOLDERS
    

    The 2006 year was the first full year of True operating as an oil and gas
energy trust, focused on providing unitholder distributions. The year
presented endless challenges from dramatically decreasing commodity prices to
sweeping government proposed tax changes in the trust sector. Although a
disappointing year in the capital markets for the Trust, a number of
operational accomplishments were achieved. The annual operational results
reflect the Trust's response to the challenges of weaker crude oil and natural
gas prices.
    Accomplishments for the fourth quarter and year ended December 31, 2006
include:

    Distributions
    The Board maintained ten consecutive monthly distributions of $0.24 per
unit through to October 16, 2006. The monthly distributions paid on November
15, 2006 and December 15, 2006 were set at $0.18 per unit. Additionally,
monthly distributions declared and paid on January 15, 2007 and February 15,
2007 were $0.12 per unit, with a further announced distribution of $0.12 per
unit to be paid on March 15, 2007.
    On January 15, 2007, the Trust announced its intention to convert to a
growth oriented, dividend paying intermediate exploration and production
company (the "Reorganization"), which will be voted upon by securityholders at
the Annual and Special Meeting (the "Meeting") to be held on March 30, 2007.
Further as announced on February 15, 2007, the Board has determined that no
distribution will be declared for the month of March 2007, which would
normally have been paid on April 16, 2007 to securityholders of record as at
March 30, 2007, pending the consideration of the Reorganization at the
Meeting.

    Production
    2006 production averaged 13,861 boe/d as compared to 8,672 boe/d in 2005,
representing a 60% increase. Average sales volumes for the fourth quarter of
2006 were 19,747 boe/d, compared to 13,248 boe/d in the third quarter of 2006,
which reflects the closing of the acquisition of Prairie Schooner Petroleum
Ltd. ("Prairie Schooner") late in the third quarter.
    During the first six months of 2007, we will continue to be very active
on the drilling front, focused on the implementation of the Kerrobert SAGD
program and drilling in west central Alberta. Capital expenditures in the
first quarter of 2007 are expected to be approximately $50 million.
    Production for the first quarter of 2007, based on field estimates, is
expected to be approximately 19,000 boe/d. The decrease in production expected
for this period reflects shut-in production at Kerrobert as facility upgrades
and new steam wells are being drilled, which is expected to materially
increase production later in the year. We currently expect production to
average approximately 20,500 boe/d for 2007.

    Financial
    Cash flow from operations for 2006 was $90.4 million on gross sales of
$220.9 million compared to cash flow from operations of $87.1 million on gross
sales of $161.7 million in 2005. For the fourth quarter of 2006, cash flow
from operations was $31.8 million compared to $32.9 million for the same
period in 2005. The increase in cash flow for the 2006 year was the result of
higher production volumes offset by lower natural gas prices. True's realized
natural gas prices in 2006 averaged $6.75/mcf compared to $9.41/mcf in 2005.
    The net loss for 2006 was $233.6 million compared to net earnings of
$13.9 million in 2005. This primarily reflects fourth quarter 2006 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.

    Drilling
    During the 2006 year, True achieved a 98% success rate in the drilling or
participation in 98 (61.5 net) working interest wells, resulting in 72 (41.6
net) gas wells, 24 (18.4 net) oil wells and 2 (1.5 net) dry holes. In the
fourth quarter of 2006, True drilled 21 (10.1 net) working interest wells with
a 95% success rate, resulting in 15 (6.7 net) gas wells, 4 (1.4 net) oil
wells, 1 (1 net) stratagraphic test oil well and 1 (1 net) dry hole. True
successfully participated in 17 (7.6 net) wells in Alberta and 3 (1.5 net)
wells in Saskatchewan during the fourth quarter.

    Acquisitions
    On June 23, 2006, True completed the acquisition of Shellbridge Oil &
Gas, Inc. ("Shellbridge") at a cost of $68.8 million. On September 22, 2006,
True completed the acquisition of Prairie Schooner at a cost of
$344.4 million.
    Late in September 2006, the Trust completed the purchase of a facility in
the Kerrobert, Saskatchewan area which will allow the Trust to begin
implementation of the SAGD phase of the project. During the first phase of
implementation over the first to third quarters of 2007, the Trust plans to
convert a number of existing wells to steam injectors and drill additional
wells that will be used as producing well bores. The facility is currently
running at 600 bbls/d of heavy oil production with capacity of approximately
5,000 bbls/d. Also included in the acquisition were lands on which True has
identified a number of development and exploration opportunities.

    Liquidity
    At December 31, 2006, True had $153.0 million drawn on a revolving term
credit facility, $4.9 million drawn on a demand operating facility,
$81.6 million in convertible debentures (liability component) and the balance
a net working capital deficiency which resulted in total net debt of $275.8
million.
    On October 2, 2006, the existing $150 million credit facility was
replaced by a $225 million facility provided by a Canadian chartered bank, a
U.S. bank, a foreign bank and one institutional lender. As at December 31,
2006, there is approximately $67 million available under this lending
facility.
    Following the implementation of the Premium Distribution(TM)
Reinvestment, Distribution Reinvestment and Optional Trust Unit Purchase Plan
("DRIP") effective March 27, 2006, participation in the first eight months of
the plan averaged approximately 48%. 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 the DRIP until further notice. At the current lower unit
price, this move was considered prudent to avoid further dilution to
unitholders through the DRIP program.
    True has actively increased its commodity price hedging program since
July 2006. At present, True has hedged approximately 33% of current natural
gas production through to the end of March 2007, and approximately 31% of
current natural gas production is hedged in the second quarter through to
October 31, 2007. The AECO natural gas collars have a weighted average floor
of CDN$8.63 per GJ for the first quarter of 2007 and CDN$7.00 per GJ for the
second quarter through October 2007. In addition, True has AECO natural gas
put options (price floor) at CDN$8.00 in the first quarter, in addition to
fixed price natural gas contracts with an average of CDN$9.42 per GJ for the
first quarter and approximately CDN$7.03 to CDN$7.05 per GJ for the second
quarter through to October 2007. As well, True has entered into WTI crude oil
puts with a floor of US$70.00 per barrel for 1,800 bbls per day for the first
quarter of 2007 and an average price floor of US$64.55 per barrel for
2,200 bbls per day during the second quarter of 2007. True will continue to
implement various hedging strategies during 2007 with a focus on maintaining
sufficient cash flow to provide funding of True's 2007 capital program.

    Announcement of Plan to Convert to a Corporation
    On October 31, 2006 the Federal government announced sweeping changes to
the Canadian tax system which will, in essence, impose a tax on distributions
from the Trust commencing with the 2011 tax year. The impact of the federal
government's announcement resulted in a substantial decline in the market
value of all trust units generally, including True. In the absence of final
legislation implementing the 2006 proposed changes, the implications are
difficult to fully evaluate and no assurance can be provided as to the extent
and timing of their application to the Trust and our unitholders. Clearly,
this has created a lot of uncertainty in the oil and gas trust sector.
    The Board evaluated a number of alternatives and is recommending the
Reorganization outlined in the Trust's January 15, 2007 press release.
    Pursuant to the Reorganization announced on January 15, 2007, holders of
trust units of the Trust would receive an equal number of common shares from
the newly formed corporation which will hold the assets previously held
directly or indirectly by the Trust. The exchangeable shares will also be
exchanged for common shares of the newly formed corporation based on the
conversion ratio thereof. An Information Circular and Proxy Statement in
connection with the Meeting will be mailed to securityholders on or about
March 5, 2007 in advance of the March 30, 2007 meeting date. The
Reorganization will be 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. We encourage all our
securityholders to carefully review the forthcoming information circular and
vote in person or by proxy at the March 30th Meeting.

    Paul R. Baay
    President & CEO
    March 1, 2007

    
                     MANAGEMENT'S DISCUSSION AND ANALYSIS
    

    March 1, 2007 - The following Management's Discussion and Analysis of
financial results as provided by the management of True Energy Trust ("True"
or the "Trust") should be read in conjunction with audited consolidated
financial statements for the years ended December 31, 2006 and 2005 for the
Trust. This commentary is based on information available to, and is dated,
March 1, 2007. The financial data presented is in accordance with Canadian
generally accepted accounting principles ("GAAP") in Canadian dollars, except
where indicated otherwise.

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

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

    This Management's Discussion and Analysis also contains the term "payout
ratio" which is not a recognized measure under Canadian GAAP. Management uses
payout ratio to refer to distributions measured as a percentage of cash flow
available for development and acquisition opportunities as well as overall
sustainability of distributions. True calculates this measure consistent with
recent staff notices provided by the Canadian Securities Administrators in
respect of income trusts. True's method of calculating this measure may differ
from other entities, and accordingly, may not be comparable to the measure
used by other trusts or companies. This Management's Discussion and Analysis
also contains other terms such as net debt and operating netbacks, which are
not recognized measures under Canadian GAAP. Management believes these
measures are useful supplemental measures of firstly, the total amount of
current and long-term debt and secondly, the amount of revenues received after
royalties and operating costs. Readers are cautioned, however, that these
measures should not be construed as an alternative to other terms such as
current and long-term debt or net earnings determined in accordance with GAAP
as measures of performance. True's method of calculating these measures may
differ from other entities, and accordingly, may not be comparable to measures
used by other trusts or companies.
    Additional information relating to the Trust, including True's Annual
Information Form, is available on SEDAR at www.sedar.com.

    FORWARD LOOKING STATEMENTS: Certain information contained herein may
contain forward looking statements including management's assessment of future
plans and operations, impact of, and timing of certain projects, effects of
drilling or wells to be tied-in, the effect of government announcements,
proposals and legislation, plans regarding hedging, timing of anticipated
adoption of new accounting rules, estimated cash flow from operations for the
first quarter of 2007, wells to be drilled, the effect of recent legislation,
expected or anticipated production rates, the weighting of production between
different commodities, commodity prices, exchange rates, expected levels of
royalty rates, operating costs, general and administrative costs, costs of
services and other costs and expenses, capital expenditures and the nature of
capital expenditures and the method of financing thereof, may constitute
forward-looking statements under applicable securities laws and necessarily
involve risks including, without limitation, risks associated with oil and gas
exploration, development, exploitation, production, marketing and
transportation, loss of markets, volatility of commodity prices, currency
fluctuations, imprecision of reserve estimates, environmental risks,
competition from other producers, inability to retain drilling rigs and other
services, incorrect assessment of the value of acquisitions, failure to
realize the anticipated benefits of acquisitions, delays resulting from or
inability to obtain required regulatory approvals and ability to access
sufficient capital from internal and external sources. The recovery and
reserve estimates of True's reserves provided herein are estimates only and
there is no guarantee that the estimated reserves will be recovered. Events or
circumstances may cause actual results to differ materially from those
predicted, as a result of the risk factors set out and other known and unknown
risks, uncertainties, and other factors, many of which are beyond the control
of True. The reader is cautioned not to place undue reliance on this forward
looking information. As a consequence, actual results may differ materially
from those anticipated in the forward-looking statements. Readers are
cautioned that the foregoing list of factors is not exhausted. Additional
information on these and other factors that could effect True's operations and
financial results are included in reports on file with Canadian securities
regulatory authorities and may be accessed through the SEDAR website
(www.sedar.com), at True's website (www.trueenergytrust.com). Furthermore, the
forward-looking statements contained herein are made as at the date hereof and
True does not undertake any obligation to update publicly or to revise any of
the included forward-looking statements, whether as a result of new
information, future events or otherwise, except as may be required by
applicable securities laws.
    The reader is further cautioned that the preparation of financial
statements in accordance with GAAP requires management to make certain
judgments and estimates that affect the reported amounts of assets,
liabilities, revenues and expenses. Estimating reserves is also critical to
several accounting estimates and requires judgments and decisions based upon
available geological, geophysical, engineering and economic data. These
estimates may change, having either a negative or positive effect on net
earnings as further information becomes available, and as the economic
environment changes.

    Corporate Developments

    Acquisition of Prairie Schooner Petroleum Ltd.
    On September 22, 2006, the Trust completed the acquisition of Prairie
Schooner Petroleum Ltd. ("Prairie Schooner") on the basis of 1.22 trust units
of True for each outstanding share of Prairie Schooner, pursuant to a plan of
arrangement under the Business Corporations Act (Alberta). In total, True
issued 25,759,563 trust units to acquire Prairie Schooner.

    Acquisition of Shellbridge Oil & Gas, Inc.
    On June 23, 2006 the Trust completed the acquisition of Shellbridge Oil &
Gas, Inc. ("Shellbridge") on the basis of 0.14 trust units of True for each
outstanding share of Shellbridge, pursuant to a plan of arrangement under the
Business Corporations Act (Alberta). In total, True issued 4,389,366 trust
units to acquire Shellbridge.
    Further information on the acquisitions of Prairie Schooner and
Shellbridge is found in notes 3 and 5 of the consolidated financial
statements.

    Plan of Arrangement - Conversion to a Trust
    On November 2, 2005 True Energy Inc. and TKE Energy Trust ("TKE") entered
into a business combination whereby True Energy Inc. acquired TKE via a
reverse takeover, thus creating True Energy Trust ("True" or the "Trust"), and
a publicly listed exploration focused company, Vero Energy Inc. ("Vero"),
pursuant to a Plan of Arrangement ("TKE Arrangement").
    Concurrent with approval of the TKE Arrangement, TKE received approval
from Unitholders at the TKE Unitholder Meeting to consolidate its existing
outstanding trust units on a one-for-two (1:2) basis and to change its name to
"True Energy Trust". Under the TKE Arrangement, True Energy Inc. and TKE
Energy Inc. were amalgamated to form the new administrator of the Trust under
the name True Energy Inc.
    The TKE Arrangement resulted in True Energy Inc. shareholders receiving,
for each True common share held: (i) 0.5 of a pre-consolidated trust units
(0.25 of a post-consolidated Trust Unit); (ii) 0.10 of a Vero Share; and (iii)
one Vero arrangement warrant. Each whole Vero arrangement warrant entitled the
holder to acquire 0.0655 of a Vero Share, for a period of 30 days following
November 2, 2005.
    Pursuant to the TKE Arrangement, the Trust owns 100% of the assets of TKE
and approximately 90% of the former True Energy Inc. assets. The remainder of
the True Energy Inc. assets were transferred to Vero, consisting primarily of
producing assets and undeveloped lands in the Whitecourt/ Edson area of west
central Alberta.
    The acquisition of True Energy Inc. by TKE Energy Trust to form the Trust
has been accounted for as a reverse takeover of TKE and a continuity of
interests of True Energy Inc. Accordingly, the consolidated financial
statements for 2005 reflect the financial position, results of operations and
cash flows as if the Trust had always carried on the business formerly carried
on by True Energy Inc. The year ended December 31, 2005 reflects the results
of operations and cash flows of True Energy Inc. and its subsidiaries for the
period January 1 to November 1, 2005, and the results of operations and cash
flows of the Trust (including TKE and its subsidiaries) for the period
November 2 to December 31, 2005. The comparative figures are the results of
True Energy Inc. and its subsidiaries. Due to the conversion into a trust,
certain information included in Management's Discussion and Analysis for prior
periods may not be directly comparable.
    The term "units" has been used to identify both the trust units and the
exchangeable shares of the Trust issued on or after November 2, 2005 as well
as the common shares of True Energy Inc. outstanding prior to the conversion
on November 2, 2005.

