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True Energy Trust announces year end 2008 financial results


View All News Releases March 16, 2009

    TSX: TUI.UN

    CALGARY, March 16 /CNW/ - (TSX: TUI.UN) True Energy Trust ("True,"
"Company" or the "Trust") announces its financial and operating results for
the year ended December 31, 2008.HIGHLIGHTS

    -------------------------------------------------------------------------
                                                     Years ended December 31,
                                                           2008         2007
    -------------------------------------------------------------------------
    FINANCIAL (unaudited)
    (CDN$000s except unit and per unit amounts)
    Revenue (before royalties and hedging(1))           265,385      258,490
    Funds flow from operations(2)                        77,893      101,172
      Per basic trust unit                                $0.99        $1.33
      Per diluted trust unit(5)                           $0.98        $1.33
    Net loss                                            (19,590)     (24,267)
      Per basic trust unit                               $(0.25)      $(0.32)
      Per diluted trust unit(5)                          $(0.25)      $(0.32)
    Distributions declared                               36,334       73,451
      Per unit                                            $0.46        $0.96
    -------------------------------------------------------------------------
    Exploration and development                          36,699       87,347
    Corporate and property acquisitions                   6,303        1,505
    -------------------------------------------------------------------------
    Capital expenditures - cash                          43,002       88,852
    Property dispositions - cash                        (44,340)     (31,808)
    Other - non-cash                                      3,710         (530)
    -------------------------------------------------------------------------
    Total capital expenditures - net                      2,372       56,514
    -------------------------------------------------------------------------
    Long-term debt                                      132,388      168,475
    Convertible debentures(3)                            81,124       79,407
    Working capital deficiency                            1,492        2,431
    -------------------------------------------------------------------------
    Total net debt(3)                                   215,004      250,313
    -------------------------------------------------------------------------
    Total assets                                        736,117      880,252
    Unitholders' equity                                 406,461      462,780
    -------------------------------------------------------------------------

    OPERATING
    Daily sales volumes
      Crude oil, condensate and NGLs       (bbls/d)       4,333        5,330
      Natural gas                           (mcf/d)      45,202       64,853
      Total oil equivalent                  (boe/d)      11,867       16,139
    Average prices
      Crude oil, condensate and NGLs        ($/bbl)       76.75        48.71
      Crude oil, condensate and NGLs
       (including hedging(1))               ($/bbl)       64.24        47.74
      Natural gas                           ($/mcf)        8.50         6.73
      Natural gas (including hedging(1))    ($/mcf)        8.00         7.08
      Total oil equivalent                  ($/boe)       60.42        43.13
      Total oil equivalent
       (including hedging(1))               ($/boe)       53.92        44.23
    -------------------------------------------------------------------------



    -------------------------------------------------------------------------
                                                     Years ended December 31,
                                                           2008         2007
    -------------------------------------------------------------------------
    Statistics
      Operating netback(4)                  ($/boe)       30.91        22.21
      Operating netback(4)
       (including hedging(1))               ($/boe)       24.41        23.31
      Transportation                        ($/boe)        1.62         1.35
      Production expenses                   ($/boe)       15.33        11.59
      General & administrative              ($/boe)        3.67         3.09
      Royalties as a % of sales
       after transportation                                 21%          19%
    -------------------------------------------------------------------------

    TRUST UNITS
    Trust units outstanding                          78,496,581   79,216,046
    Trust unit incentive rights outstanding           2,700,500    5,931,997
    Units issuable for exchangeable shares              300,433      335,793
    Units issuable for convertible debentures         5,390,625    5,390,625
    -------------------------------------------------------------------------
    Diluted trust units outstanding                  86,888,139   90,874,461
    Diluted weighted average trust units(5)          78,985,481   75,792,488

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

    TRUST UNIT TRADING STATISTICS

    (CDN$, except volumes) based on
     intra-day trading
    High                                                   4.69         7.47
    Low                                                    1.17         2.76
    Close                                                  1.20         3.35
    Average daily volume                                270,458      492,004
    -------------------------------------------------------------------------

    (1) The Trust has entered into various commodity risk management
        contracts which are considered to be economic hedges. Per unit
        metrics after hedging includes only the realized portion of gains or
        losses on commodity contracts.

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

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

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

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

    (5) In computing weighted average diluted earnings per trust unit for the
        year ended December 31, 2008 a total of 2,700,500 (2007: 5,931,997)
        trust incentive units, 300,433 (2007: 335,793) exchangeable shares
        and 5,390,625 (2007: 5,390,625) trust units issuable pursuant to the
        conversion of convertible debentures were excluded from the
        calculation for the years ended December 31, 2008 and 2007 as they
        were not dilutive.

        To calculate weighted average diluted funds flow from operations for
        the year ended December 31, 2008, a total of 300,433 (2007: nil)
        exchangeable shares were added to the denominator, resulting in
        diluted weighted average trust units of 79,285,914 and funds flow
        from operations per diluted trust unit of $0.98 under this
        calculation. Under this calculation, a total of 2,700,500 (2007:
        5,931,997) trust incentive units and 5,390,625 (2007: 5,390,625)
        trust units issuable pursuant to the conversion of convertible
        debentures were excluded from the calculation for the years ended
        December 31, 2008 and 2007 as they were not dilutive.


                            REPORT TO UNITHOLDERSTrue's Management and directors recognized, in 2006, the vulnerability
inherent with a weak balance sheet and set a goal of reducing the Company's
total net debt to ensure the Trust's long term financial flexibility. The
successful corporate strategy employed included divesting a segment of the
company's production base coupled with reducing distributions to $0.04 per
unit effective December 2007. These efforts culminated in the Trust decreasing
total net debt from $275.8 million in December 2006 by $60.8 million exiting
2008 with total net debt of $215.0 million. Unfortunately throughout the
second half of 2008 industry witnessed fierce erosion of commodity pricing
with an ensuing severe energy bear equity market. As a consequence the Trust
further decreased distributions in December 2008 to $0.02 per unit,
diminishing annual cash distribution paid in 2008 to $0.46 per unit.
    Further on February 9, 2009 as economic conditions continued to
deteriorate driven by significant declining crude oil prices, a weakening
outlook for natural gas demand and heightened risk in the credit markets, the
Company deemed it prudent to suspend its distribution as of February 2009 to
maintain corporate liquidity during the current financial turmoil and
prevailing commodity price environment. Distributions continue to be reviewed
monthly in context of commodity prices, among other factors, and are subject
to revision by our Board of Directors.
    True continues to also tighten the cost structure of our business with
forecasted cuts from 2008 levels of approximately 30% to total operating
expenses which includes general and administrative costs (G&A) and lease
operating costs in 2009. The Trust's capital program has been restricted to
$15 million and the Company is forecasting 2009 production volumes to average
approximately 10,000 boe/d.
    Additional protection of the cash flow forecasts was achieved by hedging
approximately 60% of True's estimated 2009 natural gas production for the
period of March 1, 2009 to September 30, 2009 and 49% for the fourth quarter
of 2009 at a combined average fixed price of $6.42 CAD per GJ ($7.06/mcf), and
approximately 18% of True's estimated natural gas production is hedged for the
first half of 2010 at an average price of $7.25 CAD per GJ ($7.96/mcf). The
addition of a recent crude oil price collar effectively hedges approximately
13% of True's estimated 2009 crude oil production. True maintains an active
commodity price risk management program focused on maintaining sufficient cash
flow to fund its operations.
    True's operating forecast for 2009 which assumes a CAD$/US$ exchange rate
of $0.82, West Texas Intermediate ("WTI") oil price ranging from US$50.00/bbl
to US$55.00/bbl, AECO natural gas price ranging from CAD$5.00/GJ ($5.50/mcf)
to CAD$5.92/GJ ($6.50/mcf) and average annual production of approximately
10,000 boe/d generates cash flow from operations ranging from $30 million to
$40 million, after deducting royalties, all operating costs, G&A and debt
servicing costs. Based on the foregoing assumptions and assuming 2009
distributions of $1.6 million coupled with the planned capital budget of $15
million the Trust would utilize approximately 55% of the Trust's forecasted
cash flow from operations on the low side case ensuring liquidity if commodity
prices continue to weaken.Financial

    Highlights:

    1.  Total net proceeds from the sale of properties in 2008 were
        $44.3 million; which was used to pay down debt.

    2.  True's total net debt including the liability component of its
        convertible debentures, excluding unrealized commodity contract
        assets and liabilities, future income taxes and asset retirement
        obligations, as at December 31, 2008 was $215.0 million, down from
        $250.3 million as at December 31, 2007 and $275.8 million as at
        December 31, 2006. The convertible debentures have a maturity date of
        June 30, 2011.