    Fourth Quarter 2006

    Cash flow from operations during the fourth quarter of 2006 was
$31.8 million, a decrease of 3% compared to $32.9 million for the fourth
quarter of 2005. By comparison, in the last quarter of 2006, True's earnings
were a net loss of $250.7 million compared to net earnings of $3.2 million in
the fourth quarter of 2005. The net loss during the fourth quarter is
primarily due to 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, 2006 averaged
19,747 boe/d, up 83% from the 10,784 boe/d produced in the fourth quarter of
2005. Production during the last quarter of 2006 included the additional
volumes derived from the Shellbridge and Prairie Schooner acquisitions as well
as drilling activity during 2006. In the fourth quarter of 2006, average sales
volumes increased 49% from the third quarter 2006 average volumes of
13,248 boe/d as a result of the first full quarter of Prairie Schooner natural
gas volumes. Natural gas sales averaged 73.8 Mmcf/d during the last quarter of
2006, compared to 42.5 Mmcf/d in the fourth quarter of 2005. The weighting
toward natural gas averaged 62% in the fourth quarter, compared to 66% in the
corresponding period of 2005. In the last quarter of 2006, True's natural gas
exploration efforts focused on drilling 15 (6.7 net) wells, primarily in the
Huxley, Ferrier and Willesden Green areas. Crude oil, condensate and NGL sales
volumes averaged 7,440 bbls/d in the fourth quarter compared to 3,699 bbls/d
during the same period of 2005. During the fourth quarter of 2006, True
drilled 1 (0.4 net) heavy oil well at Mantario, 2 (0.8 net) light oil wells at
George and 1 (0.3 net) light oil well at Gage. During the fourth quarter of
2006, True invested $25.9 million on capital projects, excluding corporate and
asset acquisitions and dispositions, compared to $52.6 million in 2005.
    During the fourth quarter of 2006, True experienced an overall decrease
in commodity prices. The average Alberta Spot price for natural gas during
this quarter was 43% lower than in the same period in 2005. For the three
months ending December 31, 2006, before transportation and hedging, True
received an average natural gas price of $6.98/Mcf, 41% less than $11.88/Mcf
in the same period in 2005 and 16% higher than $6.02/Mcf in the third quarter
of 2006. For heavy crude oil, True received an average price before
transportation of $34.82/bbl during the fourth quarter of 2006, 14% more than
$30.53/bbl in the same period in 2005 and 33% less than $51.92/bbl in the
third quarter of 2006. In comparison, the average reference price for Bow
River crude in the fourth quarter of 2006 was 7% more than the average 2005
price in the same period. For light oil, condensate and NGL's, True received
an average price of $60.34/bbl before hedging during the last quarter of 2006,
3% less than the average price of $62.13/bbl received in the same period of
2005, compared to a 9% decrease in the Edmonton par reference price. The
average price for light oil, condensate and NGLs for True was 13% lower than
the $69.68/bbl for the third quarter of 2006. During the fourth quarter of
2006, pre-transportation revenue of $76.8 million was 26% more than the
corresponding 2005 period.
    In the fourth quarter of 2006, the Trust paid $18.5 million in royalties,
compared to $15.5 million in the same period in 2005. As a percentage of
pre-hedge sales (after transportation costs), royalties were 25% in the fourth
quarter of 2006 compared to 26% in the same period in 2005. In this same
period of 2006, operating costs totaled $17.7 million, compared to
$7.6 million recorded in the same period of 2005. During the fourth quarter of
2006, operating costs averaged $9.76/boe, up from the $7.66/boe incurred
during the fourth quarter of 2005, primarily reflecting the different property
mix and increased field costs for services. In comparison, operating costs for
the third quarter of 2006 averaged $8.58/boe. True is forecasting operating
costs of approximately $9/boe in 2007. During the fourth quarter of 2006,
company field operating netbacks decreased by 43% to $21.05/boe compared to
2005, driven primarily by decreased natural gas prices, increased operating
costs, and partially offset by decreased royalties. In comparison, the company
operating netbacks for natural gas before hedging during the fourth quarter of
2006 of $3.78/Mcf were 49% less than the 2005 netbacks, reflecting a
significantly lower gas price offset by a reduction in royalties. In
comparison, the field operating netback for natural gas for the third quarter
of 2006 was $3.12/Mcf. Field operating netbacks before hedging for crude oil
and NGLs during the fourth quarter of 2006 averaged $18.35/bbl, down from
$22.96/bbl during the fourth quarter of 2005, primarily as a result of a small
increase in the overall commodity price received, offset by higher operating
costs associated with increased heavy oil production. In comparison, the field
operating netback for crude oil and NGLs for the third quarter of 2006 was
$30.32/bbl.
    In the fourth quarter of 2006, the net cost of general and administrative
expenses was $5.9 million, compared to $1.2 million in the comparable 2005
period reflecting the increased costs for services and staffing as a result of
the Shellbridge and Prairie Schooner acquisitions, as well as increased
staffing to support higher production levels.
    Depletion, depreciation and accretion expense for the fourth quarter of
2006 was $53.1 million, compared to $28.7 million in 2005, reflecting the
acquisition of Shellbridge and Prairie Schooner assets in 2006 and increased
production in the quarter.

    Net Earnings (Loss) and Cash Flow from Operations

    True generated cash flow from operations of $90.4 million ($1.87 per
diluted unit) for the year ended December 31, 2006, up 4% from the
$87.1 million ($3.47 per diluted unit) for the year of 2005. Lower commodity
prices, despite increased volumes were the primary factors contributing to the
decrease in cash flow per diluted unit.
    True generated a net loss of $233.6 million ($(4.95) per diluted unit) in
the year 2006 compared to net earnings of $13.9 million ($0.55 per diluted
unit) in 2005. Net loss per unit in 2006 was impacted by higher depletion,
depreciation and accretion charges from the 2006 acquisitions of Shellbridge
and Prairie Schooner, a ceiling test write-down of $110.0 million, a goodwill
impairment charge of $169.8 million and higher unit-based compensation
expenses due to increased personnel numbers.

    
    Cash Flow From Operations and Net Earnings
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($000s, except per unit amounts)                       2006         2005
    -------------------------------------------------------------------------
    Cash flow from operations                            90,391       87,137
      Basic ($/unit)                                       1.91         3.53
      Diluted ($/unit)                                     1.87         3.47

    Net earnings (loss)                                (233,564)      13,890
      Basic ($/unit)                                      (4.95)        0.56
      Diluted ($/unit)                                    (4.95)        0.55
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Reconciliation of Cash Flow from Operations and Distributions

    Distributable cash is determined by aggregating various amounts received,
including interest income on notes of subsidiaries and other interest income
received or receivable, income generated under net profits interest, royalty,
other permitted investments, ARTC and dividends and other distributions on
securities of subsidiaries, after deduction of all expenses and liabilities of
the Trust. The portion of distributable cash declared payable to unitholders
on any distribution date is determined on recommendation of the Board of
Directors of True Energy Inc., as administrator of the Trust.

    
    Reconciliation of Cash Flow from Operations and Distributions
    -------------------------------------------------------------------------
                                                     Years ended December 31,

    ($000s, except per unit amounts)                       2006         2005
    -------------------------------------------------------------------------
    Cash flow from operations                            90,391       87,137
    Change in non-cash working capital                   36,925       21,665
    -------------------------------------------------------------------------
    Cash flow from operating activities                 127,316      108,802
    Funding from convertible debentures and DRIP        124,564            -
    Cash withheld to fund capital and
     other expenditures                                (127,525)     (91,441)
    -------------------------------------------------------------------------
    Distributions paid                                  124,355       17,361
    Accumulated distributions, beginning of year         17,361            -
    -------------------------------------------------------------------------
    Accumulated distributions, end of year              141,716       17,361
    -------------------------------------------------------------------------
    Distributions per unit for outstanding units
     in the year (2005: two month period)                  2.64         0.48
    Accumulated distributions per unit, beginning
     of year                                               0.48            -
    -------------------------------------------------------------------------
    Accumulated distributions per unit, end of year        3.12         0.48
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Following the implementation of the Premium Distribution(TM)
Reinvestment, Distribution Reinvestment and Optional Trust Unit Purchase Plan
("DRIP") effective March 27, 2006, participation in the first eight months of
the plan averaged approximately 48%. Funds reinvested in the Trust through
this plan will be available to fund capital and other expenditures. On
November 16, 2006, the Trust announced the suspension of equity available for
reinvestment under DRIP until further notice.

    
    Payout Ratio
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($000s, except percentages)                            2006         2005
    -------------------------------------------------------------------------
    Cash flow from operations                            90,391       87,137
    Change in non-cash working capital                   36,925       21,665
    -------------------------------------------------------------------------
    Cash flow from operating activities                 127,316      108,802
    -------------------------------------------------------------------------

    Distributions paid before DRIP                      124,355       17,361
    DRIP                                                (42,608)        (301)
    -------------------------------------------------------------------------
    Distributions after DRIP                             81,747       17,060
    -------------------------------------------------------------------------
    Payout ratio before DRIP                                98%          16%
    Payout ratio after DRIP                                 64%          16%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

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

    Sales Volumes

    Sales volumes for the year ended December 31, 2006 averaged 13,861 boe/d,
an increase of 60% compared to 8,672 boe/d reported in the year 2005. This
increase was due to a combination of results from drilling activity and the
acquisitions of TKE effective November 2, 2005, Shellbridge effective June 23,
2006 and Prairie Schooner effective September 22, 2006. Estimated production
for the first quarter of 2007, based on field estimates, is approximately
19,000 boe/d. True currently has 12 (6.5) Alberta wells and 1 (0.8 net)
Saskatchewan wells remaining to be tied-in; current drilling operations are
expected to add to this backlog in the short term, but contributing to
production later in the year.
    For the year ended December 31, 2006, the weighting towards natural gas
production averaged 62% compared to 66% in 2005. Heavy oil sales made up 26%
of total production for the 2006 year compared to 24% in 2005. The increase in
heavy oil weighting for the year was due to the addition of primarily heavy
oil weighted assets from Shellbridge at the end of the second quarter of 2006.
The September 2006 acquisition of Prairie Schooner added significant natural
gas volumes which has since increased the natural gas production weighting.
Currently, the Trust estimates that the weighting towards natural gas
production is approximately 64%.

    
    Sales Volumes
    -------------------------------------------------------------------------
                                                     Years ended December 31,
                                                           2006         2005
    -------------------------------------------------------------------------
    Natural gas                     (mcf/d)              51,264       34,287
    -------------------------------------------------------------------------
    Heavy oil                      (bbls/d)               3,612        2,075

    Light oil and condensate       (bbls/d)               1,285          591

    NGLs                           (bbls/d)                 420          292
    -------------------------------------------------------------------------
    Total crude oil and NGLs       (bbls/d)               5,317        2,958
    -------------------------------------------------------------------------
    Total boe/d                       (6:1)              13,861        8,672
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Sales of natural gas averaged 51.3 mmcf/d for 2006, compared to
34.3 mmcf/d in 2005, an increase of 50%.
    Crude oil and NGLs sales for 2006 averaged 5,317 bbls/d up 80% from 2005
average sales of 2,958 bbls/d. Most of this increase was due to greater heavy
oil volumes from the acquisition of Shellbridge in June 2006 and an increased
drilling program. During 2006, True also drilled and placed on production
18 (15.4 net) heavy oil wells with the majority of these wells in the Hoosier,
Mantario and Kerrobert, Saskatchewan areas.

    Commodity Prices

    The impact of changes in the Canadian dollar from the conversion of US$
based commodities prices reduced profitability during the year ended
December 31, 2006 when compared to the same period in 2005. The U.S./Canadian
exchange rate changed 7% from an average of 0.8261 in 2005 to 0.8817 in 2006.

    
    Average Commodity Prices
    -------------------------------------------------------------------------
                                        Years ended December 31,
                                              2006         2005     % change
    -------------------------------------------------------------------------
    Exchange rate (US$/Cdn$)                0.8817       0.8261            7

    Natural gas:
    NYMEX (US$/mmbtu)                         6.99         9.01          (22)
    Alberta spot ($/mcf)                      6.17         8.65          (29)
    True's average price ($/mcf)              6.75         9.41          (28)
    True's average price
     (including hedging)($/mcf)               6.93         9.41          (26)

    Crude oil:
    WTI (US$/bbl)                            66.23        56.59           17
    Edmonton par - light oil ($/bbl)         73.30        69.18            6
    Bow River - medium/heavy oil ($/bbl)     51.54        43.83           18
    Hardisty Heavy - heavy oil ($/bbl)       43.32        34.35           26
    True's average prices ($/bbl)
      Light crude and condensate             66.15        64.19            3
      Light crude and condensate
       (including hedging)                   64.26        63.19            2
      NGLs                                   51.15        52.69           (3)
      Light crude oil, condensate and NGLs   62.46        60.39            3
      Light crude oil, condensate and NGLs
       (including hedging)                   61.03        59.72            2
      Heavy crude oil                        41.17        32.23           28
      Total crude oil and NGLs               48.00        40.64           18
      Total crude oil and NGLs
       (including hedging)                   47.54        40.44           18
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    True's natural gas is primarily sold on the daily spot market. During
2006, the Alberta Spot reference price decreased by 29% compared to 2005.
Similarly, True's average sales price before transportation and hedging for
2006 averaged $6.75/mcf for its natural gas, 28% less than the $9.41/mcf
received in the prior year.
    For heavy crude oil, True received an average price before transportation
of $41.17/bbl during 2006, an increase of 28% over 2005 prices. The Bow River
and Hardisty Heavy reference prices increased by 18% and 26%, respectively.
The majority of True's heavy crude oil density ranges between 11 and 16
degrees API consistent with the Hardisty Heavy reference price. The Trust
blends most of its heavy oil with condensate on a 4:1 ratio to meet pipeline
requirements. The lower comparative prices for condensate purchased for
blending purposes has resulted in a relatively stronger price gain for the
Trust's product than the reference price.
    For light oil, condensate and NGLs, True recorded an average $62.46/bbl
before hedging during 2006, 3% greater than the average price received in
2005. During this period, the Edmonton par price increased by 6%. The Edmonton
par price peaked in excess of $80/bbl during July 2006 and since decreased for
the remainder of 2006.

    Revenue

    Revenue before other income and transportation for the year ended
December 31, 2006 was $219.4 million, 36% greater than the $161.6 million in
2005. The higher revenue was the result of significant growth in production
volumes for natural gas, crude oil, condensate and NGLs, despite lower overall
crude oil and natural gas prices.