    3.  As at December 31, 2008, True has approximately $132.4 million drawn
        on its extendible, revolving bank credit facility leaving
        $19.6 million available to assist in managing our operations and
        capital program.

    4.  The Trust and operating subsidiaries of the Trust have approximately
        $495 million in tax pools available for deduction against future
        income.Funds flow from operations for the 2008 year was $77.9 million on gross
sales of $265.4 million compared to funds flow from operations of $101.2
million on gross sales of $258.5 million for the same period in 2007. The
decrease in funds flow for the 2008 year compared to 2007 was primarily the
result of lower sales volumes and higher realized hedging losses in 2008,
despite improved commodity pricing and operating netbacks.
    Funds flow from operations for the 2008 fourth quarter was $5.9 million
on gross sales of $41.0 million compared to funds flow from operations of
$19.5 million on gross sales of $61.8 million for the same period in 2007.
This was reflective of lower commodity prices, lower sales volumes and higher
costs in 2008. Overall commodity prices for the fourth quarter of 2008
decreased significantly from that seen earlier in 2008 in connection with the
current global economic crisis. Crude oil prices in the month of December 2008
declined to a low of under US$40 WTI, a level not seen since 2004. Fourth
quarter 2008 funds flow from operations also includes $1.0 million of charges
associated with severance costs.
    True maintains a commodity price risk management program to provide a
measure of stability to funds flow from operations. Unrealized mark-to-market
gains or losses are non-cash adjustments to the current fair market value of
the contract over its entire term and are included in the calculation of net
loss.
    The net loss for the 2008 year was $19.6 million compared to a net loss
of $24.3 million for 2007. The decrease in the net loss from 2007 to 2008 was
primarily due to reduced non-cash charges for depletion, depreciation and
accretion, higher unrealized gains on commodity contracts, offset by a reduced
future income tax recovery and lower funds flow from operations. The net loss
for the 2008 fourth quarter was $9.5 million compared to a net loss of $0.4
million in the same period in 2007. The net loss for the 2008 fourth quarter
was impacted by reduced funds flow from operations, partly offset by a $7.4
million unrealized mark-to-market gain on commodity contracts.

    Liquidity

    As an oil and gas business, the Trust has a declining asset base and
therefore relies on ongoing development and acquisitions to replace production
and add additional reserves. Future oil and natural gas production and
reserves are highly dependent on the success of exploiting the Trust's
existing asset base and in acquiring additional reserves. To the extent the
Trust is successful or unsuccessful in these activities; funds flow could be
increased or reduced.
    The Trust generally relies on operating cash flows and the bank loan to
fund capital requirements and provide liquidity. From time to time, the Trust
accesses capital markets to meet its additional financing needs and to
maintain flexibility in funding its capital programs. Future liquidity depends
primarily on cash flow generated from operations, existing credit facilities
and the ability to access debt and equity markets.
    The Trust's capital structure includes a revolving bank credit facility
and unsecured subordinated convertible debentures. The 7.5% unsecured
convertible debentures represents approximately 37% of the Trust's total net
debt and these debentures are due July 2011. Upon maturity or redemption of
these debentures, the Trust can be pay the outstanding principal or premium
(if any) in cash or, subject to regulatory approval, through the issuance of
additional Trust units at 95% of a weighted average trading price of the Trust
units. True's extendible, revolving bank credit facility was renewed on June
27, 2008 with an authorized loan amount of $152 million and consists of a $15
million demand operating facility and a $137 million extendible revolving term
syndicated credit facility. True's authorized loan amount was confirmed at
$152 million effective September 30, 2008 with the next borrowing base review
scheduled for March 31, 2009. The borrowing base will be subject to the
lending syndicate's determination which is based upon the latest reserves
information, their internal commodity price decks and other factors. In the
event the borrowing base is lowered below the drawn credit facility at that
time, any shortfall would be required to be repaid within 60 days of
notification, or as otherwise agreed by the lending syndicate, and this
funding would currently be expected to come from alternative sources of debt
or equity financing or the proceeds from asset dispositions as available. The
revolving period ends on June 26, 2009, unless extended for a further 364 day
period. Should the facilities not be renewed they convert to a 366 day
non-revolving credit facility. $12.5 million of the syndicated facility is
with a US bank which may be required to be repaid or reallocated to one or
more of the other four current members of the syndicate or a new member on
June 28, 2009. As at December 31, 2008, True had approximately $19.6 million
available under the facility to assist in managing our operations and capital
program. True is fully compliant with all of its debt covenants.
    True's total net debt, excluding unrealized commodity contract assets and
liabilities, future income taxes and asset retirement obligations, as at
December 31, 2008, was $215.0 million, representing $132.4 million outstanding
on the credit facility, $81.1 million in convertible debentures (liability
component) and a $1.5 million working capital deficiency.
    Combined funding requirements for distributions declared and True's
capital expenditures represented approximately 102% of funds flow from
operations in the twelve months ended December 31, 2008. Budgeted reduced
capital spending and distributions during the year mitigated the reduced
annual cash flows, primarily as a result of crude oil price declines
experienced in the later half of 2008.
    There are currently no capital commitments, other than those associated
with the Trust's credit facilities outlined above and its 2009 drilling and
exploration program of $3 million for the first half of 2009. The Trust
continually monitors its capital spending program in light of the recent
volatility with respect to commodity prices and Canadian dollar exchange rates
with the aim of ensuring the Trust will be able to meet future anticipated
obligations incurred from normal ongoing operations with funds flow from
operations and draws on the Trust's syndicated facility, as necessary.
    In August 2008, the Trust announced approval of the renewal of its normal
course issuer bid ("NCIB") program to repurchase up to 7.8 million of its
outstanding trust units during the period August 28, 2008 through August 27,
2009, subject to certain restrictions. As of December 31, 2008, the Trust has
purchased 615,100 trust units at a weighted average price of $2.74 per trust
unit under the NCIB renewed on August 28, 2008. This purchase is in response
to True's belief that the current market price for Trust units does not
reflect the underlying value of the Trust and the cancellation of the above
purchased Trust units will increase the proportionate interest of, and be
advantageous to, all remaining unitholders. Future repurchases will be
dependent on excess cash available after consideration of the Trust's priority
uses of cash and the trading price of the Trust's units relative to the net
asset value of the Trust.
    In November 2008, the Trust received Toronto Stock Exchange approval for
its normal course issuer bid program to repurchase up to 10% of the issued and
outstanding 7.50% convertible unsecured subordinated debentures of the Trust
("Debentures") from December 1, 2008 to November 30, 2009. True believes that,
from time to time, the market price of the Debentures may not fully reflect
the underlying value of the Debentures and that at such times the purchase of
the Debentures would be in the best interests of the Trust. Such purchases
will increase the proportionate interest of, and may be advantageous to, all
remaining holders of Debentures as well as holders of Trust units. To date,
there have been no repurchases of the Debentures under this NCIB.
    True does not hold any Asset-Backed Commercial Paper investments. As a
non-operating working interest owner, True has a minor exposure of
approximately $70,000 from oil sales marketed through SemCanada Crude Company,
which filed for CCAA protection on July 22, 2008. True does not have any
exposure to Lehman Brothers, which filed for Chapter 11 bankruptcy protection
in the United States. To the best of True's knowledge, the Trust does not have
any exposure to other US financial institutions.
    True maintains an active commodity price risk management program. The
Trust will continue its hedging strategies focusing on maintaining sufficient
cash flow to fund True's operations.
    In addition to the Trust's financial commodity risk management contracts,
the Trust has entered into a natural gas physical delivery sales contract to
sell 5,275 GJ/day at a fixed price of $7.29/GJ and $7.90/GJ for the third and
fourth quarter of 2009, respectively.

    Property Acquisition and Dispositions

    On October 1, 2008, True closed the purchase of further working interests
in the Mantario, Saskatchewan area for $4.3 million in cash after adjustments.
Effective October 1, 2008 this tuck-in acquisition added approximately 225
bbls/d of heavy oil production for metrics of $19,100/boe/d and $8.60/boe.
    During the first quarter of 2008, True was successful in completing the
divestiture of a non-core property in Northeast Alberta for net proceeds of
$5.8 million. During the second quarter of 2008, True disposed of its
Dodsland-Stranraer property located in Saskatchewan for net proceeds of $38.5
million. Total net proceeds from the sale of properties in the 2008 were $44.3
million; the net proceeds from the dispositions were used to pay down debt.Reserves and Production

    Highlights from True's December 31, 2008 reserves include:

    1.  True's net asset value, based on GLJ Petroleum Consultants Ltd.
        ("GLJ") reserve report evaluation at a 10% discount rate, equates to
        $4.98 per unit and $4.96 per fully diluted unit.