    
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($000s)                                                2006         2005
    -------------------------------------------------------------------------
    Light crude oil and condensate                       31,030       13,852
    NGLs                                                  7,846        5,617
    Heavy oil                                            54,278       24,402
    -------------------------------------------------------------------------
    Crude oil and NGLs                                   93,154       43,871
    Natural gas                                         126,216      117,758
    -------------------------------------------------------------------------
    Total revenue before other                          219,370      161,629
    Other                                                 1,543           41
    -------------------------------------------------------------------------
    Total revenue before royalties and hedging          220,913      161,670
    Gain (loss) on commodity contracts                    2,639         (217)
    -------------------------------------------------------------------------
    Total                                               223,552      161,453
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    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.
    Pursuant to the agreement between the Trust and Prairie Schooner entered
into in connection with the acquisition of Prairie Schooner, both Prairie
Schooner and True agreed to hedge up to 30% of the current production during
the winter on a mutually agreed basis. Since July 2006, True has actively
increased its hedging program, entering into various crude oil and natural gas
hedging contracts. True also assumed certain hedging contracts from the
Prairie Schooner acquisition. Currently, the Trust has hedged volumes of
1,800 bbl/d of crude oil and liquids and 26,000 GJ/d of natural gas for the
first quarter 2007, 2,200 bbls/d of crude oil and liquids and 25,000 GJ/d of
natural gas for the second quarter 2007, 25,000 GJ/d of natural gas for the
third quarter 2007 and 11,739 GJ/d of natural gas for the fourth quarter 2007.
The Trust plans to implement various hedging strategies during 2007 with a
focus on maintaining sufficient cash flow to provide funding of True's 2007
capital program.
    A summary of the hedge volumes and average prices by quarter is shown in
the following tables (see Note 18 to the consolidated financial statements for
a detailed disclosure of all commodity contracts in place as at March 1,
2007):

    
    Crude oil and liquids     Average Volumes (bbls/d)
    -------------------------------------------------------------------------
                              Q1 2007      Q2 2007      Q3 2007      Q4 2007
    -------------------------------------------------------------------------
    Put option (price floor)    1,800        2,200            -            -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Average Price (US$/bbl WTI)
    -------------------------------------------------------------------------
                              Q1 2007      Q2 2007      Q3 2007      Q4 2007
    -------------------------------------------------------------------------
    Put option price floor      70.00        64.55            -            -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Natural gas      Average Volumes (GJ/d)
    -------------------------------------------------------------------------
                              Q1 2007      Q2 2007      Q3 2007      Q4 2007
    -------------------------------------------------------------------------
    Costless collars            8,000       15,000       15,000        5,031
    Put option (price floor)   13,000            -            -            -
    Fixed                       5,000       10,000       10,000        6,708
    -------------------------------------------------------------------------
    Total GJ/d                 26,000       25,000       25,000       11,739
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Average Price ($/GJ AECO C)
    -------------------------------------------------------------------------
                              Q1 2007      Q2 2007      Q3 2007      Q4 2007
    -------------------------------------------------------------------------
    Collar ceiling price        10.71         9.29         9.29         9.29
    Collar floor price           8.63         7.00         7.00         7.00
    Put option price floor       8.00            -            -            -
    Fixed                        9.42         7.05         7.05         7.03
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

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

    
    Commodity contracts
    -------------------------------------------------------------------------
    ($000s)                 Crude Oil      Natural         2006         2005
                            & Liquids          Gas        Total        Total
    -------------------------------------------------------------------------
    Realized cash gain
     (loss) on
     contracts(1)                (890)       3,529        2,639         (217)
    Unrealized gain (loss)
     on contracts                   -            -            -            -
    -------------------------------------------------------------------------
    Total gain (loss) on
     commodity contracts         (890)       3,529        2,639         (217)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Includes the amortization of natural gas put option premiums of
        $1.8 million for the year ended December 31, 2006.
    

    All of the existing contracts as of December 31, 2006 require monthly
settlement and have been designated as hedges in accordance with Accounting
Guideline 13. Further, the estimated fair value of open hedging contracts at
the end of each reporting period is disclosed in accordance with this
standard. As at December 31, 2006, the unrealized gain on the then outstanding
commodity contracts, which changes on a daily basis, was $8.2 million.
    Effective January 1, 2007, True will be required to adopt Section 1530
"Comprehensive Income", Section 3855 "Financial Instruments - Recognition and
Measurement" and Section 3865 "Hedges" issued by the CICA. Further details are
discussed in the Financial Reporting Update section of this report.

    Royalties

    For the 2006 year, total royalties were $51.8 million, compared to
$40.8 million incurred in 2005 up 27%, which was slightly less than the 36%
increase in total revenue for the year. Overall royalties as a percentage of
revenue (after transportation costs) in 2006 was 24%, compared with 26% in
2005. True recorded its maximum Alberta Royalty Tax Credit ("ARTC") in 2006.
Royalties as a percentage of revenue (after transportation costs) in the year
ended December 31, 2006 varied in the 16% to 28% range, reflecting gas cost
allowance credits received and the relative commodity price changes combined
with the lower overall royalty rate on the TKE asset base. The ARTC program
has been eliminated effective January 1, 2007 which will effectively increase
royalties by $0.5 million per year.

    
    -------------------------------------------------------------------------
    Royalties by Commodity Type                      Years ended December 31,
    ($000s, except where noted)                            2006         2005
    -------------------------------------------------------------------------
    Light crude oil and condensate                        4,728        2,544
      $/bbl                                               10.08        11.79
      Average light crude oil and condensate
       royalty rate (%)                                      16           15

    NGLs                                                  1,979        1,138
      $/bbl                                               12.90        10.67
      Average NGLs royalty rate (%)                          25           19

    Heavy Oil                                            14,395        5,107
      $/bbl                                               10.91         6.75
      Average heavy oil royalty rate (%)                     28           22

    Natural Gas                                          30,714       32,029
      $/mcf                                                1.64         2.56
      Average natural gas royalty rate (%)                   25           28

    -------------------------------------------------------------------------
    Total                                                51,816       40,818
    -------------------------------------------------------------------------
      $/boe                                               10.24        12.90
    -------------------------------------------------------------------------
      Average total royalty rate (%)                         24           26
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Royalties, by Type
                                                     Years ended December 31,
    ($000s)                                                2006         2005
    -------------------------------------------------------------------------
    Crown royalties, net of ARTC                         32,243       28,739
    Indian Oil and Gas Canada royalties                   2,948          909
    Freehold & GORR                                      16,625       11,170
    -------------------------------------------------------------------------
    Total                                                51,816       40,818
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Expenses
    -------------------------------------------------------------------------

                                                     Years ended December 31,
    ($000s)                                                2006         2005
    -------------------------------------------------------------------------
    Production                                           46,685       21,219
    Transportation                                        6,517        3,525
    General and administrative                           14,896        4,231
    Interest and financing charges                       10,665        1,308
    Unit-based compensation                               6,597        5,402
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Expenses per boe
    -------------------------------------------------------------------------

                                                     Years ended December 31,
    ($ per boe)                                            2006         2005
    -------------------------------------------------------------------------
    Production                                             9.23         6.70
    Transportation                                         1.29         1.11
    General and administrative                             2.94         1.34
    Interest and financing charges                         2.11         0.41
    Unit-based compensation                                1.30         0.43
    -------------------------------------------------------------------------
    

    Production Expenses

    For the 2006 year, production expenses totaled $46.7 million, compared to
$21.2 million recorded in 2005. During 2006, production expenses averaged
$9.23/boe, an increase of 38% over 2005. This increase in production expenses
is largely due to a different property mix along with inflationary pressure on
the costs of services.

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

                                                     Years ended December 31,
    ($000s, except where noted)                            2006         2005
    -------------------------------------------------------------------------
    Light crude oil and condensate                        6,305        2,115
      $/bbl                                               13.44         9.80

    NGLs                                                  1,568          500
      $/bbl                                               10.22         4.69

    Heavy oil                                            13,754        5,420
      $/bbl                                               10.43         7.16

    Natural gas                                          25,058       13,184
      $/mcf                                                1.34         1.05

    Total                                                46,685       21,219
    -------------------------------------------------------------------------
      $/boe                                                9.23         6.70
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Transportation

    Transportation costs continue to be approximately 2% to 3% of gross
revenues for the year ended December 31, 2006 and 2005.

    Operating Netbacks

    For the 2006 year, corporate field operating netbacks (before hedging)
decreased by 26% to $22.60/boe from $30.34/boe in 2005, primarily resulting
from the weaker natural gas prices, increased production expenses and offset
somewhat by increased prices for crude oil and NGLs. After including hedging
activities, corporate field operating netbacks for 2006 was $23.12/boe
compared to $30.28/boe in 2005.

    
    Field Operating Netbacks - Corporate (before hedging)
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($/boe)                                               2006          2005
    -------------------------------------------------------------------------
    Sales                                                43.36         51.06
    Transportation                                       (1.29)        (1.12)
    Royalties                                           (10.24)       (12.90)
    Production expense                                   (9.23)        (6.70)
    -------------------------------------------------------------------------
    Field operating netback                              22.60         30.34
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Field operating netbacks for natural gas during 2006 decreased 36% to
$3.59/mcf, compared to $5.62/mcf for 2004, reflecting the weaker natural gas
prices experienced. Per unit royalties decreased by 36% reflecting the change
in asset base through acquisitions. After including hedging activities, field
operating netbacks for natural gas for 2006 was $3.77/mcf compared to
$5.62/mcf in 2005.

    
    Field Operating Netbacks - Natural Gas (before hedging)
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($/mcf)                                                2006         2005
    -------------------------------------------------------------------------
    Sales                                                  6.75         9.41
    Transportation                                        (0.18)       (0.18)
    Royalties                                             (1.64)       (2.56)
    Production expense                                    (1.34)       (1.05)
    -------------------------------------------------------------------------
    Field operating netback                                3.59         5.62
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Field operating netbacks for crude oil and NGLs averaged $24.36/bbl
during 2006, up 3% compared to $23.81/bbl for 2005, compared to an 18%
increase in crude oil and NGLs sales price. This reflects the increased
weighting of True's production of heavy oil compared to light oil and NGLs and
the corresponding increase in average sales prices for heavy oil relative to
light oil and NGLs, offset somewhat by increased production costs associated
with heavy oil. After including hedging activities, field operating netbacks
for crude oil and NGLs was $23.90/boe compared to $23.61/boe in 2005.

    
    Field Operating Netbacks - Crude Oil and NGLs (before hedging)
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($/bbl)                                                2006         2005
    -------------------------------------------------------------------------
    Sales                                                 48.00        40.64
    Transportation                                        (1.63)       (1.25)
    Royalties                                            (10.87)       (8.14)
    Production expense                                   (11.14)       (7.44)
    -------------------------------------------------------------------------
    Field operating netback                               24.36        23.81
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    General and Administrative

    Net general and administrative expenses for the year ended December 31,
2006 were $14.9 million compared to $4.2 million for the same period in 2005.
On a per-unit of production basis, general and administrative expenses ("G&A")
in 2006 are $2.94/boe, compared to $1.34/boe in 2005.
    The increase during the first nine months of 2006 is attributed to higher
costs incurred for reserve reporting, audit costs, annual reporting charges
for preparation and mailing, recruiting, annual registration, securities
filing fees, internal control compliance and employee cash compensation. The
most significant increase in G&A expenses was due to increased staff levels in
relation to the three acquisitions since November 2005 and higher compensation
costs. As a result of unprecedented levels of activity for the Trust and for
the industry as a whole, the costs associated with hiring, compensating and
retaining employees and consultants have risen significantly. Total employee
compensation and benefit costs for 2006 increased by 91% over 2005 which
reflects the increased personnel and average increases in compensation over
the prior year that were necessary to maintain competitive for retaining
employees in the marketplace.
    G&A expenses in 2006 include $523,000 or $0.10/boe for external costs
associated with internal control compliance under Multilateral Instrument 52-
109 compared to nil in 2005.
    Other specific increases in G&A expenses from 2005 to 2006 include
approximately $652,000 related to prior year underaccruals of 2005 G&A, as
well as $542,000 (2005 - nil) for bad debts recorded in the fourth quarter of
2006.
    The Trust estimates G&A costs/boe to decrease to approximately $2.28/boe
in 2007.

    
    General and Administrative Expenses
    -------------------------------------------------------------------------
                                                      Year ended December 31,
    ($000s, except where noted)                            2006         2005
    -------------------------------------------------------------------------
    Gross expenses                                       19,702        9,204
    Capitalized                                          (2,640)      (2,265)
    Recoveries                                           (2,166)      (2,708)
    -------------------------------------------------------------------------
    Net expenses                                         14,896        4,231
    -------------------------------------------------------------------------
    Net expenses, per unit ($/boe)                         2.94         1.34
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Interest and Financing Charges

    True recorded $10.7 million of interest and financing charges in 2006
compared to $1.3 million in the same period of 2005. Financing charges during
2006 were $1.0 million, with the balance being interest charges. True's net
debt at December 31, 2006 of $275.8 million includes the $81.6 million
liability portion of convertible debentures issued in the second quarter,
$157.9 million of bank debt and the balance a working capital deficiency. The
acquisition of Prairie Schooner near the end of the third quarter represents
approximately $74 million of additional net debt as at September 30, 2006,
with only 101 days of activity included in the year-to-date results.

    
    Interest and Financing Charges
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($000s, except where noted)                            2006         2005
    -------------------------------------------------------------------------
    Interest and financing charges                       10,665        1,308
    Interest and financing charges ($/boe)                 2.11         0.41

    Net debt including convertible debentures
     at quarter end                                     275,816      111,129
    Debt to fourth quarter cash flow from operations
     ratio annualized                                      2.1x         1.1x

    Net debt excluding convertible debentures
     at quarter end                                     194,265      111,129
    Debt to fourth quarter cash flow from operations
     ratio annualized                                      1.5x         1.1x
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Unit-Based Compensation

    Non-cash unit-based compensation expense for the year ended December 31,
2006 was $6.6 million compared to $5.4 million in 2005. The increase in the
2006 expense reflects the increased staffing levels of True given the
additional acquisitions in 2006 and increased production activities requiring
appropriate levels of support staff.
    For 2005, all options and incentive units held by True Energy Inc. and
TKE service providers were either exercised or expired on or before completion
of the Arrangement on November 2, 2005, triggering an acceleration of stock
based compensation charges. For TKE, these costs were treated as transaction
costs and included in the purchase price equation of the acquisition. For
True, a total of $2.2 million of costs were triggered, reflected in the
financial statements for 2005 as Plan of Arrangement costs.

    Capital Expenditures

    True invested $116.5 million on capital projects during 2006, including
cash acquisitions and before property dispositions and non-cash corporate
acquisitions, compared to $116.0 million in 2005. During the 2006 year, True
achieved a 98% success rate in the drilling or participation in 98 (61.5 net)
wells, resulting in 72 (41.6 net) natural gas wells, 24 (18.4 net) oil wells
and 2 (1.5 net) dry holes. True successfully participated in or drilled 54
(23.7 net) wells in Alberta, and 42 (36.3 net) wells in Saskatchewan. True
completed the acquisition of Prairie Schooner on September 22, 2006 at a total
cost of $344.4 million and Shellbridge on June 23, 2006 at a total cost of
$68.8 million. These acquisitions are disclosed in note 3a and 3b,
respectively, of the consolidated financial statements.