    2.  The Trust's reserves life index has extended to 6.4 years for proved
        reserves and 10.1 years for proved plus probable reserves.

    3.  The Trust recorded all-in annual Finding, Development and Acquisition
        ("FD&A") cost of $18.20 per barrel of oil equivalent ("boe") in 2008
        before consideration of future development capital ("FDC") for proved
        reserves category. This is a 51 percent reduction from the $37.30 per
        boe FD&A cost realized in 2007. Including FDC, the FD&A cost was
        $20.90 per boe. The three year average FD&A cost is $36.70 per boe
        for the proved category before FDC; including FDC, the three year
        average FD&A cost is $30.40 per boe.

    4.  The Trust established a recycle ratio, after hedging and excluding
        future development costs, of 1.34x on a proved basis and 0.77x on a
        proved and probable basis.

    5.  Total proved plus probable Company Interest Reserves, including all
        royalties receivable but before deducting royalty burdens, as
        evaluated by GLJ at December 31, 2008 were 39,488 mboe (gas
        converted 6:1).

    6.  Based on the reserves information and other data as at December 31,
        2008, the Trust has performed ceiling test calculations in accordance
        with the requirements of CICA AcG 16 "Oil and Gas Accounting - Full
        Cost." No ceiling test impairment of oil and gas properties was
        identified for accounting purposes as at December 31, 2008.For additional information please refer to the reserves news release
dated February 9, 2009 (posted on www.sedar.com).
    For the 2008 year, sales volumes averaged 11,867 boe/d compared to 14,937
boe/d that was produced in Q4 of 2007. The reduction in average sales volumes
is a result of natural production decline, minimal 2008 capital spending and
the impact of dispositions totaling approximately 1,000 boe/d that were closed
during the first half of 2008. Effective October 1, 2008, True closed the
purchase of further working interests in the Mantario, Saskatchewan area for
$4.3 million in cash after adjustments. This tuck in acquisition added
approximately 225 bbls/d of heavy oil production for metrics of $19,100 per
boe/d.
    2008 fourth quarter sales volumes averaged 10,750 boe/d. True's
production and operations have been negatively impacted by the extreme weather
conditions experienced in western Canada in December 2008 and extending into
January 2009.
    Based on minimal capital spending, and normal production declines, 2009
production volumes are anticipated to average approximately 10,000 boe/d.

    Drilling

    During the 2008 year, True had an interest in a total of 38 (17.1 net)
wells drilled, which resulted in 7.1 net natural gas wells, 4.0 net light oil
wells, 0.8 net heavy oil well and 1.0 net water disposal well. 4.2 net wells
were dry and abandoned.
    Included in the above were nine gross natural gas wells that evaluated
True land at no cost to the Company. In eight True has an overriding royalty;
in the other True has no capital cost to drill, complete and tie in, retaining
a 20% working interest from first production. True has over 377,000 net acres
of undeveloped mineral leases in Alberta, British Columbia and Saskatchewan as
of December 31, 2008. An integral component of our growth strategy is to
aggressively farmout our interest in non core areas.
    During the fourth quarter of 2008, True drilled or participated in 10
(5.1 net) wells including 3.1 net natural gas wells, and 2.0 net light oil
wells. Fourth quarter drilling was focused on the Kerrobert Viking horizontal
light oil wells in Kindersley and conventional natural gas drilling at Saddle
Lake in North East Alberta. 1.0 net wells from the Saddle Lake drilling
program are expected to be tied in during the first quarter of 2009.
    During the fourth quarter of 2008, True was successful in farming out its
interest in 12,700 net acres located in British Columbia. The arrangement will
see True carried through the drilling and completion phases of the program
with the ability to retain a small working interest and remain involved in a
key high impact, high cost Montney play.

    Disposition of Working Interest in Block 126 Peru

    As announced on November 24, 2008, True and Petrominerales Ltd.
(TSX:PMG), a 76.4% owned subsidiary of Petrobank Energy and Resources Ltd.,
have entered into an agreement whereby Petrominerales will acquire True's 10%
working interest and will be designated the operator of Block 126 located in
the Ucayali Basin of east central Peru. A wholly-owned subsidiary of True held
the 10% working interest and is the operator in a partnership with Veraz
Petroleum Ltd. ("Veraz"). Closing of this transaction is subject to the
consent of Perupetro S.A, the private law state company responsible for
promoting the investment of hydrocarbon exploration and exploitation
activities in Peru and receipt of the purchase price according to the
agreement. True continues to have a minor investment in Veraz.

    2009 Outlook

    The global economic contraction has caused oil and gas prices to plummet
producing both, a sector wide severe bear equity market and substantially
decreasing cash flow. The consequences are being felt industry wide with
slashed capital programs coupled with suppressed expense budgets. True has
adopted a very cautious outlook with material reductions in its operating cost
base.
    True has targeted reductions in general and administrative expenses early
in 2009 and we will continue to focus on opportunities to reduce operating
costs. As part of the general and administrative cost reductions, True has
streamlined its operations and reduced head office staffing levels by a third.
True has forecasted cuts of 30% to total operating expenses, which includes
general and administrative costs and lease operating costs, in 2009. Cost
reductions in combination with limiting our capital spending in the first half
of 2009 will add to our financial flexibility and better position True to
operate in the current difficult economic environment.
    True does not intend to drill any operated wells in the first half of
2009. Furthermore, capital spending will be limited to $3 million during the
first six months of 2009. In addition to focusing on increasing production
from existing wells through continued optimization, and performing necessary
maintenance programs, the first half 2009 capital spending will be limited to
the tie-in of two gross (1 net) Saddle Lake area natural gas wells drilled in
the fourth quarter of 2008. Non-operated projects will continue to be closely
scrutinized against internal opportunities. True's total 2009 capital program
is not expected to exceed $15 million and will reflect our future view of
commodity pricing and cash flow, available business opportunities, and
industry costs trends.
    The Company has reorganized its senior management with the appointment of
myself as President and CEO, Mr. Russell G. Oicle as Vice President,
Exploration and Mr. Duncan A. Chisholm, as Vice President, Operations. This
group brings in excess of 100 years of experience and expertise to True as
successful full cycle explorationists and production optimization specialists.
    With a cautious bias to cost control, the Company will proceed in 2009 to
explore its quality land base while high grading the plethora of low risk
development opportunities.
    A conference call to discuss True's annual financial and reserves results
will be held on March 17, 2009 at 2:00 PM MDT/4:00 PM EDT. To participate,
please call toll-free 1-800-731-5774 or 416-644-3423. The conference call will
also be recorded and available by calling 1-877-289-8525 or 416-640-1917 and
entering passcode 21295355 followed by the pound sign.
    True's annual general meeting is scheduled for 3:00pm on May 20, 2009 in
the Herald Doll Room at the Hyatt Regency in Calgary.Raymond G. Smith, P. Eng.
    President and CEO
    March 16, 2009


                    MANAGEMENT'S DISCUSSION AND ANALYSISMarch 16, 2009 - The following Management's Discussion and Analysis of
financial results as provided by the management of True Energy Trust ("True"
or the "Trust") should be read in conjunction with the audited consolidated
financial statements of the Trust for the years ended December 31, 2008 and
2007. This commentary is based on information available to, and is dated as
of, March 16, 2009. The financial data presented is in accordance with
Canadian generally accepted accounting principles ("GAAP") in Canadian
dollars, except where indicated otherwise.

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

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

    FORWARD LOOKING STATEMENTS: Certain information contained herein may
contain forward looking statements including management's assessment of future
plans and operations, drilling and tie-in plans and the timing thereof, plans
regarding wells to be drilled, expected or anticipated production rates,
hedging strategies, distributions and method of funding thereof, anticipated
liquidity of the Trust and various matters that may impact such liquidity,
timing of bringing production back on from certain wells, planned reductions
in operating expenses in 2009 and expected operating expenses, expected
production and transportation expenses and general and administrative
expenses, expected levels of revenues and operating netbacks in 2009 compared
to 2008, proportion of distributions anticipated to be taxable and
non-taxable, maintenance of productive capacity and capital expenditures and
the nature of capital expenditures and the timing and method of financing
thereof, may constitute forward-looking statements under applicable securities
laws and necessarily involve risks including, without limitation, risks
associated with oil and gas exploration, development, exploitation,
production, marketing and transportation, loss of markets, volatility of
commodity prices, currency fluctuations, imprecision of reserve estimates,
environmental risks, competition from other producers, inability to retain
drilling rigs and other services, incorrect assessment of the value of
acquisitions, failure to realize the anticipated benefits of acquisitions,
delays resulting from or inability to obtain required regulatory approvals and
ability to access sufficient capital from internal and external sources. The
recovery and reserve estimates of True's reserves provided herein are
estimates only and there is no guarantee that the estimated reserves will be
recovered. Events or circumstances may cause actual results to differ
materially from those predicted, as a result of the risk factors set out and
other known and unknown risks, uncertainties, and other factors, many of which
are beyond the control of True. In addition, forward-looking statements or
information are based on a number of factors and assumptions which have been
used to develop such statements and information but which may prove to be
incorrect. Included herein is an estimate of True's cash flow from operations
in 2009 and the percentage that 2009 assumed distributions and its planned
capital budget will be of such estimated funds flow from operations. Such
financial outlook was approved by management of the Trust on February 9, 2009
and such financial outlook is included herein to provide an assessment of the
ability of the Trust to generate the cash necessary to fund future capital
investments after assumed distribution and to repay debt. Although the Trust
believes that the expectations reflected in such forward-looking statements or
information are reasonable, undue reliance should not be placed on
forward-looking statements because the Trust can give no assurance that such
expectations will prove to be correct. In addition to other factors and
assumptions which may be identified herein, assumptions have been made
regarding, among other things: the impact of increasing competition; the
general stability of the economic and political environment in which the Trust
operates; the timely receipt of any required regulatory approvals; the ability
of the Trust to obtain qualified staff, equipment and services in a timely and
cost efficient manner; drilling results; the ability of the operator of the
projects which the Trust has an interest in to operate the field in a safe,
efficient and effective manner; the ability of the Trust to obtain financing
on acceptable terms; field production rates and decline rates; the ability to
replace and expand oil and natural gas reserves through acquisition,
development of exploration; the timing and costs of pipeline, storage and
facility construction and expansion and the ability of the Trust to secure
adequate product transportation; future commodity gas prices; currency,
exchange and interest rates; the regulatory framework regarding royalties,
taxes and environmental matters in the jurisdictions in which the Trust
operates; and the ability of the Trust to successfully market its oil and
natural gas products. Readers are cautioned that the foregoing list is not
exhaustive of all factors and assumptions which have been used. As a
consequence, actual results may differ materially from those anticipated in
the forward-looking statements. Additional information on these and other
factors that could effect True's operations and financial results are included
in reports on file with Canadian securities regulatory authorities and may be
accessed through the SEDAR website (www.sedar.com), at True's website
(www.trueenergytrust.com). Furthermore, the forward-looking statements
contained herein are made as at the date hereof and True does not undertake
any obligation to update publicly or to revise any of the included
forward-looking statements, whether as a result of new information, future
events or otherwise, except as may be required by applicable securities laws.
    The reader is further cautioned that the preparation of financial
statements in accordance with GAAP requires management to make certain
judgments and estimates that affect the reported amounts of assets,
liabilities, revenues and expenses. Estimating reserves is also critical to
several accounting estimates and requires judgments and decisions based upon
available geological, geophysical, engineering and economic data. These
estimates may change, having either a negative or positive effect on net
earnings as further information becomes available, and as the economic
environment changes.

    Overview and Description of the Business

    True Energy Trust is a Canadian trust, formed in 2005 via the reverse
takeover of TKE Energy Trust. The Trust is involved in the exploration,
development and production of petroleum and natural gas in western Canada. The
Trust has a significant multi-year drilling inventory of locations in Alberta,
Saskatchewan and British Columbia.
    True's Trust units and convertible debentures are listed on the Toronto
Stock Exchange under the symbols TUI.UN and TUI.DB, respectively.

    Fourth Quarter 2008

    Funds flow from operations during the fourth quarter of 2008 was $5.9
million, a decrease of 70% compared to $19.5 million for the fourth quarter of
2007. This was reflective of lower commodity prices, lower sales volumes and
higher costs in 2008. Overall commodity prices for the fourth quarter of 2008
decreased significantly from that seen earlier in 2008 in connection with the
current global economic crisis. Crude oil prices in the month of December 2008
declined to a low of under US$40 WTI, a level not seen since 2004. Fourth
quarter 2008 funds flow from operations also includes $1.0 million of charges
associated with severance costs. By comparison, in the last quarter of 2008,
True had a net loss of $9.5 million compared to a net loss of $0.4 million in
the fourth quarter of 2007.
    Sales volumes for the three months ended December 31, 2008 averaged
10,750 boe/d, down 28% from the 14,937 boe/d produced in the fourth quarter of
2007. Fourth quarter 2008 sales volumes were lower than the same period in
2007 due to natural production declines, decreased production due to property
dispositions during 2008, extreme weather conditions, and minimal capital
spending.
    In the fourth quarter of 2008, average sales volumes decreased 5% from
the third quarter 2008 average volumes of 11,263 boe/d. True's production and
operations were impacted by the extreme weather conditions and commodity price
erosion experienced in western Canada in December 2008 and extending into
January 2009. True realized the loss of an estimated 950 boe/d which was
directly related to both weather and True's ongoing review of profitability.
True continues to apply good winter operating practices to remedy the offline
production, however, an estimated 250 boe/d will be reactivated upon receiving
improved commodity prices. Natural gas sales averaged 38.4 Mmcf/d during the
last quarter of 2008, compared to 57.4 Mmcf/d in the fourth quarter of 2007.
The Trust's natural gas sales reduction was in part attributed to a
Saskatchewan asset divestiture. The weighting toward natural gas averaged 60%
in the fourth quarter, compared to 64% in the corresponding period of 2007.
Crude oil, condensate and NGL sales volumes averaged 4,347 bbls/d in the
fourth quarter of 2008 compared to 5,370 bbls/d during the same period of
2007.
    During the fourth quarter of 2008, True spent $11.0 million on capital
projects, excluding corporate and asset acquisitions and dispositions,
compared to $15.5 million in 2007. In the fourth quarter of 2008, True drilled
or participated in 10 (5.1 net) wells including 3.1 net natural gas wells, and
2.0 net light oil wells. Fourth quarter drilling was focused on the Kerrobert
Viking horizontal light oil wells in Kindersley and conventional natural gas
drilling at Saddle Lake in North East Alberta. 1.0 net well from the Saddle
Lake drilling program is expected to be tied in during the first quarter of
2009. Also, during the fourth quarter of 2008, True was successful in farming
out its interest in 12,700 net acres located in British Columbia. The
arrangement will see True carried through the drilling and completion phases
of the program with the ability to retain a small working interest and remain
involved in a key Montney formation play.
    During the fourth quarter of 2008, True experienced an overall decrease
of 41% in commodity prices, based on decreases in crude oil, condensate and
NGL pricing, as compared to the same period in 2007. The average daily and
monthly AECO indices for natural gas during this quarter was 9% and 13%,
respectively, higher than in the same period in 2007. For the three months
ending December 31, 2008, True received an average natural gas price, before
transportation and hedging, of $6.98/Mcf, 9% higher than $6.40/Mcf in the same
period in 2007 and 22% lower than $8.97/Mcf in the third quarter of 2008. For
heavy crude oil, True received an average price before transportation of
$36.52/bbl during the fourth quarter of 2008, 8% less than $39.72/bbl in the
same period in 2007 and 61% less than $92.51/bbl in the third quarter of 2008.
In comparison, the average reference price for Hardisty Heavy crude in the
fourth quarter of 2008 was 12% less than the average 2007 price in the same
period. For light oil, condensate and NGLs, True received an average price of
$45.96/bbl before transportation and hedging during the last quarter of 2008,
41% less than the average price of $78.42/bbl received in the same period of
2007, compared to a 27% decrease in the Edmonton par reference price. The
average price for light oil, condensate and NGLs for True was 57% lower than
the $107.55/bbl for the third quarter of 2008. During the fourth quarter of
2008, revenue before other income and hedging of $40.2 million was 33% lower
than the corresponding 2007 period.
    In the fourth quarter of 2008, the Trust paid $9.0 million in royalties,
compared to $12.6 million in the same period in 2007. As a percentage of
pre-hedge sales (after transportation costs), royalties were 23% in the fourth
quarter of 2008 compared to 22% in the same period in 2007. In this same
period of 2008, operating costs totaled $17.9 million, compared to $16.5
million recorded in the same period of 2007. During the fourth quarter of
2008, operating costs averaged $18.11/boe, up from the $12.01/boe incurred
during the fourth quarter of 2007. The increase was due to a number of factors
including incremental unanticipated prior period cost adjustments from
non-operated properties and additional workover and other costs from earlier
in 2008. Also, fuel gas costs associated with steam generation at the
Kerrobert facility contributed $1.57/boe in the fourth quarter of 2008,
whereas these costs were capitalized in 2007 during initial steaming period
for the project expansion. In addition, the fixed component of certain
operating costs combined with reduced sales volumes between comparable periods
has contributed to the increase in costs on a per boe basis. In comparison,
operating costs for the third quarter of 2008 averaged $14.95/boe. True is
targeting operating costs of approximately $48.8 million ($13.40/boe) in 2009.
This is based upon assumptions of estimated production of approximately 10,000
boe/d and planned cost reductions. During the fourth quarter of 2008, company
field operating netbacks decreased by 40% to $12.31/boe compared to 2007,
driven primarily by decreased overall commodity prices and increased operating
costs. In comparison, the company field operating netback for the third
quarter of 2008 was $38.31/boe. Field operating netbacks for natural gas
before hedging during the fourth quarter of 2008 of $2.35/Mcf were 15% less
than the 2007 netbacks, reflecting higher royalties and production costs,
somewhat offset by higher commodity prices and reduced transportation costs.
In comparison, the field operating netback for natural gas for the third
quarter of 2008 was $5.50/Mcf. Field operating netbacks before hedging for
crude oil, condensate and NGLs during the fourth quarter of 2008 averaged
$9.68/bbl, down from $27.34/bbl during the fourth quarter of 2007, primarily
as a result of a significant decrease in the overall commodity price received,
and with higher production expenses partially offset by a reduction in
royalties. In comparison, the field operating netback for crude oil,
condensate and NGLs for the third quarter of 2008 was $48.07/bbl.
    In the fourth quarter of 2008, the net cost of general and administrative
expenses was $4.1 million, compared to $4.7 million in the comparable 2007
period reflecting a reduction of the number of salaried personnel on staff and
other efforts to reduce costs. Fourth quarter 2008 general and administrative
costs include $1.0 million of charges associated with severance costs. True is
forecasting general and administrative costs of approximately $11.5 million
($3.15/boe) in 2009 based on the cost reduction initiatives applied in early
January and estimated 2009 production volumes of approximately 10,000 boe/d.
This represents an approximate 30% reduction over 2008 costs.
    Depletion, depreciation and accretion expense for the fourth quarter of
2008 was $29.4 million, compared to $39.8 million in 2007, which reflects
reduced carrying costs in 2008, combined with lower production volumes in
fourth quarter 2008 versus 2007.2008 Annual Financial and Operational Results