    
    Capital Expenditures
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($000s)                                                2006         2005
    -------------------------------------------------------------------------
    Lease acquisitions and retention                      9,056        8,667
    Geological and geophysical                            2,399        2,817
    Drilling and completion costs                        69,218       85,033
    Facilities and equipment                             18,533       18,964
    -------------------------------------------------------------------------
      Exploration and development                        99,206      115,481
    Corporate and property acquisitions                  17,322          490
    -------------------------------------------------------------------------
      Total capital expenditures - cash                 116,528      115,971
    Property dispositions - cash                        (24,514)           -
    -------------------------------------------------------------------------
      Total net capital expenditures - cash              92,014      115,971
    -------------------------------------------------------------------------

    Corporate acquisitions - non-cash                   482,875      475,450
    Property acquisitions - non-cash (1)                  1,817
    Property dispositions - non-cash (2)                      -      (26,880)
    Other (3)                                             3,006          412
    -------------------------------------------------------------------------
    Corporate acquisitions and other                    487,698      448,982
    -------------------------------------------------------------------------
      Total capital expenditures                        579,712      564,953
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Includes consideration paid for the acquisition of a property
        interest by issue of trust units.
    (2) Includes the disposition of properties to Vero under the November 2,
        2005 TKE arrangement.
    (3) Other includes current period's asset retirement obligations and unit
        based compensation capitalized.
    

    True continues to develop its land base. At December 31, 2006, True has
approximately 731,000 net undeveloped acres of land of the total net acreage
position of 1,153,000 net acres in Saskatchewan, Alberta, and British
Columbia. The addition of Shellbridge in June 2006 and Prairie Schooner in
September 2006 added approximately 98,000 and 257,000 net acres, respectively,
to the Trust's undeveloped land position.
    As at December 31, 2006, the Trust has committed to drill 13 wells in
Alberta and 16 wells in Saskatchewan by the end of 2007 pursuant to various
farm-in agreements with oil and gas companies. Subsequent to year-end 2006,
the Trust has further committed to drill an additional 10 wells in Alberta and
3 in Saskatchewan. Total estimated cost to the Trust for these commitments is
$29.0 million.
    Corporate and property acquisitions for cash during 2006 consisted
primarily of the acquisition of the Kerrobert, Saskatchewan SAGD heavy oil
facility and wells at the end of September 2006 and the purchase of additional
property interests in the Willesden Green, Alberta in October 2006.
    Dispositions during 2006 consist of two separate oil and gas property
sales involving areas outside of the Trust's core areas for future
development. On May 31, 2006, True closed the sale of its southeast
Saskatchewan oil properties Hartaven and Handsworth for $24 million cash. On
June 20, 2006, True closed the sale of its Peejay and Squirrel area B.C.
properties for $1.2 million cash. The net proceeds received on both property
sales after adjustments was an aggregate of $24.5 million.

    Depletion, Depreciation and Accretion

    Depletion, depreciation and accretion (site restoration) expense for 2006
was $138.9 million, compared to $61.4 million in 2005, reflecting the
acquisition of TKE in 2005, Shellbridge in June 2006, Prairie Schooner in
September 2006 in conjunction with increased production volumes. True has
excluded from the depletion calculation $99.2 million for undeveloped
properties, $49.3 million for undeveloped land and $49.9 million for estimated
salvage.

    
    Depletion, Depreciation and Accretion Costs
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($000s, except where noted)                            2006         2005
    -------------------------------------------------------------------------
    Depletion                                           122,559       51,804
    Depreciation                                         15,251        9,300
    Accretion                                             1,065          336
    -------------------------------------------------------------------------
      Total                                             138,875       61,440
    -------------------------------------------------------------------------
    Per unit ($/boe)                                      27.45        19.41
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Ceiling Test

    The Trust calculates a ceiling test quarterly and annually whereby the
carrying value of petroleum and natural gas properties is compared to
estimated future cash flow from the production of proved reserves. The ceiling
test is performed in accordance with the requirements of the Canadian
Institute of Chartered Accountants ("CICA") AcG-16 "Oil and Gas Accounting -
Full Cost, a two step process.
    The Trust performed a ceiling test calculation at December 31, 2006
resulting in undiscounted cash flows from proved reserves and the unproved
properties not exceeding the carrying value of oil and gas assets.
Consequently, True performed stage two of the ceiling test assessing whether
discounted future cash flows from the production of proved plus probable
reserves plus the carrying cost of unproved properties, net of any impairment
allowance, exceeds the carrying value of its petroleum and natural gas
properties. As a result of performing this test, a ceiling test impairment
loss of $110.0 million has been recorded as a write-down of petroleum and
natural gas properties in the consolidated statements of operations and
included in accumulated depletion.
    At December 31, 2006, the Trust calculated the ceiling test using prices
of $39.01/bbl for heavy oil, $66.31/bbl for light and medium gravity oil, and
$56.56/bbl for NGLs, and $8.33/mcf for natural gas.

    Plan of Arrangement Costs

    Costs relating to the TKE Arrangement on November 2, 2005 include charges
of $2.2 million of stock-based compensation costs arising from the vesting and
exercising of True Energy Inc. options and $1.4 million of severance and
retention costs.

    Asset Retirement Obligation

    As at December 31, 3006, the Trust has recorded an Asset Retirement
Obligation ("ARO") of $26.6 million, compared to $10.4 million at December 31,
2005, for future abandonment and reclamation of the Trust's properties. For
the 2006 year, the ARO increased by $1.0 million for accretion expense and
$13.7 million as a result of the Shellbridge and Prairie Schooner acquisitions
and included $1.4 million net changes in estimates for property acquisitions
and development activities.

    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 transaction. The goodwill balance prior to impairment of
$169.8 million was derived from two 2005 acquisitions, the second quarter 2006
acquisition of Shellbridge and the third quarter acquisition of Prairie
Schooner. The $97.8 million increase in goodwill during 2006 was a combination
of the $24.0 million goodwill recognized on the Shellbridge acquisition,
$71.6 million recognized on the Prairie Schooner acquisition along with a
$2.2 million purchase price equation revision for TKE from the under accrual
of certain capital, net operating expenditures and transaction costs and
adjustments to tax pools from a prior year tax assessment.
    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 Federal Government's announcement of its plans to tax distributions
by publicly traded income trust and similar structures resulted in the markets
reacting quite strongly to the news. As of November 2, 2006, the market
capitalization of the Trust had declined by approximately $130 million (17.6%)
since October 31, 2006. The S&P/TSX Energy Index was off 18% during this same
period. The unit price of the Trust additionally declined to December 31, 2006
in light of various factors including further softening of commodity prices
and uncertainty associated with the government's announcement. In light of the
decline in the market capitalization of the Trust, the Trust has reviewed the
valuation of goodwill as of December 31, 2006 based upon the latest available
data, including the market capitalization of the Trust, recent commodity
prices and an updated reserve engineering report. Based upon this review, an
impairment of goodwill of $169.8 million has been recorded as a non-cash
charge to income as of December 31, 2006.

    Income Taxes

    For the year ended December 31, 2006 the Trust has recorded a provision
for capital taxes of $3.2 million compared to $3.4 million expensed in 2005.
Capital taxes are based on debt and equity levels of the Trust at the end of
the year and were slightly lower in 2006 due to the elimination of federal
capital tax effective January 1, 2006, offset by increased provincial capital
tax. In addition, increased gross sales revenue from Saskatchewan based
properties in 2006 was partially offset by recent provincial capital tax
reductions. In the second quarter of 2006, the federal government enacted
legislation that eliminates federal capital tax, retroactive to January 1,
2006. As a result, capital taxes on a go-forward basis will be based on only
provincial capital taxes.
    Future income taxes arise from differences between the accounting and tax
bases of the operating companies' assets and liabilities. For the year ended
December 31, 2006 the Trust recognized a future income tax recovery provision
of $101.1 million compared to a provision of $2.6 million expensed in 2005. On
April 10, 2006 the Alberta government enacted a decrease of 1.5 percent to the
provincial corporate tax rate. In addition, on June 6, 2006 the Federal
government enacted a two percent decrease to the federal corporate tax rate
from January 1, 2008 to January 1, 2010 and an elimination of the 1.12 percent
federal surtax at January 1, 2008.
    In the Trust's structure, payments are made between the operating
subsidiaries and the Trust transferring income and future income tax liability
to the unitholders. We expect that if the trust structure of the Trust were
maintained, based on existing legislation, that no cash income taxes would be
paid by the operating subsidiaries. As such, the future income tax liability
recorded on the balance sheet would likely have been recovered through
earnings over time. As at December 31, 2006, the operating subsidiaries have a
future income tax liability balance of $123.9 million. Canadian generally
accepted accounting principles require that a future income tax liability be
recorded when the book value of assets exceeds the balance of tax pools. It
further requires that a future tax liability be recorded on an acquisition
when a corporation acquires assets with associated tax pools that are less
than the purchase price.
    At December 31, 2006 the Trust and operating subsidiaries of the Trust
had approximately $498 million (2005 - $180 million), net of partnership
deferrals, in tax pools available for deduction against future earnings as
follows:

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

                                                      Operating
    ($000s)                                  Trust subsidiaries        Total
    -------------------------------------------------------------------------
    Intangible resource pools (net of
    partnership deferrals)             $    15,015  $   306,454  $   321,559
    Undepreciated capital cost                   -      158,132      158,132
    Loss carryforwards
     (expire through 2026)                       -        5,624        5,624
    Unit issue costs                         5,126        6,958       12,084
    Other                                        -          271          271
    -------------------------------------------------------------------------
                                       $    20,231  $   477,439  $   497,670
    -------------------------------------------------------------------------
    

    The October 31, 2006 announcement of the Tax Fairness Plan by the Federal
Government anticipates a distribution tax on distributions from publicly
traded income trusts and similar structures. For existing income trusts and
limited partnerships, the government is proposing a four-year transition
period. As such, the Trust would not be subject to the new measures until the
2011 taxation year provided the Trust continues to meet certain requirements.
Refer to "Business Risks and Uncertainties" for further details.
    The government's plans must first be enacted in Parliament and it may be
some time before the plans, translated into legislation, are substantially
enacted, particularly given the fact that there is a minority government in
place. As such, as at December 31, 2006, and until third reading of the Bill
in Parliament, current and future income taxes have not been adjusted as a
result of this recent announcement. If implemented as currently proposed, the
Trust would be required to recognize in its accounts, in the period in which
the change is substantively enacted, future income taxes on temporary
differences in the Trust.

    Distributions

    Trust unitholders who held their trust units throughout 2006 received
distributions of $2.64 per unit. For the year ended December 31, 2006 the
Trust declared $124.4 million in total distributions as follows:

    
    -------------------------------------------------------------------------
    ($000s, except per unit amount)                Distribution
    Year ended December 31, 2006                       Per Unit        Total
    -------------------------------------------------------------------------
    Distributions paid                              $      2.64  $   124,355
    -------------------------------------------------------------------------
    

    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.
    
    -------------------------------------------------------------------------
    Calendar Year                    Distributions      Taxable    Return of
                                                        Portion      Capital
    -------------------------------------------------------------------------
    2005 (two months)(2)               $     0.480  $     0.456  $     0.024
    2006 year to date(3)                     2.640        2.033        0.607
    -------------------------------------------------------------------------
    Cumulative                         $     3.120  $     2.489  $     0.631
    -------------------------------------------------------------------------

    (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.
    (3) For Canadian tax purposes, 2006 distributions were determined to be
        77 percent taxable and 23 percent a tax deferred return of capital in
        the hands of Canadian unitholders. In Canada, the tax deferred
        portion would usually be treated as an adjustment to the cost base of
        the units.
    

    In consultation with its U.S. tax advisors, True believes that the trust
units should be "qualified dividends" for U.S. federal purposes. As such, the
portion of distributions made during 2006 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 trust units. Please view our March 15, 2006 press release
addressing this.

    Monthly Distributions

    Actual distributions paid and declared per Trust unit along with
anticipated relevant payment dates for 2006 are as follows:

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

    December 28, 2005     December 31, 2005     January 16, 2006      $ 0.24
    January 27, 2006      January 31, 2006      February 15, 2006       0.24
    February 24, 2006     February 28, 2006     March 15, 2006          0.24
    March 29, 2006        March 31, 2006        April 17, 2006          0.24
    April 24, 2006        April 26, 2006        May 15, 2006            0.24
    May 25, 2006          May 29, 2006          June 15, 2006           0.24
    June 23, 2006         June 27, 2006         July 17, 2006           0.24
    July 24, 2006         July 26, 2006         August 15, 2006         0.24
    August 24, 2006       August 28, 2006       September 15, 2006      0.24
    September 22, 2006    September 26, 2006    October 16, 2006        0.24
    October 25, 2006      October 27, 2006      November 15, 2006       0.18
    November 24, 2006     November 28, 2006     December 15, 2006       0.18
    December 27, 2006     December 31, 2006     January 15, 2006        0.12
    -------------------------------------------------------------------------
    

    The Management and Board of the Trust continuously assesses distribution
levels, in light of commodity prices and other factors, and announces the
distribution per unit amount on a monthly basis.
    In 2006, the distributions were funded from a combination of cash flows
from operating activities, the proceeds from a convertible debenture offering,
and the DRIP program.
    The Board of True maintained ten consecutive monthly distributions of
$0.24 per unit through to October 16, 2006. In a press release dated
October 10, 2006, the Trust announced that the cash distribution for the month
of October would be $0.18 per unit, to be paid on November 15, 2006 to all
unitholders of record as of October 27, 2006. Further, in a press release
dated December 14, 2006, the Trust announced that the cash distribution for
the month of December would be $0.12 per unit, to be paid on January 15, 2007
to all unitholders of record on December 31, 2006. These reductions in the
monthly distribution were determined to be prudent by the Board to reflect
weakening commodity prices, both in the current spot market and in the forward
strip prices and to strengthen the balance sheet. Additionally, a monthly
distribution declared and paid on February 15, 2007 was $0.12 per unit, with a
further announced distribution of $0.12 per unit to be paid on March 15, 2007.
    On January 15, 2007, the Trust announced its intention to convert to a
growth oriented, dividend paying intermediate exploration and production
company (the "Reorganization"), which will be voted upon by securityholders at
an Annual and Special Meeting (the "Meeting") to be held on March 30, 2007.
Further as announced on February 15, 2007, the Board of True has determined
that no distribution will 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.
    Combined with a capital efficient growth strategy, True intends to
establish a dividend policy to take effect following the completion of the
Reorganization of True into a corporation. The initial dividend proposed by
True as a corporation is to be set at $0.02/share per month to be paid
quarterly.
    Should the Reorganization not be approved by True securityholders, the
Board of True will meet in April 2007 to determine the level of distribution
to be paid by the Trust.

    Distribution Reinvestment Plan

    Effective March 27, 2006, True adopted a Premium Distribution(TM)
Reinvestment, Distribution Reinvestment and Optional Trust Unit Purchase Plan
(the "Plan"). The Plan amends, restates and replaces in its entirety the
distribution reinvestment and optional trust unit purchase plan (the "Old
Plan") of True dated December 1, 2004, which was implemented by TKE. The Plan
allows eligible unitholders of True to direct that their cash distributions be
reinvested in additional trust units at 95% of the Average Market Price (as
defined in the Plan) on the applicable distribution payment date. The Plan
further allows eligible unitholders to elect, under the Premium
Distribution(TM) component of the Plan, to have these additional trust units
delivered to the designated Plan broker in exchange for a premium cash
distribution equal to 102% of the cash distribution that such unitholders
would otherwise have received on the applicable distribution payment date if
they did not participate in the Plan (subject to proration in certain events
as provided in the Plan.) Canaccord Capital Corporation acts as the Plan
broker for the Premium Distribution(TM) component of the Plan.
    In addition, the Plan allows those unitholders who participate in either
the regular distribution reinvestment component or the Premium
Distribution(TM) component of the Plan to purchase additional trust units from
treasury at a purchase price equal to the Average Market Price (with no
discount) in minimum amounts of $2,000 per remittance up to a maximum
aggregate amount of $50,000 per month by any one unitholder, in any calendar
month, all subject to an overall annual limit of 2% of the total number of
outstanding trust units. The Trust reserves the right to limit the amount of
any new equity available under the Plan on any particular distribution date
and thus participants may be pro-rated in certain circumstances.
    Participation during the first eight months of the plan averaged
approximately 48%.
    On November 16, 2006, the Trust announced the suspension of equity
available for reinvestment under the Plan until further notice.