    Net Loss and Funds Flow from OperationsTrue generated funds flow from operations of $77.9 million ($0.98 per
diluted unit) for the year ended December 31, 2008, down 23% from $101.2
million ($1.33 per diluted unit) for the 2007 year.  The decrease in funds
flow for the 2008 year compared to 2007 was primarily the result of lower
sales volumes and higher realized hedging losses, despite improved commodity
pricing and operating netbacks.
    True maintains a commodity price risk management program to provide a
measure of stability to funds flow from operations. Unrealized mark-to-market
gains or losses are non-cash adjustments to the current fair market value of
the contract over its entire term and are included in the calculation of net
loss.
    The net loss for the 2008 year was $19.6 million ($0.25 per diluted unit)
compared to a net loss of $24.3 million ($0.32 per diluted unit) in 2007. The
decrease in the net loss from 2007 to 2008 was primarily due to reduced
non-cash charges for depletion, depreciation and accretion, higher unrealized
gains on commodity contracts, offset by a reduced future income tax recovery
and lower funds flow from operations.Funds Flow From Operations and Net Loss

    -------------------------------------------------------------------------
                                                     Years Ended December 31,
    ($000s, except per unit amounts)                       2008         2007
    -------------------------------------------------------------------------
    Funds flow from operations                           77,893      101,172
      Basic   ($/unit)                                     0.99         1.33
      Diluted ($/unit)                                     0.98         1.33

    Net loss                                            (19,590)     (24,267)
      Basic   ($/unit)                                    (0.25)       (0.32)
      Diluted ($/unit)                                    (0.25)       (0.32)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Reconciliation of Funds Flow from Operations and Cash Flow from
    Operating Activities

    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($000s, except per unit amounts)                       2008         2007
    -------------------------------------------------------------------------
    Funds flow from operations                           77,893      101,172
    Asset retirement costs incurred                      (2,603)        (835)
    Change in non-cash working capital                    3,494      (18,131)
    -------------------------------------------------------------------------
    Cash flow from operating activities                  78,784       82,206
    -------------------------------------------------------------------------Sales Volumes

    Sales volumes for the year ended December 31, 2008 averaged 11,867 boe/d
compared to 16,139 boe/d for the same period in 2007, representing a 26%
decrease.
    In addition to natural production decline and minimal 2008 capital
spending, year over year production volumes were impacted by dispositions
totalling approximately 1,000 boe/d that were closed during the first half of
2008. Also, approximately 950 boe/d was affected in the fourth quarter of 2008
(approximately 240 boe/d annualized) due to extreme weather conditions causing
delayed servicing and freeze offs.
    On October 1, 2008, True closed the purchase of further working interests
in the Mantario, Saskatchewan area for $4.3 million in cash after adjustments.
Effective October 1, 2008 this tuck-in acquisition adds approximately 225
bbls/d of heavy oil production for metrics of $19,100/boe/d and $8.60/boe.Sales Volumes
    -------------------------------------------------------------------------
                                                     Years ended December 31,
                                                           2008         2007
    -------------------------------------------------------------------------
    Natural gas                             (mcf/d)      45,202       64,853
    -------------------------------------------------------------------------

    Heavy oil                              (bbls/d)       2,897        3,450
    Light oil and condensate               (bbls/d)         999        1,289
    NGLs                                   (bbls/d)         437          591
    -------------------------------------------------------------------------
    Total crude oil and NGLs               (bbls/d)       4,333        5,330
    -------------------------------------------------------------------------
    Total boe/d                               (6:1)      11,867       16,139
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------During the 2008 year, True had an interest in a total of 38 wells (17.1
net) drilled, which resulted in 7.1 net natural gas wells, 4.0 net light oil
wells, 0.8 net heavy oil well and 1.0 net water disposal well. 4.2 net were
dry and abandoned.
    Included in the above were nine gross natural gas wells that evaluated
True land at no cost to the Company. In eight True has an overriding royalty;
in the other True has no capital cost to drill, complete and tie in, retaining
a 20% working interest from first production. True has over 377,000 net acres
of undeveloped mineral leases in Alberta, British Columbia and Saskatchewan as
of December 31, 2008. An integral component of our growth strategy is to
aggressively farmout our interest in non core areas.
    By comparison, True drilled or participated in 40 (27.3 net) working
interest wells in 2007.
    For the year ended December 31, 2008, the weighting towards natural gas
sales averaged 63% compared to 67% for the 2007 year. Heavy oil sales made up
24% of total production for the 2008 year compared to 21% in 2007.
    Sales of natural gas averaged 45.2 Mmcf/d for 2008, compared to 64.9
Mmcf/d in 2007, a decrease of 30%. Crude oil and NGL sales for 2008 decreased
19% averaging 4,333 bbls/d compared to 2007 average sales of 5,330 bbls/d.
    2009 production volumes are anticipated to average approximately 10,000
boe/d. The forecast of 2009 production volumes is based upon a number of
assumptions, including normal production declines and expenditures under the
current planned capital budget of $15 million.Commodity Prices

    Average Commodity Prices
    -------------------------------------------------------------------------
                                                     Years ended December 31,
                                              2008         2007     % Change
    -------------------------------------------------------------------------
    Exchange rate (US$/Cdn$)                0.9372       0.9390           -%

    Natural gas:
    NYMEX (US$/mmbtu)                         8.89         7.14          25%
    AECO daily index (CDN$/Mcf)               8.13         6.44          26%
    AECO monthly index (CDN$/Mcf)             8.12         6.61          23%
    True's average price ($/mcf)              8.50         6.73          26%
    True's average price
     (including hedging(1)) ($/mcf)           8.00         7.08          13%

    Crude oil:
    WTI (US$/bbl)                            99.73        74.25          34%
    Edmonton par - light oil ($/bbl)        102.85        77.06          33%
    Bow River - medium/heavy oil ($/bbl)     83.85        53.16          58%
    Hardisty Heavy - heavy oil ($/bbl)       76.32        44.77          70%
    True's average prices ($/bbl)
      Light crude oil, condensate, and NGLs  88.42        64.60          37%
      Heavy crude oil                        70.96        40.05          77%
      Total crude oil and NGLs               76.75        48.71          58%
      Total crude oil and NGLs
       (including hedging(1))                64.24        47.74          35%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Per unit metrics including hedging include realized gains or losses
        on commodity contracts and exclude unrealized gains or losses on
        commodity contracts.True's natural gas sales are priced with reference to the daily or
monthly AECO indices. During 2008, the AECO daily and monthly reference price
increased by 26% and 23%, respectively, compared to the same period in 2007.
Similarly, True's average sales price before hedging for 2008 increased by 26%
compared to the same period in 2007. True's natural gas price after including
hedging for 2008 was $8.00/mcf compared to $7.08/mcf for 2007.
    The Trust has entered into a natural gas physical delivery sales contract
to sell 5,275 GJ/day at a fixed price of $7.29/GJ and $7.90/GJ for the third
and fourth quarter of 2009, respectively.
    For heavy crude oil, True received an average price before transportation
of $70.96/bbl for 2008, an increase of 77% over prices in the 2007 year. The
Bow River reference price increased by 58% and the Hardisty Heavy reference
price increased by 70% over the same period. The majority of True's heavy
crude oil density ranges between 11 and 16 degrees API consistent with the
Hardisty Heavy reference price, although all of True's heavy oil production is
sold at Saskatchewan delivery points. During 2008, the blending costs for
condensate were lower which has also contributed to higher pricing received
    For light oil, condensate and NGLs, True recorded an average $88.42/bbl
before hedging during 2008, 37% higher than the average price received in the
2007 year. In comparison, the Edmonton par price increased by 33% over the
same period. The average WTI crude oil US dollar based price increased 34%
from 2007 to 2008. True's realized price after including hedging was
$126.14/bbl for 2008 compared to $45.22/bbl for the same period in 2007.
Although oil prices achieved record highs throughout 2008, peaking in July at
US$147.27 per barrel of for WTI and averaging US$99.73 per barrel for the full
year, the sharp decline in oil prices during the fourth of 2008 has resulted
in exit 2008 oil prices at their lowest level since 2004. The full impact of
the price decline will not be realized until the first quarter of 2009. The
average US$/Cdn$ foreign exchange rate was 0.94 for the full year of 2008;
however, a sharp decline in the fourth quarter resulted in the U.S. dollar
closing at 0.83 per Canadian dollar on December 31, 2008. The negative
correlation between the Canadian dollar and U.S. dollar denominated WTI oil
prices should lessen the impact on the Trust of any future declines in the
price of oil, however, crude oil prices have remained depressed in the early
part of 2009 and investors should expect that revenues in 2009 will be
significantly lower than those recorded in 2008.
    WTI crude oil prices varied greatly throughout 2008, increasing
significantly to a high of US$147/bbl in July and dramatically falling during
the fourth quarter of 2008 with December 2008 prices of under US$40/bbl. The
pricing outlook in 2009 for crude oil and natural gas remains uncertain given
the current global economic environment.

    Revenue

    Revenue before other income and hedging for the year ended December 31,
2008 was $262.4 million, 3% higher than the $254.0 million in the same period
in 2007. The higher revenue for the 2008 period was the result of
significantly higher commodity prices, despite lower sales volumes.-------------------------------------------------------------------------
                                                     Years ended December 31,
    ($000s)                                                2008         2007
    -------------------------------------------------------------------------
    Light crude oil, condensate and NGLs                 46,485       44,325
    Heavy oil                                            75,241       50,436
    -------------------------------------------------------------------------
    Crude oil and NGLs                                  121,726       94,761
    Natural gas                                         140,701      159,278
    -------------------------------------------------------------------------
    Total revenue before other                          262,427      254,039
    Other(1)                                              2,958        4,451
    -------------------------------------------------------------------------
    Total revenue before royalties and hedging          265,385      258,490
    -------------------------------------------------------------------------

    (1) Other revenue primarily consists of processing and other third party
        income.Revenues for 2009 are currently expected to be lower than 2008 due to
lower commodity prices and average estimated 2009 production of approximately
10,000 boe/d.

    Commodity Price Risk Management

    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, collars and
the purchase of floor price options and other derivative financial instruments
and physical delivery sales contracts 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 funds flow from
operations, as well as, to ensure True realizes positive economic returns from
its capital developments and acquisition activities. The Trust will continue
its hedging strategies focusing on maintaining sufficient cash flow to fund
True's operations. Any remaining unhedged production is realized at market
prices.
    A summary of the financial hedge volumes and average prices by quarter
currently outstanding as of March 16, 2009 is shown in the following tables:Natural gas

    Average Volumes (GJ/d)
    -------------------------------------------------------------------------
                                    Q1 2009    Q2 2009    Q3 2009    Q4 2009
    -------------------------------------------------------------------------
    Fixed                            15,544     20,050     19,500     15,000


    -------------------------------------------------------------------------
                                    Q1 2010    Q2 2010    Q3 2010    Q4 2010
    -------------------------------------------------------------------------
    Fixed                            10,000      5,000          -          -
    Call option (ceiling price)       5,000      5,000      5,000      5,000
    -------------------------------------------------------------------------
    Total GJ/d                       15,000     10,000      5,000      5,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Average Price ($/GJ AECO C)
    -------------------------------------------------------------------------
                                    Q1 2009    Q2 2009    Q3 2009    Q4 2009
    -------------------------------------------------------------------------
    Fixed                              6.94       6.01       5.97       6.75
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                                    Q1 2010    Q2 2010    Q3 2010    Q4 2010
    -------------------------------------------------------------------------
    Fixed                              7.58       6.59          -          -
    Call option (ceiling price)        8.05       8.05       8.05       8.05
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Crude oil and liquids

    Average Volumes (bbls/d)
    -------------------------------------------------------------------------
                                    Q1 2009    Q2 2009    Q3 2009    Q4 2009
    -------------------------------------------------------------------------
    Costless collars                    172        500        500        500
    -------------------------------------------------------------------------
    Total bbls/d                        172        500        500        500
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Average Price (US$/bbl WTI)
    -------------------------------------------------------------------------
                                    Q1 2009    Q2 2009    Q3 2009    Q4 2009
    -------------------------------------------------------------------------
    Collar ceiling price              65.60      65.60      65.60      65.60
    Collar floor price                42.50      42.50      42.50      42.50
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------Included in the above natural gas table is a fixed price contract of
$5.90/GJ at 5,000 GJ/d for the Q2 2009 to Q4 2009 periods which was funded by
selling a call option of 5,000 GJ/d at $8.05 for the 2010 year.
    As of December 31, 2008, the fair value of True's outstanding commodity
contracts is an unrealized asset of $3.7 million as reflected in the financial
statements. The fair value or mark-to-market value of these contracts is based
on the estimated amount that would have been received or paid to settle the
contracts as at December 31, 2008 and may be different from what will
eventually be realized. Changes in the fair value of the commodity contracts
are recognized in the Consolidated Statements of Loss within the financial
statements.
    Strong commodity prices throughout most of 2008 had a significant impact
on the Trust's revenue; however, these strong prices resulted in realized cash
losses of $19.8 million and $8.4 million for the Trust's oil and natural gas
risk management contracts, respectively.
    The following is a summary of the gain (loss) on commodity contracts for
the years ended December 31, 2008 and 2007 as reflected in the Consolidated
Statements of Loss in the financial statements:Commodity contracts
    -------------------------------------------------------------------------
                                         Crude Oil      Natural
    ($000s)                              & Liquids          Gas   2008 Total
    -------------------------------------------------------------------------
    Realized cash loss on contracts        (19,835)      (8,387)     (28,222)
    Unrealized gain on contracts(2)         11,404        2,664       14,068
    -------------------------------------------------------------------------
    Total loss on commodity contracts       (8,431)      (5,723)     (14,154)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                                         Crude Oil      Natural
    ($000s)                              & Liquids          Gas   2007 Total
    -------------------------------------------------------------------------
    Realized cash gain (loss)
     on contracts(1)                        (1,891)       8,382        6,491
    Unrealized gain (loss)
     on contracts(2)                       (11,404)       1,061      (10,343)
    -------------------------------------------------------------------------
    Total gain (loss) on
     commodity contracts                   (13,295)       9,443       (3,852)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Includes the crude oil and natural gas commodity contract premium
        expenses and the amortization of prior year crude oil and natural gas
        commodity contract premiums of a total $3.7 million for the year
        ended December 31, 2007.
    (2) Unrealized gain (loss) commodity contracts represent non-cash
        adjustments for changes in the fair value of these contracts during
        the period.Royalties