    Foreign Ownership Update

    Based on information from Trust records and information provided by
intermediaries holding Trust units for others, we estimate that, as of
January 31, 2007 approximately 32 percent of our Unitholders are non-Canadian
residents with the remaining 68 percent being Canadian residents. True's Trust
Indenture provides that not more than 40 percent of its Units can be held by
non-Canadian residents.

    Liquidity and Capital Resources

    True's net debt as at December 31, 2006 was $275.8 million, $4.9 million
drawn on a demand operating facility, $153.0 million drawn on a revolving term
credit facility, $81.6 million in convertible debentures (liability component)
and the balance a net working capital deficiency.
    On October 2, 2006 the existing $150 million credit facility was replaced
by a $15 million demand operating facility provided by one Canadian bank and a
$210 million extendible revolving term credit facility syndicated by the
Canadian chartered bank, a U.S. bank, a foreign bank and one institutional
lender. The revolving period on the new revolving term credit facility ends on
June 29, 2007, unless extended for a further 364 day period. Should the
facilities not be renewed they convert to 366 day non-revolving term
facilities on the renewal date. Further details of the revised credit facility
are disclosed in note 6 of the consolidated financial statements. As at
December 31, 2006, there is approximately $67 million available under this
lending facility.
    Management expects to be able to fund the capital expenditure program for
2007 using cash flow from operations, available credit facilities, the
proceeds from the expected sale of certain non-core assets, and/or the reduced
distributions as a result of the planned conversion to a corporation. If cash
flows are other than projected, capital expenditure levels will be adjusted.
The practice of continually monitoring spending opportunities in comparison to
expected cash flow levels allows for adjustments to the capital program as
required.
    On June 15, 2006 the Trust completed a bought deal public offering of
86,250 7.5% convertible unsecured subordinated debentures at a price of $1,000
per Debenture for aggregate gross proceeds of $86,250,000.
    The 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
the weighted average trading price of the trust units.
    As at February 21, 2007 the Trust had outstanding a total of 5,252,333
incentive units exercisable at an average exercise price of $14.04 per unit,
403,536 exchangeable shares (convertible, as at February 21, 2007 into an
aggregate of 297,739 trust units, subject to further adjustments based on
distributions made on trust units) and 70,275,703 trust units.
    On February 13, 2007, True announced it had identified certain small,
non-core properties, for possible disposition. The planned disposition is
comprised of up to 950 boe/d of largely non-operated production. The proceeds
will be used to fund capital expenditures and pay down debt.

    Commitments

    As at December 31, 2006, the Trust has committed to drill 13 wells in
Alberta and 16 wells in Saskatchewan by the end of 2007 pursuant to various
farm-in agreements with oil and gas companies. Subsequent to year-end 2006,
the Trust has further committed to drill an additional 13 wells in Alberta and
5 in Saskatchewan. The total estimated cost to the Trust for these commitments
is $30.2 million.
    Leases relating to gas compression and other equipment with initial costs
totaling $1.2 million (2005 - $1.2 million) have been classified as capital
leases and are included in property, plant and equipment. The remaining
capital lease obligation of $111 thousand has an implicit interest rate
consisting of a variable Bankers Acceptance Rate + 3.7%; and will be repaid in
2007.
    The Trust has further committed to various corporate sponsorships
extending to June 2010 at an estimated combined cost of up to $172,000.
    The Trust is committed to payments under operating leases for office
space as follows:

    
    -------------------------------------------------------------------------
    ($000s)                                  Gross     Expected
    Year                                    Amount   Recoveries   Net Amount
    -------------------------------------------------------------------------
    2007                                     1,669          271        1,398
    2008                                     1,390          285        1,105
    2009                                     1,000          285          715
    2010                                       285          285            -
    2011                                       285          285            -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Business Prospects and 2007 Outlook

    Since its formation in September 2000, True Energy Inc. has experienced
significant growth in its production and land base. The Trust continues to
develop its core assets and conduct some exploration programs utilizing its
large inventory of geological prospects. In addition, the Trust will continue
to explore potential acquisition opportunities. Currently, the Trust's
producing properties are located in Saskatchewan, Alberta and British
Columbia.
    Late in September 2006, the Trust completed the purchase of a facility in
the Kerrobert, Saskatchewan area and wells which has allowed the Trust to
begin implementation of the SAGD phase of the project. Continuing through June
2007, the Trust plans to convert a number of existing wells to steam injectors
and drill additional wells that will be used as producing well bores. The
facility is currently running at 600 bbls/d of heavy oil production with
capacity of approximately 5,000 bbls/d. Also included in the acquisition were
three sections of land on which True has identified a number of development
and exploration opportunities.
    Capital expenditure levels will be adjusted as appropriate. Under the
Trust's assumption of approval of the conversion to a corporation, the Trust
currently anticipates spending approximately $120 million in 2007 focused on
the implementation of the Kerrobert SAGD program and further development of
its west central Alberta properties, most notably the Ferrier, Willesden Green
and Brazeau areas.
    The Trust currently anticipates that 2007 year average production will be
approximately 20,500 boe/d, weighted approximately 64% toward natural gas.
True further anticipates the US$/Cdn.$ exchange rate to average 0.90 through
the 2007 year.
    The Trust continues to maintain a large undeveloped land base of
approximately 1.1 million (0.7 million net) acres and has identified a multi-
year drilling inventory of over 600 net locations.

    Financial Reporting Update

    Effective January 1, 2007, True will be required to adopt the accounting
rules 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"
will also be effective for True on January 1, 2007. An additional Handbook
section related to disclosure and presentation of financial instruments
(Section 3861) is not effective until 2008 for the Trust. The new accounting
pronouncements that are effective for 2007 determine how reporting entities
recognize and measure financial assets, financial liabilities and
non-financial derivatives.
    New Section 3855 sets out comprehensive requirements for recognition and
measurement of financial instruments. Under this standard, an entity would
recognize a financial asset or liability only when the entity becomes a party
to the contractual provisions of the financial instrument. Financial assets
and financial liabilities would, with certain exceptions, be initially
measured at fair value.
    In conjunction with the new standard on financial instruments as
discussed above, CICA Handbook Section 1530 (Comprehensive Income) has also
been issued. A statement of comprehensive income would be included in a full
set of financial statements for both interim and annual periods under this new
standard. Comprehensive income is defined as the change in equity (net assets)
of an enterprise during a period from transactions and other events and
circumstances from non-owner sources. The new statement would present net
income and each component to be recognized in other comprehensive income.
Likewise, the CICA has issued Handbook Section 3251 (Equity) which requires
the separate presentation of: the components of equity (retained earnings,
accumulated other comprehensive income ("AOCI"), the total retained earnings
and accumulated other comprehensive income, contributed surplus, unitholders'
capital and reserves); and the changes in equity arising from each of these
components of equity.
    Effective January 1, 2007, the Trust will no longer be applying the
former Accounting Guideline 13 hedge accounting to its existing crude oil and
natural gas hedge contracts as the Trust will follow the recommendations of
Section 3865. On January 1, 2007, the Trust will mark-to-market the existing
positions and will record the fair values of approximately $8.2 million on the
Consolidated Balance Sheet as a deferred asset, with a corresponding increase
to AOCI. Subsequent changes in the fair value of the positions will be
recorded in net income.

    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. 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. Given the evolving
nature of the debate related to climate change and the control of greenhouse
gases and resulting requirements, it is not possible to predict either the
nature of those requirements or the impact on the Trust and its operations and
financial condition.
    On October 31, 2006 the Federal Minister of Finance proposed to apply a
tax at the trust level on distributions of certain income from publicly traded
mutual fund trusts and similar structures at rates of tax comparable to the
combined federal and provincial corporate tax and to treat such distributions
as dividends to the unitholders (the "October 31 Proposals"). On December 21,
2006 the Federal Minister of Finance released draft legislation to implement
the October 31, 2006 Proposals pursuant to which, commencing January 1, 2011
(provided the Trust only experiences "normal growth" and no "undue expansion"
before then) certain distributions from the Trust which would have otherwise
been taxed as ordinary income generally will be characterized as dividends in
addition to being subject to tax at corporate rates at the trust level.
Assuming the October 31 Proposals are ultimately enacted in their form, the
implementation of such legislation would be expected to result in adverse tax
consequences to the Trust and certain unitholders (including most particularly
unitholders that are tax deferred or non-residents of Canada) and may impact
cash distributions from the Trust. It is not known at this time when the
October 31 Proposals will be enacted by Parliament, if at all, or whether the
October 31 Proposals will be enacted in the form currently proposed.
    On January 15, 2007, the Trust announced the proposed Reorganization and
its intention to convert to a growth oriented, dividend paying intermediate
exploration and production company, pursuant to which holders of trust units
of the Trust would receive an equal number of shares from the newly formed
corporation who will hold the assets previously held directly or indirectly by
the Trust. The exchangeable shares will also be exchanged for common shares of
the newly formed corporation based on the conversion ratio thereof. Completion
of the Reorganization is subject to approval of securityholders of the Trust
at the meeting of securityholders to be held to consider the matter and will
be subject to receipt of all regulatory and other approvals. There is no
assurance that securityholder or other approvals required for completion of
the Reorganization will be received and that the Reorganization will be
completed.
    See also the risk factors described in the Trust's Annual Information
Form.

    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 circumstance.

    Controls and Procedures

    Disclosure Controls and Procedures

    Disclosure controls and procedures have been designed to ensure that
information required to be disclosed by the Trust is accumulated and
communicated the Trust's management as appropriate to allow timely decisions
regarding required disclosure. The Trust's Chief Executive Officer and Chief
Financial Officer have concluded, based on their evaluation as of the end of
the period covered by the Trust's annual filings for the most recently
completed financial year, that the Trust's disclosure controls and procedures
as of the end of such period are effective to provide reasonable assurance
that material information related to the Trust, 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 related to the Trust, including its consolidated
subsidiaries, to provide reasonable assurance regarding the reliability of the
Trust's financial reporting and the preparation of financial statements
together with the other financial information 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. During 2006, the Trust engaged external consultants to assist in
documenting and assessing the Trust's design of internal controls over
financial reporting. No material changes in the Trust's internal control over
financial reporting were identified during the three months ended December 31,
2006, that has materially affected, or are reasonably likely to materially
affect, the Trust's internal control of financial reporting.
    It should be noted that a control system, including the Trust's
disclosure and internal controls and procedures, no matter how well conceived,
can provide only reasonable, but not absolute, assurance that the objectives
of the control system will be met and it should not be expected that the
disclosure and internal controls and procedures will prevent all errors or
fraud.

    National Instrument 52-109 Certification of Disclosure in Issuers' Annual
    and Interim Filings ("NI 52-109") Update

    On March 30, 2004 National Instrument 52-109 came into force in various
jurisdictions with a requirement for a certification process over disclosure
and internal controls over financial reporting. Initially, an internal control
design was required to provide reasonable assurance regarding the reliability
of the financial reporting and preparation of financial statements in
accordance with Canadian GAAP, with which the Trust is in compliance at
December 31, 2006. Subsequently, an evaluation of the effectiveness over the
internal control design was to have been certified by the Chief Executive
Officer and Chief Financial Officer for the year ended December 31, 2007. The
Canadian Securities Administrators ("CSA") issued a notice on February 9, 2007
proposing that requirements under NI 52-109 be extended becoming effective for
the Trust at year end December 31, 2008. This extension is intended to allow
significant lead time for issuers to plan and implement efficiently the
activities required to support the additional certifications and disclosures
relating to internal controls over financial reporting. The CSA further
indicates that they plan, by the end of March 2007, to seek all necessary
approvals to publish revisions to NI 52-109 for public comment. The Trust will
continue to work diligently to ensure compliance with this requirement by
December 31, 2008.

    Sensitivity Analysis

    The table below shows sensitivities to cash flow as a result of product
price and operational changes. This is based on actual 2006 prices received
for the fourth quarter of 2006 and average production volumes of 19,700 boe/d
during that period, as well as the same level of debt outstanding at
December 31, 2006. Diluted weighted average trust units is based upon the
fourth quarter of 2006. These sensitivities are approximations only, and not
necessarily valid under other significantly different production levels or
product mixes. Hedging activities can significantly affect these
sensitivities. Changes in any of these parameters will affect cash flow as
shown in the table below:

    
    -------------------------------------------------------------------------
                                                                    Cash Flow
                                                      Cash Flow          from
                                                           from    Operations
                                                     Operations           Per
                                                    (annualized) Diluted Unit
    -------------------------------------------------------------------------
    Sensitivity Analysis                                 ($000s)          ($)
    -------------------------------------------------------------------------
    Change of US $1/bbl WTI                               2,300         0.03
    Change of US $0.10/ mcf                               2,300         0.03
    Change of US $0.01 Cdn/ US exchange rate              2,500         0.03
    Change in prime of 1%                                 1,300         0.02
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Selected Quarterly Consolidated Information

    The following table sets forth selected consolidated financial
information of the Trust for the eight most recently completed quarters at the
end of 2006.

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

    2005 - Quarter ended
     (unaudited)(2)
    ($000s, except per
     unit amounts)                 March 31    June 30   Sept. 30    Dec. 31
    -------------------------------------------------------------------------
    Revenues before royalties
     and hedging                     22,441     33,663     44,510     61,056
    Cash flow from operations(1)     10,732     18,013     25,500     32,892
    Cash flow from operations
     per unit(1)
      Basic                           $0.63      $0.73      $1.04      $1.02
      Diluted                         $0.61      $0.72      $1.01      $1.00
    Net earnings (loss)               1,030      3,130      6,502      3,228
    Net earnings (loss) per unit
      Basic                           $0.06      $0.13      $0.26      $0.10
      Diluted                         $0.06      $0.13      $0.26      $0.10
    Net capital
     expenditures (cash)             13,161     21,316     28,651     52,843
    Distributions declared                -          -          -     17,361
    Distributions per unit(2)             -          -          -      $0.48
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) refer to "Non-GAAP Measures" in respect of the term "cash flow from
        operations" and "cash flows from operations per unit".
    (2) restated for changes in accounting policies and to reflect the
        consolidation of units effective November 2, 2005.