    For the year ended December 31, 2008, total royalties were $54.6 million,
compared to $47.0 million incurred in 2007. Overall royalties as a percentage
of revenue (after transportation costs) in 2008 were 21%, compared with 19% in
2007. Royalties were lower by approximately $5.5 million in 2007 due to the
reversal of certain prior period over accruals for light and heavy crude oil
royalties; excluding these adjustments, the average royalty rate for the year
ended December 31, 2007 would have been 20%.-------------------------------------------------------------------------
    Royalties by Commodity Type                      Years ended December 31,
    ($000s, except where noted)                            2008         2007
    -------------------------------------------------------------------------

    Light crude oil, condensate and NGLs                 11,211        9,772
      $/bbl                                               21.33        14.24
      Average light crude oil, condensate and NGLs
       royalty rate (%)                                      25           22

    Heavy Oil                                            14,060        6,867
      $/bbl                                               13.26         5.45
      Average heavy oil royalty rate (%)                     20           14

    Natural Gas                                          29,291       30,365
      $/mcf                                                1.77         1.28
      Average natural gas royalty rate (%)                   21           20

    -------------------------------------------------------------------------
        Total                                            54,562       47,004
    -------------------------------------------------------------------------
        $/boe                                             12.56         7.98
    -------------------------------------------------------------------------
        Average total royalty rate (%)                       21           19
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Royalties, by Type
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($000s)                                                2008         2007
    -------------------------------------------------------------------------
    Crown royalties                                      30,354       20,799
    Indian Oil and Gas Canada royalties                   6,479        5,927
    Freehold & GORR                                      17,729       20,278
    -------------------------------------------------------------------------
    Total                                                54,562       47,004
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Expenses
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($000s)                                                2008         2007
    -------------------------------------------------------------------------
    Production                                           66,573       68,282
    Transportation                                        7,047        7,938
    General and administrative                           15,958       18,186
    Interest and financing charges                       14,822       18,108
    Unit-based compensation                               1,395        2,001
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Expenses per boe
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($ per boe)                                            2008         2007
    -------------------------------------------------------------------------
    Production                                            15.33        11.59
    Transportation                                         1.62         1.35
    General and administrative                             3.67         3.09
    Interest and financing charges                         3.41         3.07
    Unit-based compensation                                0.32         0.34
    -------------------------------------------------------------------------Production Expenses

    For the year ended December 31, 2008, production expenses totaled $66.6
million ($15.33/boe), compared to $68.3 million ($11.59/boe) recorded in 2007.
The increase in production expenses in 2008 on a boe basis is due to a number
of factors. Repairs and operating workovers for 2008 were approximately $15.6
million ($3.59/boe) compared to $19.1 million ($3.24/boe) in 2007. Also, fuel
gas costs associated with steam generation at the Kerrobert facility
contributed $1.91/boe in 2008, whereas these costs were capitalized in late
2007 during initial steaming period for the project expansion. In addition,
the fixed component of certain production expenses combined with reduced sales
volumes between comparable periods has contributed to the increase in costs on
a per boe basis. True is targeting operating costs of approximately $48.8
million ($13.40/boe) in 2009. This is based upon assumptions of estimated
production of approximately 10,000 boe/d and planned cost reductions.Production Expenses, by Commodity Type
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($000s, except where noted)                            2008         2007
    -------------------------------------------------------------------------
    Light crude oil, condensate and NGLs                 10,155        9,906
    $/bbl                                                 19.32        14.44

    Heavy oil                                            22,672       18,301
    $/bbl                                                 21.38        14.53

    Natural gas                                          33,746       40,075
    $/mcf                                                  2.04         1.69

    -------------------------------------------------------------------------
    Total                                                66,573       68,282
    -------------------------------------------------------------------------
    $/boe                                                 15.33        11.59
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Total                                                66,573       68,282
    -------------------------------------------------------------------------
    Processing and other third party income(1)           (2,958)      (4,451)
    -------------------------------------------------------------------------
    Total after deducting processing and other third
     party income                                        63,615       63,831
    -------------------------------------------------------------------------
    $/boe                                                 14.65        10.84
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

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

    Transportation expenses have historically been approximately 2% to 3% of
gross revenues. For the years ended December 31, 2008 and 2007, transportation
expenses averaged approximately 3%.

    Operating Netback

    For the 2008 year, corporate field operating netback (before hedging) was
$30.91/boe compared to $22.21/boe in fiscal 2007. This was the result of
increased overall commodity prices, partially offset by higher transportation,
royalties and operating costs experienced in 2008. After including hedging
activities, the corporate field operating netback for 2008 was $24.41/boe
compared to $23.31/boe in 2007.Field Operating Netback - Corporate (before hedging)
    -------------------------------------------------------------------------
                                             For the years ended December 31,
    ($/boe)                                                2008         2007
    -------------------------------------------------------------------------
    Sales                                                 60.42        43.13
    Transportation                                        (1.62)       (1.35)
    Royalties                                            (12.56)       (7.98)
    Production expense                                   (15.33)      (11.59)
    -------------------------------------------------------------------------
    Field operating netback                               30.91        22.21
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------Overall, corporate operating netbacks for 2009 are currently expected to
be lower than 2008 due to anticipated lower commodity prices.
    Field operating netback for natural gas in 2008 increased 30% to
$4.52/mcf, compared to $3.47/mcf in 2007, reflecting stronger natural gas
prices experienced, the effects of which were partially offset by higher
royalties and transportation expenses. After including hedging activities,
field operating netback for natural gas for fiscal 2008 was $4.02/mcf compared
to $3.83/mcf in the same period in 2007.Field Operating Netback - Natural Gas (before hedging)
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($/mcf)                                                2008         2007
    -------------------------------------------------------------------------
    Sales                                                  8.50         6.73
    Transportation                                        (0.17)       (0.29)
    Royalties                                             (1.77)       (1.28)
    Production expense                                    (2.04)       (1.69)
    -------------------------------------------------------------------------
    Field operating netback                                4.52         3.47
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Field operating netback for crude oil, condensate and NGLs averaged
$37.46/bbl for 2008, up 50% compared to $25.01/bbl for 2007. This compares to
a 58% increase in the crude oil, condensate and NGLs sales price combined with
an increase in overall expenses over the same period. After including hedging
activities, field operating netback for crude oil and NGLs for 2008 was
$24.96/boe compared to $24.04/boe in 2007.


    Field Operating Netback - Crude Oil, Condensate and NGLs (before hedging)
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($/bbl)                                                2008         2007
    -------------------------------------------------------------------------
    Sales                                                 76.75        48.71
    Transportation                                        (2.66)       (0.65)
    Royalties                                            (15.93)       (8.55)
    Production expense                                   (20.70)      (14.50)
    -------------------------------------------------------------------------
    Field operating netback                               37.46        25.01
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------General and Administrative

    Net general and administrative ("G&A") expenses for 2008 were $16.0
million compared to $18.2 million for 2007. The decrease in the G&A expense
for the year ended December 31, 2008 from the same period in 2007 reflects a
reduction of the number of salaried personnel on staff and other efforts to
reduce costs. G&A costs for the year includes $1.0 million of charges
associated with severance costs in the fourth quarter of 2008. The reduction
in amounts of capitalized G&A for 2008 is consistent with a lower capital
program. On a per boe basis, G&A expenses for fiscal 2008 were $3.67/boe
compared to $3.09/boe for fiscal 2007. The increase in G&A on a per boe basis
is consistent with reduced sales volumes experienced in 2008 compared to 2007.
    True had targeted reductions in G&A expenses in early 2009. As part of
the G&A cost reductions, True has streamlined its operations and reduced head
office staffing levels and costs by approximately one third. For 2009, the
Trust is anticipating G&A costs to be approximately $11.5 million ($3.15/boe)
based on the cost reduction initiatives applied in early January 2009 and
estimated 2009 production volumes of approximately 10,000 boe/d.General and Administrative Expenses
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($000s, except where noted)                            2008         2007
    -------------------------------------------------------------------------
    Gross expenses                                       20,197       24,191
    Capitalized                                          (2,419)      (3,881)
    Recoveries                                           (1,820)      (2,124)
    -------------------------------------------------------------------------
    Net expenses                                         15,958       18,186
    -------------------------------------------------------------------------
    Net expenses, per unit ($/boe)                         3.67         3.09
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------Interest and Financing Charges