    Selected Annual Information

    -------------------------------------------------------------------------
    Years Ended December 31,
    ($000s, except per unit amounts)              2006     2005(2)    2004(2)
    -------------------------------------------------------------------------
    Revenues before royalties and hedging      220,913    161,670     67,948
    Cash flow from operations(1)                90,391     87,137     33,945
    Cash flow from operations per unit(1)
      Basic                                      $1.91      $3.53      $2.28
      Diluted                                    $1.87      $3.47      $2.23
    Net earnings (loss)                       (233,564)    13,890      8,960
    Net earnings (loss) per unit
      Basic                                     $(4.95)     $0.56      $0.60
      Diluted                                   $(4.95)     $0.55      $0.59
    Net capital expenditures (cash)             92,014    115,971     54,919
    Total assets                             1,016,658    731,129    108,339
    Total net debt                             275,816    111,129     22,158
    Long-term financial liabilities
      Obligations under capital lease                -         54          -
      Capital taxes payable                          -      1,700      1,364
      Future income taxes                      123,861    146,729     13,209
      Asset retirement obligations              26,605     10,457      3,951
      Exchangeable shares of Subsidiary          4,153      9,709          -
    Production (boe/d)                          13,861      8,672      5,048
    Distributions declared                     124,355     17,361          -
    Distributions per unit(2)                    $2.64      $0.48          -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) refer to "Non-GAAP Measures" in respect of the term "cash flow from
        operations" and "cash flows from operations per unit".
    (2) restated for changes in accounting policies and to reflect the
        consolidation of units effective November 2, 2005.



    TRUE ENERGY TRUST
    CONSOLIDATED BALANCE SHEETS
    As at December 31
    -------------------------------------------------------------------------

    ($000s)                                                2006         2005
    -------------------------------------------------------------------------
    ASSETS
    Current assets
      Accounts receivable                           $    73,199  $    57,276
      Deposits and prepaid expenses                       7,928        1,806
                                                    -------------------------
                                                         81,127       59,082
    Property, plant and equipment (note 4)              931,979      600,077
    Deferred financing charges (note 7)                   3,552            -
    Goodwill (note 5)                                         -       71,970
                                                    -------------------------
    Total assets                                    $ 1,016,658  $   731,129
                                                    -------------------------
                                                    -------------------------

    LIABILITIES
    Current liabilities
      Accounts payable and accrued liabilities      $   107,431  $    88,270
      Distribution payable to unitholders                 8,433        8,677
      Capital taxes payable                               1,513        1,641
      Current portion of obligations
       under capital lease (note 8)                         111          258
      Bank debt (note 6)                                      -       71,365
                                                    -------------------------
                                                        117,488      170,211
    Obligations under capital lease (note 8)                  -           54
    Long-term debt (note 6)                             157,904            -
    Capital taxes payable                                     -        1,700
    Convertible debentures (note 7)                      81,551            -
    Asset retirement obligations (note 9)                26,605       10,457
    Future income taxes (note 14)                       123,861      146,729
                                                    -------------------------
    Total liabilities                                   507,409      329,151
                                                    -------------------------

    NON-CONTROLLING INTEREST
      Exchangeable shares of subsidiary (note 10)         4,153        9,709

    UNITHOLDERS' EQUITY
      Unitholders' capital (note 11)                    876,904      418,968
      Equity component of convertible
       debentures (note 7)                                5,119            -
      Contributed surplus (note 12)                      12,818        5,127
      Deficit                                          (389,745)     (31,826)
                                                    -------------------------
    Total unitholders' equity                           505,096      392,269
                                                    -------------------------
    Total liabilities and unitholders' equity       $ 1,016,658  $   731,129
                                                    -------------------------
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    COMMITMENTS (note 17)
    SUBSEQUENT EVENT (note 19)

    See accompanying notes to the consolidated financial statements.



    TRUE ENERGY TRUST
    CONSOLIDATED STATEMENTS OF OPERATIONS AND DEFICIT
    For the years ended December 31

    ($000s)                                                2006         2005
    -------------------------------------------------------------------------

    REVENUES
      Petroleum and natural gas sales               $   220,913  $   161,670
      Royalties                                         (51,816)     (40,818)
      Gain (loss) on commodity contracts                  2,639         (217)
                                                    -------------------------
                                                        171,736      120,635

    EXPENSES
      Production                                         46,685       21,219
      Transportation                                      6,517        3,525
      General and administrative                         14,896        4,231
      Interest and financing charges                     10,665        1,308
      Unit-based compensation (note 12)                   6,597        5,402
      Depletion, depreciation and accretion (note 4)    138,875       61,440
      Write-down of petroleum and
       natural gas properties (note 4)                  110,000            -
      Goodwill impairment (note 5)                      169,768            -
      Plan of Arrangement costs (note 4(c))                   -        3,561
                                                    -------------------------
                                                        504,003      100,686

    EARNINGS (LOSS) BEFORE TAXES                       (332,267)      19,949

    TAXES (note 14)
      Current income taxes                                    -            7
      Capital taxes                                       3,245        3,394
      Future income taxes (recovery)                   (101,145)       2,636
                                                    -------------------------
                                                        (97,900)       6,037

    NET EARNINGS (LOSS) BEFORE
     NON-CONTROLLING INTEREST                          (234,367)      13,912

    Non-controlling interest (note 10)                     (803)          22
                                                    -------------------------
    NET EARNINGS (LOSS)                                (233,564)      13,890

    Deficit, beginning of year                          (31,826)      (6,090)
    Transfer of assets pursuant to
     Plan of Arrangement (note 3(d))                          -      (22,265)
    Distributions declared                             (124,355)     (17,361)
                                                    -------------------------

    Deficit, end of year                            $  (389,745) $   (31,826)
    -------------------------------------------------------------------------

    Net earnings (loss) per trust unit (note 15)
      Basic                                         $     (4.95) $      0.56
      Diluted                                       $     (4.95) $      0.55
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    See accompanying notes to the consolidated financial statements.



    TRUE ENERGY TRUST
    CONSOLIDATED STATEMENTS OF CASH FLOWS
    For the years ended December 31
    ($000s)                                                2006         2005
    -------------------------------------------------------------------------

    Cash provided by (used in):
    CASH FLOW FROM OPERATING ACTIVITIES
    Net earnings (loss)                             $  (233,564) $    13,890
    Items not involving cash:
      Non-controlling interest (note 10)                   (803)          22
      Depletion, depreciation and accretion (note 4)    138,875       61,440
      Write-down of petroleum and
       natural gas properties (note 4)                  110,000            -
      Goodwill impairment (note 5)                      169,768            -
      Unit-based compensation (note 12)                   6,597        7,552
      Amortization of deferred financing charges            437            -
      Accretion on convertible debentures                   420            -
      Future income taxes (recovery) (note 14)         (101,145)       2,636
      Capital taxes  (note 14)                             (194)       1,597
                                                    -------------------------
                                                         90,391       87,137
      Change in non-cash working capital (note 13)       36,925       21,665
                                                    -------------------------
                                                        127,316      108,802
                                                    -------------------------

    CASH FLOW FROM (USED IN) FINANCING ACTIVITIES
      Increase in bank debt                              19,166       15,169
      Obligations under capital lease                      (201)         (32)
      Issuance of convertible debentures (note 7)        86,250            -
      Deferred financing charges (note 7)                (3,989)           -
      Issuance of common shares                               -       11,397
      Share and unit issue costs                         (2,410)      (3,462)
      Payment of cash component of distributions        (81,991)     (10,766)
                                                    -------------------------
                                                         16,825       12,306
      Change in non-cash working capital (note 13)          143      (10,664)
                                                    -------------------------
                                                         16,968        1,642
                                                    -------------------------

    CASH FLOW FROM (USED IN) INVESTING ACTITIVIES
      Additions to property, plant and equipment       (116,528)    (115,971)
      Corporate transaction costs (note 3)               (2,083)      (4,174)
      Proceeds on sale of property,
       plant and equipment                               24,514        5,012
                                                    -------------------------
                                                        (94,097)    (115,133)
      Change in non-cash working capital (note 13)      (55,405)       4,689
                                                    -------------------------
                                                       (149,502)    (110,444)
                                                    -------------------------

    Cash acquired on corporate acquisition (note 3)       5,218            -

    Change in cash                                            -            -

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

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

    See accompanying notes to the consolidated financial statements.



    NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
    Years ended December 31, 2006 and 2005
    -------------------------------------------------------------------------

    1.  STRUCTURE OF THE TRUST

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

        Pursuant to the TKE Arrangement, True Energy Inc. and TKE Energy
        Trust ("TKE") entered into a business combination whereby True Energy
        Inc. acquired TKE in a reverse takeover, thus creating True Energy
        Trust and a publicly listed exploration focused company, Vero Energy
        Inc. ("Vero"). The former shareholders of True Energy Inc. control
        approximately 71% of the Trust and substantially all of the Trust's
        new management team is the former management of True Energy Inc.

        The TKE Arrangement resulted in True Energy Inc. shareholders
        receiving, for each True Share held: (i) 0.5 of a pre-consolidated
        trust units (0.25 of a post-consolidated trust unit); (ii) 0.10 of a
        Vero Share; and (iii) one Vero arrangement warrant.

        Concurrent with approval of the TKE Arrangement, TKE received
        approval from Unitholders at the TKE unitholder meeting to
        consolidate its existing outstanding trust units on a one-for-two
        (1:2) basis and to change its name to "True Energy Trust". Under the
        TKE Arrangement, True Energy Inc. and TKE Energy Inc. were
        amalgamated to form the new administrator of the Trust under the name
        True Energy Inc.

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

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

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

        The conversion of True Energy Inc. to the Trust has been accounted
        for as a reverse takeover of TKE and a continuity of interests of
        True Energy Inc. Prior to the TKE Arrangement on November 2, 2005,
        the consolidated financial statements included the accounts of True
        Energy Inc. and its subsidiaries and partnership. After giving effect
        to the TKE Arrangement, the consolidated financial statements include
        the accounts of the Trust, its subsidiaries and partnerships.

        The term "units" has been used to identify both the trust units and
        the exchangeable shares of the Trust issued on or after November 2,
        2005 as well as the common shares of True Energy Inc. outstanding
        prior to the TKE Arrangement on November 2, 2005.

        On January 15, 2007, the Trust announced its intention to convert
        into an intermediate exploration and production company as disclosed
        in note 19 of these financial statements.

    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 and directly related overhead.
           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 to capitalized costs 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 net of Alberta
           Royalty Tax Credits, capital and income taxes, 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 unproved properties is excluded from the impairment
           test described above and subject to a separate impairment test.

        g. Goodwill

           Goodwill is recognized on corporate 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. Cash and Cash Equivalents

           Cash and cash equivalents include bank balances and highly liquid
           temporary money market instruments with original maturities of
           three months or less.

        i. 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.

        j. Prepaid Contracts

           Advance payments received under prepaid contracts for oil and gas
           not delivered are deferred and are recognized as revenue when
           deliveries are made. Revenue is recognized on a straight-line
           basis by dividing the advance payment by the total contracted
           volumes.

        k. 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.

        l. 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. As the Trust distributes all of
           its taxable income to the unitholders and meets the requirements
           of the Income Tax Act (Canada) applicable to the Trust, no
           provision for income taxes has been made in the Trust.

        m. 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.

        n. Derivative Financial Instruments

           The Trust uses derivative financial instruments from time to time
           to hedge its exposure to commodity price and foreign exchange
           fluctuations. The Trust does not enter into derivative financial
           instruments for trading or speculative purposes.

           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 reviews the derivative financial
           instruments to determine their effectiveness as hedges, both at
           inception and over the term of the instruments.

           The Trust enters into hedges of its exposure to petroleum and
           natural gas commodity prices by entering into crude oil and
           natural gas swap contracts, options or collars, when it is deemed
           appropriate. If the derivatives are deemed not to qualify as
           hedges under Canadian accounting standards, the fair values of the
           derivative financial instruments are recorded as assets or
           liabilities on the balance sheet. Otherwise, the derivative
           contracts are accounted for as hedges and are not recognized on
           the balance sheet. Realized gains and losses on these contracts
           are then recognized in petroleum and natural gas revenue and cash
           flows in the same period in which the revenues associated with the
           hedged transaction are recognized. Premiums paid or received are
           deferred and amortized to earnings over the term of the contract.

        o. 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.

        p. 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.

    3.  ACQUISITIONS/DISPOSITIONS

        a. Acquisition of Prairie Schooner Petroleum Ltd.

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

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

           The purchase price equation is as follows:

           ($000's)
           ------------------------------------------------------------------
           Cost of acquisition:
             Trust units issued                                  $   342,870
             True transaction costs                                    1,563
           ------------------------------------------------------------------
                                                                 $   344,433
           ------------------------------------------------------------------
           Allocated at estimated fair values:
             Accounts receivable                                 $    32,295
             Deposits and prepaid expenses                             1,075
             Property, plant and equipment                           435,346
             Goodwill (note 5)                                        71,601
             Bank debt                                               (67,373)
             Accounts payable and accrued liabilities                (42,636)
             Future income taxes                                     (73,467)
             Asset retirement obligations                            (12,408)
           ------------------------------------------------------------------
                                                                 $   344,433
           ------------------------------------------------------------------
           ------------------------------------------------------------------

        b. Acquisition of Shellbridge Oil & Gas, Inc.

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

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

           The purchase price equation is as follows:

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

        c. Acquisition of TKE Energy Trust

           On November 2, 2005 True Energy Inc. and TKE entered into a
           business combination whereby True Energy Inc. acquired TKE in a
           reverse takeover, changing to True Energy Trust, and a publicly
           listed exploration focused company, Vero Energy Inc., pursuant to
           a Plan of Arrangement. The former shareholders of True Energy Inc.
           controlled approximately 71% of the Trust and substantially all of
           the former management of True Energy Inc. formed the Trust's new
           management team.

           The TKE Arrangement resulted in True shareholders receiving, for
           each True Share held: (i) 0.5 of a pre-consolidated trust units
           (0.25 of a post-consolidated trust unit); (ii) 0.10 of a Vero
           Share; and (iii) one Vero arrangement warrant.

           To effect the TKE Arrangement, for accounting purposes only, all
           of the issued and outstanding trust units, being 20,708,128 trust
           units, of TKE were treated as acquired by True Energy Inc. The
           transaction value was based upon the adjusted weighted average
           trading price of True Energy Inc. common shares for the two days
           prior to the transaction announcement on August 23, 2005, of
           $5.04, plus the assumption of TKE's debt. The transaction was
           accounted for using the purchase method, with the excess purchase
           price over the fair value of net identifiable assets acquired of
           approximately $42.4 million being allocated to goodwill.

           The purchase equation was adjusted during 2006 to reflect certain
           net under accruals for operating income and capital expenditures
           and transaction costs and adjustments from tax assessments
           relating to the period prior to November 2, 2005. As a result,
           transactions costs were increased by $0.5 million, total net
           accounts receivable was reduced by $0.7 million, future income tax
           liability was increased by $1.0 million and goodwill was increased
           by $2.2 million.

           The purchase price equation is as follows:

           ($000s)
           ------------------------------------------------------------------
           Cost of acquisition:
             Trust units issued                                  $   196,214
             Transaction costs                                         2,505
           ------------------------------------------------------------------
                                                                 $   198,719
           ------------------------------------------------------------------
           Allocated at estimated fair values:
             Accounts receivable                                 $    10,833
             Deposits and prepaid expenses                             1,152
             Property, plant and equipment                           291,706
             Goodwill (note 5)                                        44,573
             Accounts payable and accrued liabilities                (17,912)
             Bank debt                                               (32,077)
             Distribution payable                                     (2,382)
             Obligation under capital lease                             (343)
             Non-controlling interest                                (10,351)
             Future income taxes                                     (80,320)
             Asset retirement obligations                             (6,160)
           ------------------------------------------------------------------
                                                                 $   198,719
           ------------------------------------------------------------------
           ------------------------------------------------------------------

           In accordance with the TKE Arrangement, all stock options of True
           Energy Inc. vested and were exercised or expired resulting in
           recognition of previously unamortized stock-based compensation of
           $2.2 million being charged to Plan of Arrangement costs in
           earnings for 2005. In addition, the Trust incurred $1.4 million in
           severance and retention costs that are included in Plan of
           Arrangement costs within earnings for 2005.

        d. Disposition to Vero Energy Inc.

           Under the TKE Arrangement, True Energy Inc. transferred to Vero
           certain prospective natural gas weighted assets and undeveloped
           land at their net book value. A future tax asset was transferred
           as the result of disposing of petroleum and natural gas properties
           with a net book value of $26.9 million compared to tax pools of
           $27.9 million. The details are as follows:

           ($000s)
           ------------------------------------------------------------------
           Petroleum and natural gas properties                  $    26,880
           Asset retirement capital                                      318
           Future income tax asset                                       384
           ------------------------------------------------------------------
           Total assets transferred                                   27,582
           Asset retirement obligation                                  (318)
           Bank indebtedness assumed                                  (5,000)
           ------------------------------------------------------------------
           Net assets transferred and charged to deficit         $    22,264
           ------------------------------------------------------------------
           ------------------------------------------------------------------

           In conjunction with the TKE Arrangement, the Trust entered into a
           Transitional Services Agreement ("Agreement") with Vero where the
           Trust provided personnel and certain administrative and technical
           services in connection with the management, development,
           exploitation and operation of the assets of Vero. The initial term
           of the Agreement was for a period of 3 months after the effective
           date of the TKE Arrangement, however, this Agreement has been
           extended to April 1, 2006, at which time it expired. The Trust
           provided these services to Vero on an expense reimbursement basis,
           based on Vero's monthly capital activity and production levels
           relative to the combined capital activity and production levels of
           both the Trust and Vero. Total expenses reimbursed by Vero for the
           three month period ended March 31, 2006 were $0.1 million.

        e. Acquisition of Meridian Energy Corporation

           Effective March 15, 2005, True Energy Inc. acquired all of the
           issued and outstanding common shares of Meridian Energy
           Corporation ("Meridian"), a public company, involved in the
           exploration, development and production of oil and natural gas in
           central Alberta. The consideration offered was $0.6 million and
           0.91 of a True Energy Inc. common share for each Meridian common
           share resulting in 35,111,184 True Energy Inc. shares issued as at
           March 31, 2005 and an additional 638,747 shares issued in April
           and June 2005. The value of the transaction, based on an adjusted
           average share price for the common shares of True Energy Inc. of
           $4.20 at January 19, 2005, was $152.2 million (including
           $1.4 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 $29.6 million, which
           was reflected as goodwill. The accounts include the results of
           Meridian effective March 15, 2005, the date the majority of
           Meridian shares were taken up and exchanged for True Energy Inc.
           common shares.

           The purchase equation was adjusted at December 31, 2005 to reflect
           revised estimates for tax information regarding expected temporary
           difference reversals. As a result, the future tax liability was
           decreased by $3.6 million and goodwill was also decreased by the
           same amount.

           The purchase price equation is as follows:

           ($000's)
           ------------------------------------------------------------------
           Cost of acquisition:
             Common shares issued                                $   150,150
             True transaction costs                                    1,411
             Cash to shareholders                                        620
           ------------------------------------------------------------------
                                                                 $   152,181
           ------------------------------------------------------------------
           Allocated at estimated fair values:
             Accounts receivable                                 $    15,186
             Deposits and prepaid expenses                                89
             Property, plant and equipment                           183,744
             Goodwill (note 5)                                        29,577
             Accounts payable and accrued liabilities                (14,119)
             Bank debt                                               (11,389)
             Future income taxes                                     (49,915)
             Asset retirement obligations                               (992)
           ------------------------------------------------------------------
                                                                 $   152,181
           ------------------------------------------------------------------
           ------------------------------------------------------------------


    4.  PROPERTY, PLANT AND EQUIPMENT

        ($000s)
        ---------------------------------------------------------------------
                                                     Accumulated
                                                   depletion and    Net book
        December 31, 2006                     Cost  depreciation       value
        ---------------------------------------------------------------------
        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
        ---------------------------------------------------------------------

        December 31, 2005
        ---------------------------------------------------------------------
        Petroleum and natural
         gas properties                $   735,788  $   136,539  $   599,249
        Office furniture
         and equipment                       1,461          633          828
        ---------------------------------------------------------------------
                                       $   737,249  $   137,172  $   600,077
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


        The Trust has excluded from the depletion calculation $99.2 million
        (2005 - $36.3 million) for undeveloped properties and $49.3 million
        (2005 - $24.1 million) for undeveloped land.

        In 2006, the Trust capitalized $2.6 million (2005 - $2.3 million) of
        general and administrative expenses and $1.1 million (2005 -
        $1.4 million) of unit-based compensation expense directly related to
        exploration and development activities.

        The Trust performed a ceiling test calculation at December 31, 2006
        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. As a result of performing this test, a
        ceiling test impairment loss of $110.0 million has been recorded as a
        write-down of petroleum and natural gas properties in the
        consolidated statements of operations and is 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, 2006 were:

        ---------------------------------------------------------------------
                                      Medium/Light
        Year                Heavy Oil          Oil  Natural Gas         NGLs
                               ($/bbl)      ($/bbl)       ($mcf)      ($/bbl)
        ---------------------------------------------------------------------
        2007              $     38.69  $     68.23  $      7.44  $     56.57
        2008                    39.58        68.14         7.90        56.48
        2009                    38.09        64.66         7.82        53.74
        2010                    37.33        62.11         7.81        51.88
        2011                    36.42        60.30         7.95        50.56
        2012                    37.82        61.43         8.16        51.66
        2013                    38.77        62.60         8.32        53.01
        2014                    39.81        64.70         8.47        54.40
        2015                    40.78        66.08         8.65        55.66
        2016                    41.99        67.51         8.81        56.91
        2017                    43.55        68.76         8.99        58.14
        2018                    44.98        70.09         9.17        59.40
        Remaining               53.81        78.70        10.83        70.88
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


    5.  GOODWILL

        ---------------------------------------------------------------------
                                                     Years ended December 31,
        ($000s)                                            2006         2005
        ---------------------------------------------------------------------
        Balance, beginning of period                $    71,970  $         -
        Prairie Schooner acquisition (note 3a)           71,601            -
        Shellbridge acquisition (note 3b)                24,017            -
        TKE acquisition (note 3c)                         2,180       42,393
        Meridian acquisition (note 3e)                        -       29,577
        Goodwill impairment recognized                 (169,768)           -
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Balance, end of period                      $         -  $    71,970
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


        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 has been recorded as a
        non-cash charge to income as of December 31, 2006.

    6.  LONG-TERM DEBT

        The Trust has a $15 million demand operating facility provided by one
        Canadian bank and $210 million extendible revolving term credit
        facility syndicated by the Canadian chartered bank, a U.S. bank, a
        foreign bank and one institutional lender. Amounts borrowed under the
        credit facility bear interest at a floating rate based on the
        applicable Canadian prime rate, U.S. base rates, LIBOR rates, plus
        between 0% and 1.95%, depending on the types of borrowings and the
        Trust's debt to cash flow ratio. Security is provided by a
        $400 million debenture containing a first ranking security interest
        on all of the Trust's assets. The credit facility is secured against
        all the assets of True Energy Inc., the Trust and all material
        subsidiaries. True has provided a negative pledge and undertaking to
        provide fixed charges over major petroleum and natural gas reserves
        in certain circumstances. A standby fee is charged on between 0.125%
        and 0.400% on the undrawn portion of the facility, depending on the
        Trust's debt to cash flow ratio. The borrowing base is currently
        scheduled for renewal on or before March 31, 2007. As at December 31,
        2006, there was $4.9 million outstanding under the operating facility
        and $153.0 million outstanding under the revolving term credit
        facility, which leaves approximately $67.1 million under the
        facility.

        The revolving period on the new revolving term credit facility ends
        on June 29, 2007, unless extended for a further 364 day period.
        Should the facilities not be renewed they convert to 366 day
        non-revolving term facilities on the renewal date. Payment will not
        be required under the revolving term facility for more than 365 days
        from the balance sheet date and as at December 31, 2006 there is
        sufficient availability under the revolving term credit facility to
        also cover the operating facility and, as such, the entire credit
        facility has been classified as long-term.

    7.  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 are amortized over
        the term of the debentures. The debt component of the convertible
        debentures will accrete up to the principal balance at maturity. The
        accretion, amortization of issue costs 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 year ended December 31, 2006:

        Convertible debentures
        ---------------------------------------------------------------------
                                                           Debt       Equity
                                         Number of    Component    Component
                                        Debentures       ($000s)      ($000s)
        ---------------------------------------------------------------------
        Issued on June 15, 2006             86,250  $    81,131  $     5,119
        Accretion                                -          420  $         -
        ---------------------------------------------------------------------
        Balance, December 31, 2006          86,250  $    81,551  $     5,119
        ---------------------------------------------------------------------


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

        Deferred financing charges ($000s)
        ---------------------------------------------------------------------
        Costs incurred                                           $     3,989
        Less amortization in the period                                 (437)
        ---------------------------------------------------------------------
        Balance, December 31, 2006                               $     3,552
        ---------------------------------------------------------------------


    8.  OBLIGATIONS UNDER CAPITAL LEASE

        Leases relating to gas compression and other equipment with initial
        costs totaling $1.2 million (2005 - $1.2 million) have been
        classified as capital leases and are included in property, plant and
        equipment. The remaining capital lease obligation of $111 thousand
        has an implicit interest rate consisting of a variable Bankers
        Acceptance rate + 3.7%; and will be repaid in 2007.

    9.  ASSET RETIREMENT OBLIGATIONS

        The Trust's asset retirement obligations result from net ownership
        interests in petroleum and natural gas assets including well sites,
        gathering systems and processing facilities. The Trust estimates the
        total undiscounted amount of cash flows required to settle its asset
        retirement obligations is approximately $74.7 million which will be
        incurred between 2007 and 2053. A credit-adjusted risk-free rate of
        8.0 percent and an inflation rate of 2.2 percent were used to
        calculate the fair value of the asset retirement obligation.

        ---------------------------------------------------------------------
        ($000s)                                            2006         2005
        ---------------------------------------------------------------------
        Asset retirement obligation,
         beginning of year                          $    10,457  $     3,951
        Liabilities acquired through
         corporate acquisitions                          13,704        7,152
        Liabilities incurred                              1,210        1,717
        Changes in prior period estimates                   810       (2,381)
        Liabilities released on dispositions               (641)        (318)
        Accretion expense                                 1,065          336
        ---------------------------------------------------------------------
        Asset retirement obligation, end of year    $    26,605  $    10,457
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


    10. EXCHANGEABLE SHARES OF SUBSIDIARY

        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

        ---------------------------------------------------------------------
                                    2006                      2005
                                            Amount                    Amount
                               Number       ($000s)      Number       ($000s)
        ---------------------------------------------------------------------
        Balance, beginning
         of year              788,558  $     9,709            -  $         -
        TKE shares acquired
         under Arrangement          -            -      843,304       10,351
        Non-controlling
         interest expense           -         (803)           -           22
        Exchanged for
         trust units         (385,022)      (4,753)     (54,746)        (664)
        ---------------------------------------------------------------------
        Balance, end of year  403,536  $     4,153      788,558  $     9,709
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        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 exchange ratio was
        adjusted November 2, 2005 to reflect the consolidation of trust units
        on a 1 for 2 trust unit basis. The exchangeable shares are not
        eligible for cash distributions; however cash distributions will
        increase the exchange ratio.

        As at December 31, 2006, the exchange ratio was 0.71107 (2005 -
        0.57686).

        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.

    11. UNITHOLDERS' CAPITAL

        a. Trust Units of True Energy Trust

           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.

    -------------------------------------------------------------------------
                                    2006                      2005
                                            Amount                    Amount
                               Number       ($000s)      Number       ($000s)
    -------------------------------------------------------------------------
    Balance, beginning
     of year               36,176,196  $   418,968            -  $         -
    Units issued for True
     Common Shares                  -            -   51,550,302      223,686
    TKE units acquired
     under Arrangement              -            -   20,708,128      196,214
                          ---------------------------------------------------
                           36,176,196      418,968   72,258,430      419,900
                          ---------------------------------------------------
    Balance after 1:2
     consolidation         36,176,196      418,968   36,129,215      419,900
    Issued to acquire
     Prairie Schooner      25,759,563      341,089            -            -
     (net of issue costs
     of $1.8 million)
    Issued to acquire
     Shellbridge            4,389,366       67,669            -            -
     (net of issue costs
     of $0.6 million)
    Exchangeable shares
     converted                231,035        4,753       30,869          664
    Units issued
     pursuant to DRIP       3,574,185       42,608       16,112          301
    Issued to acquire
     property interest        145,358        1,817            -            -
    Unit issue costs, (net
     of $0.4 million tax)           -            -            -       (1,897)
    -------------------------------------------------------------------------
    Balance, end of year   70,275,703  $   876,904   36,176,196  $   418,968
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

        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 year ended and as at December 31, 2006.

           Unit Rights Continuity
           ------------------------------------------------------------------
                                               Average Exercise
                                                        Price(a)      Number
           ------------------------------------------------------------------
           Balance, December 31, 2004               $         -            -
           Granted                                  $     18.27    3,159,000
           Forfeited                                $         -            -
           ------------------------------------------------------------------
           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
           ------------------------------------------------------------------

    Unit Rights Outstanding
    -------------------------------------------------------------------------
    Exercise                     Outstanding                 Exercisable
    Price      Exercise             Exercise   Remain-              Exercise
    Before        Price            Price Net       ing             Price Net
    Price        Net of        At   of Price  Contrac-        At    of Price
    Reduc-        Reduc-  Dec. 31,     Reduc-     tual   Dec. 31,     Reduc-
    tions         tions      2006    tions(b)   Life(b)     2006     tions(b
    -------------------------------------------------------------------------
    $10.58 -   $10.15 - 1,539,000    $ 10.40      4.7           -       N/A
     $12.53     $12.00

    $13.74 -   $12.63 -   681,000    $ 13.05      4.5           -       N/A
     $14.83     $13.80

    $15.92 -   $14.41 -   227,500    $ 14.61      4.3      29,166     14.93
     $16.70     $15.16

    $18.25 -   $16.15 - 2,982,331    $ 16.36      3.9   1,919,888     16.27
     $20.98     $19.10
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    $10.58 -   $10.30 - 5,429,831    $ 14.18      4.2   1,949,054     16.25
     $20.98     $19.10
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (a) Exercise prices reflect grant prices less reduction in exercise
        prices.
    (b) Based on weighted average unit rights outstanding.

        c. Employee Trust Unit Savings Plan

           Effective October 1, 2006, the Trust introduced an employee trust
           unit savings plan for the benefit of all employees. Under the
           savings plan, employees may elect to contribute up to 10 percent
           of their salary and contributions are used to fund the acquisition
           of trust units. The Trust matches employee contributions at a rate
           of $1.00 for each $1.00 contributed. Trust units are purchased in
           the open market by the plan administrator, an investment firm, on
           behalf of the participants in the plan. For the first three months
           of the plan ended December 31, 2006, the Trust matched
           $0.1 million under the plan.

        d. Common Shares of True Energy Inc.

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

           Issued:
           ------------------------------------------------------------------
                                                      Number of       Amount
                                                         Shares       ($000s)
           ------------------------------------------------------------------
           Balance, December 31, 2004                62,097,979  $    60,229
           ------------------------------------------------------------------
           Options exercised                          5,252,694       11,397
           Issued on acquisition of Meridian
            Energy Corporation                       35,749,931      150,150
           Share issue costs (net of future
            income taxes of $0.4 million)                     -         (671)
           Tax effect of 2004 flow-through shares             -       (2,115)
           Transfer from contributed surplus to
            share capital on exercise of options              -        4,696
                                                    -------------------------
           Balance prior to Plan of Arrangement     103,100,604      223,686
                                                    -------------------------
           Balance after 2:1 consolidation           51,550,302      223,686
           Exchanged for Trust units                (51,550,302)    (223,686)
           ------------------------------------------------------------------
           Balance, December 31, 2005                         -  $         -
           ------------------------------------------------------------------
           ------------------------------------------------------------------


        e. Stock Options of True Energy Inc.

           The following table summarizes the changes in stock options
           outstanding for the year ended December 31, 2005.

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

                                                                   Weighted-
                                                                     Average
                                                                    Exercise
                                                        Options        Price
           ------------------------------------------------------------------
           Outstanding, December 31, 2004             3,958,567  $      1.35
           -----------------------------------------------------
           Cancelled                                   (417,873)        1.95
           Granted                                    1,712,000         4.01
           Exercised                                 (5,252,694)        2.17
           -----------------------------------------------------
           Outstanding, December 31, 2005                     -  $         -
           -----------------------------------------------------
           -----------------------------------------------------


    12. CONTRIBUTED SURPLUS

        ---------------------------------------------------------------------
                                                      Year ended December 31
        ($000s)                                            2006         2005
        ---------------------------------------------------------------------
        Balance, beginning of year                  $     5,127  $       877
        Unit-based compensation expense                   7,691        5,127
        Stock-based compensation expense                      -        3,819
        Transfer to share capital
         on exercise of options                               -       (4,696)
        ---------------------------------------------------------------------
        Balance, end of year                        $    12,818  $     5,127
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


        a. Unit-based Compensation

           During 2006, the Trust granted 3,022,500 unit incentive rights to
           employees and directors. In 2006 the Trust recorded unit-based
           compensation of $7.7 million, of which $1.1 million was
           capitalized to property, plant and equipment.

           The fair values of all incentive rights granted are estimated on
           the date of grant using the Black-Scholes option-pricing model.
           The weighted average fair market value of incentive rights granted
           during the year ended December 31, 2006 and the assumptions used
           in their determination are as noted below.

           ------------------------------------------------------------------
                                                     Year ended December 31,
                                                                        2006
           ------------------------------------------------------------------
           Assumptions:
             Risk free interest rate (%)                                   4
             Expected life (years)                                         5
             Expected volatility (%)                                      24
           ------------------------------------------------------------------
           Results:
             Weighted average fair value of incentive rights granted  $ 4.27
           ------------------------------------------------------------------
           ------------------------------------------------------------------


        b. Stock-based Compensation

           The expense recognized applies to stock options granted in 2003
           and thereafter. During the year ended December 31, 2006, the Trust
           granted nil (2005: 1,712,000) stock options to employees,
           consultants, officers and directors.

           For stock options granted in 2002 and prior years, the Trust
           elected to continue accounting for the related compensation
           expense on the intrinsic value at the grant date. Accordingly, net
           income for 2002 and subsequent years remains unchanged with
           respect to stock options granted in 2002.

           The Trust continues to disclose the pro forma earnings impact of
           stock options granted in 2002. If the fair value method had been
           used for options granted in 2002, the Trust's net earnings and net
           earnings per share for the years ended December 31, 2005 would
           approximate the following pro forma amounts:

           ------------------------------------------------------------------
           ($000s, except per                   Year ended December 31, 2005
            trust unit amounts)
           ------------------------------------------------------------------
           Net Earnings:
             As reported                                         $    13,890
             Pro forma                                           $    13,865
           ------------------------------------------------------------------
           Net Earnings per trust unit:
             As reported                                         $      0.56
             Pro forma                                           $      0.56
           ------------------------------------------------------------------
           Diluted:
             As reported                                         $      0.55
             Pro forma                                           $      0.55
           ------------------------------------------------------------------
           ------------------------------------------------------------------


           The fair value of each option granted is estimated on the date of
           grant using the Black-Scholes option pricing model with weighted
           average assumptions and resulting values for grants as follows:

           ------------------------------------------------------------------
                                                Year ended December 31, 2005
           ------------------------------------------------------------------
           Assumptions:
             Risk free interest rate (%)                                2.80
             Expected life (years)                                       5.0
             Expected volatility (%)                                      44
           ------------------------------------------------------------------
           Results:
             Weighted average fair value of options granted      $      1.69
           ------------------------------------------------------------------
           ------------------------------------------------------------------


    13. SUPPLEMENTAL CASH FLOW INFORMATION

        Cash Interest and Taxes Paid
        ---------------------------------------------------------------------
                                                     Year ended December 31,
        ($000s)                                            2006         2005
        ---------------------------------------------------------------------
        Cash paid:
        Interest                                    $    10,598  $     1,308
        Taxes (net of refunds)                      $     4,476  $     1,659
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


        Change in Non-cash Working Capital
        ---------------------------------------------------------------------
                                                     Year ended December 31,
        ($000s)                                            2006         2005
        ---------------------------------------------------------------------
        Changes in non-cash working capital items:
          Accounts receivable                       $    25,633  $   (18,671)
          Deposits and prepaid expenses                  (4,887)        (154)
          Accounts payable and accrued liabilities      (37,449)      34,179
          Capital taxes                                  (1,634)         336
        ---------------------------------------------------------------------
                                                    $   (18,337) $    15,690
        ---------------------------------------------------------------------

        Changes related to operating activities     $    36,925  $    21,665
        Changes related to financing activities             143      (10,664)
        Changes related to investing activities         (55,405)       4,689
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
                                                    $   (18,337) $    15,690
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


        In December 2006, the Trust closed on an asset exchange agreement
        whereby certain property interests of the Trust in Saskatchewan were
        exchanged for other property interests in Saskatchewan from another
        oil and gas producer. The exchange was a non-cash transaction that
        was valued at approximately $8.4 million as agreed by the parties.

    14. INCOME TAXES

        The Trust is a mutual fund trust as defined under the Income Tax Act
        (Canada). All taxable income earned by the Trust has been allocated
        to unitholders and such allocations are deducted for income tax
        purposes. The Trust does not recognize any future income tax assets
        or liabilities on "temporary differences" (difference between the
        accounting basis and tax basis of assets and liabilities) in the
        Trust. As at December 31, 2006, this "temporary difference" (tax
        basis exceeds accounting basis) is $7.1 million (2005: $4.1 million).
        The Trust's subsidiaries are subject to income taxation and provide
        income tax obligations based upon statutory corporate rates.

        As at December 31, 2006, the Trust's subsidiaries have tax basis of
        approximately $478 million that is available to shelter future
        taxable income. Included in this tax basis are estimated non-capital
        loss carry forwards of approximately $5.6 million that expire in
        years through 2026. In addition, the Trust has approximately
        $20 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 35.7% (2005: 39.5%) to earnings before income
        taxes. This difference results from the following items:

        ---------------------------------------------------------------------
                                                     Year ended December 31,
        ($000s)                                            2006         2005
        ---------------------------------------------------------------------
        Expected income tax expense (recovery)      $  (118,645)    $  7,878
        Amount in Trust income                          (33,757)      (7,090)
        Goodwill impairment                              60,620            -
        Crown royalties and charges                       5,032        5,044
        Resource allowance                               (4,292)      (4,836)
        Unit based compensation expense                   2,356        3,533
        Change in enacted tax rates                     (11,548)      (1,507)
        Other                                              (911)        (379)
        ---------------------------------------------------------------------
        Total tax expense (recovery)                   (101,145)       2,643
        ---------------------------------------------------------------------

        Future income tax expense (recovery)           (101,145)       2,636
        Current income tax                                    -            7
        ---------------------------------------------------------------------
        Total income tax expense (recovery)            (101,145)       2,643
        Capital tax expense                               3,245        3,394
        ---------------------------------------------------------------------
        Total tax expense (recovery)                 $  (97,900) $     6,037
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


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

        ---------------------------------------------------------------------
        ($000s)                                            2006         2005
        ---------------------------------------------------------------------
        Future income tax liabilities:
          Petroleum and natural gas properties      $  (120,203) $  (132,899)
          Partnership deferrals                         (16,374)     (28,354)
          Other                                            (565)        (565)
        Future income tax assets:
          Future site restoration/asset
           retirement obligation                          7,899        3,712
          Share issue costs                               2,207        2,166
          Non-capital losses                              1,856        8,595
          Attributed Canadian Royalty Income              1,209          523
          Other                                             110           93
        ---------------------------------------------------------------------
        Net future income tax liability             $  (123,861) $  (146,729)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


    15. PER TRUST UNIT AMOUNTS

        ---------------------------------------------------------------------
                                                    Years ended December 31,
                                                           2006         2005
        ---------------------------------------------------------------------
        Basic trust units outstanding                70,275,703   36,176,196
        Dilutive effect of:
          Trust unit incentive rights outstanding     5,429,831    3,159,000
          Units issuable for exchangeable shares        286,942      454,887
          Units issuable for convertible debentures   5,390,625            -
        ---------------------------------------------------------------------
        Diluted trust units outstanding              81,383,101   39,790,083
        ---------------------------------------------------------------------
        Weighted average trust units outstanding     47,217,258   24,678,198
        Dilutive effect of exchangeable shares,
         trust unit incentive plan and
         convertible debentures(1)                            -      454,887
        ---------------------------------------------------------------------
        Diluted weighted average
         trust units outstanding                     47,217,258   25,133,085
        ---------------------------------------------------------------------
        (1) A total of 286,942 (2005: nil) exchangeable shares, 5,429,831
            (2005: 3,159,000) trust incentive units and 5,390,625 (2005: nil)
            trust units issuable pursuant to the conversion of convertible
            debentures were excluded from the calculation for the year ended
            December 31, 2006 as they were not dilutive.


    16. RELATED PARTY TRANSACTIONS

        During the year ended December 31, 2006, the Trust paid $1.2 million
        (2005: $1.1 million) for legal services provided by a firm in which a
        current director is a partner. These payments were made in the normal
        course of operations, on commercial terms, and therefore were
        recorded at the exchange amount.

    17. COMMITMENTS

        As at December 31, 2006, the Trust has committed to drill 13 wells in
        Alberta and 16 wells in Saskatchewan by the end of 2007 pursuant to
        various farm-in agreements with oil and gas companies. Subsequent to
        year-end 2006, the Trust has further committed to drill an additional
        13 wells in Alberta and 5 in Saskatchewan. Total estimated cost to
        the Trust for these commitments is $30.2 million.

        The Trust has further committed to various corporate sponsorships
        extending to June 2010 at an estimated combined cost of up to
        $172,000.

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

        ---------------------------------------------------------------------
        ($000s)                              Gross     Expected
        Year                                Amount   Recoveries   Net amount
        ---------------------------------------------------------------------
        2007                           $     1,669  $       271  $     1,398
        2008                                 1,390          285        1,105
        2009                                 1,000          285          715
        2010                                   285          285            -
        2011                                   285          285            -
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


    18. FINANCIAL INSTRUMENTS

        a. Credit Risk

           A substantial portion of the Trust's accounts receivable are with
           customers and joint venture 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 eight 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

           The carrying amounts of financial instruments included in the
           balance sheet, other than long-term debt, approximate their fair
           value due to their short-term maturity. The long-term carrying
           value approximates fair value due to the cost of borrowing being
           at a floating rate.

        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, 2006.

        d. Commodity Risk

           The Trust seeks to reduce its exposure to commodity price risk in
           its business through the use of physical product arrangements,
           futures, and options.

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

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

    Oil put option  Jan. 1, 2007 to      800  $ 70.00 US            -     WTI
                     March 31, 2007    bbl/d

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

    Natural Gas     Sept. 1, 2006 to  10,000  $ 8.00 CDN            -  AECO C
     put option      March 31, 2007   GJ/day

    Natural Gas     Nov. 1, 2006 to    3,000  $ 8.00 CDN            -  AECO C
     put option      March 31, 2007   GJ/day

    Natural Gas     Nov. 1, 2006 to    3,000  $ 8.50 CDN  $ 10.50 CDN  AECO C
     collar          March 31, 2007   GJ/day

    Natural Gas     Nov. 1, 2006 to    2,000  $ 9.00 CDN  $ 10.95 CDN  AECO C
     collar          March 31, 2007   GJ/day

    Natural Gas     Nov. 1, 2006 to    3,000  $ 8.50 CDN  $ 10.75 CDN  AECO C
     collar          March 31, 2007   GJ/day

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

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

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

    Natural Gas     Nov. 1, 2006 to    2,000  $ 9.32 CDN  $  9.32 CDN  AECO C
     fixed           March 31, 2007   GJ/day

    Natural Gas     Nov. 1, 2006 to    3,000  $ 9.48 CDN  $  9.48 CDN  AECO C
     fixed           March 31, 2007   GJ/day

    Natural Gas     April 1, 2007 to   5,000  $ 7.00 CDN  $  7.00 CDN  AECO C
     fixed(1)        Dec. 31, 2007    GJ/day

    Natural Gas     April 1, 2007 to   5,000  $ 7.10 CDN  $  7.10 CDN  AECO C
     fixed(1)        Oct. 31, 2007    GJ/day
    -------------------------------------------------------------------------
    (1) These contracts were entered into subsequent to December 31, 2006.

        The above contracts require monthly settlement and have been
        designated as hedges in accordance with Accounting Guideline 13. As
        at December 31, 2006, the unrealized gain on the then outstanding
        commodity contracts, which changes on a daily basis, was
        $8.2 million. Included in revenue for year ended December 31, 2006
        are oil and gas net hedging gains of $2.6 million (2005: $0.2 million
        hedging loss) related to the monthly settlement of the commodity
        contracts in the period.

    19. SUBSEQUENT EVENT

        On January 15, 2007, the Trust announced its intention to convert
        into a intermediate exploration and production company (the
        "Reorganization"). Pursuant to the Reorganization, it is contemplated
        that holders of True trust units ("Trust Units") will receive an
        equal number of shares of a newly formed corporation that will hold
        the assets previously held directly or indirectly by the Trust. The
        exchangeable shares will also be exchanged for common shares based on
        the conversion ratio thereof. The Reorganization will be 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.
    

    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: Paul R. Baay, President & CEO, (403) 750-1272
or Edward J. Brown, CA, Vice President, Finance & CFO, (403) 750-2655 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, T2P 3S8, Phone: (403) 266-8670, Fax: (403) 264-8163,
www.trueenergytrust.com


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