    True recorded $14.8 million of interest and financing charges for the
year ended December 31, 2008 compared to $18.1 million in 2007. True's total
net debt at December 31, 2008 of $215.0 million includes the $81.1 million
liability portion of convertible debentures, $132.4 million of bank debt and
the net balance of working capital. The convertible debentures have a maturity
date of June 30, 2011.Interest and Financing Charges
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($000s, except where noted)                            2008         2007
    -------------------------------------------------------------------------
    Interest and financing charges                       14,822       18,108
    Interest and financing charges ($/boe)                 3.41         3.07

    Debt to funds flow from operations ratio
     annualized
    Total net debt(1) at year end                       215,004      250,313
    Total net debt to periods funds flow from
     operations ratio annualized(2)                        9.2x         3.2x

    Net debt(1) (excluding convertible debentures) at
     year end                                           133,880      171,006
    Net debt to periods funds flow from operations
     ratio annualized(2)                                   5.7x         2.2x

    Debt to funds flow from operations ratio
    Total net debt(1) at year end                       215,004      250,313
    Total net debt to funds flow from operations ratio     2.8x         2.5x

    Net debt(1) (excluding convertible debentures) at
     year end                                           133,880      171,006
    Net debt to funds flow from operations ratio           1.7x         1.7x
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

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

    Non-cash unit-based compensation expense for the year ended December 31,
2008 was $1.4 million compared to $2.0 million in 2007. The 2008 expense
reflects a reduction in the estimated weighted average fair value of incentive
rights granted for more recent options and a reduction to the 2008 expense of
$0.5 million for a reversal of prior year unit-based compensation expense for
2008 forfeitures of unvested incentive rights and reduced incentive rights
being granted in 2008 compared to the 2007 period, offset by $0.5 million of
additional compensation expense for the incentive units voluntarily
surrendered and cancelled in the year.

    Depletion, Depreciation and Accretion

    Depletion, depreciation and accretion expense for 2008 was $128.9 million
($29.68/boe), compared to the $171.5 million ($29.11/boe) in 2007, which
reflects lower production volumes combined with reduced carrying costs in the
2008 period as compared to 2007.
    For the year ended December 31, 2008, True has included $62.8 million for
future development costs in the depletion calculation and excluded from the
depletion calculation $31.3 million for undeveloped land and $42.5 million for
estimated salvage.Depletion, Depreciation and Accretion Costs

    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($000s, except where noted)                            2008         2007
    -------------------------------------------------------------------------
    Depletion and Depreciation                          126,773      169,347
    Accretion                                             2,159        2,137
    -------------------------------------------------------------------------
      Total                                             128,932      171,484
    -------------------------------------------------------------------------
    Per unit ($/boe)                                      29.68        29.11
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------Special Meeting Costs

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

    Capital Expenditures

    True invested $36.7 million on exploration and development activities
during 2008, compared to $87.3 million in 2007.
    During the 2008 year, True had an interest in a total of 38 wells (17.1
net) drilled, which resulted in 7.1 net natural gas wells, 4.0 net light oil
wells, 0.8 net heavy oil well and 1.0 net water disposal well. 4.2 net were
dry and abandoned.
    Included in the above were nine gross natural gas wells that evaluated
True land at no cost to the Company. In eight True has an overriding royalty;
in the other True has no capital cost to drill, complete and tie in, retaining
a 20% working interest from first production. True has over 377,000 net acres
of undeveloped mineral leases in Alberta, British Columbia and Saskatchewan as
of December 31, 2008. An integral component of our growth strategy is to
aggressively farmout our interest in non core areas.Capital Expenditures
    -------------------------------------------------------------------------
                                                     Years ended December 31,
    ($000s)                                                2008         2007
    -------------------------------------------------------------------------
    Lease acquisitions and retention                      1,244        2,084
    Geological and geophysical                              318        4,275
    Drilling and completion costs                        19,008       64,638
    Facilities and equipment                             16,129       15,294
    Other Capital(2)                                          -        1,056
    -------------------------------------------------------------------------
      Exploration and development(1)                     36,699       87,347
    Corporate and property acquisitions                   6,303        1,505
    -------------------------------------------------------------------------
      Total capital expenditures - cash                  43,002       88,852
    Property dispositions - cash                        (44,340)     (31,808)
    -------------------------------------------------------------------------
      Total net capital expenditures - cash              (1,338)      57,044
    -------------------------------------------------------------------------
    Other - non-cash(3)                                   3,710         (530)
    -------------------------------------------------------------------------
      Total net capital expenditures(1)                   2,372       56,514
    -------------------------------------------------------------------------

    (1) Excludes capitalized costs related to asset retirement obligation
        expenditures incurred during the year.
    (2) Other capital for 2007 includes natural gas input costs incurred
        during the initial "warm-up" phase at the Kerrobert SAGD expansion
        project.
    (3) Other includes non-cash adjustments for current period's asset
        retirement obligations and unit based compensation capitalized. For
        2007, it also includes a $(0.8 million) initial fair value adjustment
        for marketable securities acquired.The $43.0 million capital program for the year ended December 31, 2008,
was financed entirely with funds flow from operations.
    During the first quarter of 2008, True was successful in completing the
divestiture of a non-core property in Northeast Alberta for net proceeds of
$5.8 million. During the second quarter of 2008, True disposed of its
Dodsland-Stranraer property located in Saskatchewan for net proceeds of $38.5
million. Total net proceeds from the sale of properties in the 2008 were $44.3
million; the net proceeds from the dispositions were used to pay down debt.
    On October 1, 2008 True closed the purchase of further working interests
in the Mantario, Saskatchewan area for $4.3 million in cash after adjustments.
    Based on the current economic conditions and True's operating forecast
for 2009, the Trust budgets a capital program of $15 million.
    True holds an extensive land base. At December 31, 2008, True had
approximately 377,763 net undeveloped acres of land of its total developed and
undeveloped net acreage position of 677,216 net acres in Saskatchewan,
Alberta, and British Columbia.

    Ceiling Test

    The Trust calculates a ceiling test quarterly and annually to place a
limit on the aggregate carrying value of its capitalized costs, which may be
amortized against revenues of future periods. The ceiling test is performed in
accordance with the requirements of the Canadian Institute of Chartered
Accountants ("CICA") AcG-16 "Oil and Gas Accounting - Full Cost", a two step
process.
    The Trust performed a ceiling test calculation at December 31, 2008
resulting in undiscounted cash flows from proved reserves and the undeveloped
properties not exceeding the carrying value of oil and gas assets.
Consequently, True performed stage two of the ceiling test assessing whether
discounted future cash flows from the production of proved plus probable
reserves plus the carrying cost of undeveloped properties, net of any
impairment allowance, exceeds the carrying value of its petroleum and natural
gas properties. No impairment in oil and gas assets was identified as at
December 31, 2008.
    The ceiling test calculation will be updated in 2009 on a quarterly and
annual basis based upon the latest available data, including but not limited
to an updated annual external reserve engineering report which incorporates a
full evaluation of reserves or internal reserve updates at quarterly periods,
and the latest commodity pricing deck. Estimating reserves is very complex,
requiring many judgments based on available geological, geophysical,
engineering and economic data. Changes in these judgments could have a
material impact on the estimated reserves. These estimates may change, having
either a negative or positive effect on net earnings as further information
becomes available and as the economic environment changes.

    Asset Retirement Obligations

    As at December 31, 2008, the Trust has recorded an Asset Retirement
Obligation ("ARO") of $33.7 million, compared to $28.4 million at December 31,
2007, for future abandonment and reclamation of the Trust's properties. For
the year ended December 31, 2008, the ARO increased by $5.3 million total as a
result of liabilities incurred through corporate acquisitions of $0.3 million,
accretion expense of $2.2 million, and $8.7 million net changes in estimates
and liabilities incurred on development activities, offset by $3.3 million of
liabilities released on dispositions and $2.6 million of liabilities settled
during the year.

    Income Taxes

    For the year ended December 31, 2008, the Trust has recorded capital tax
expense of $2.0 million compared to $2.0 million expensed in 2007. Capital
taxes are based on debt and equity levels of the Trust at the end of the year
in addition to a resource surcharge component of Saskatchewan provincial taxes
calculated as a percentage of revenues.
    Future income taxes arise from differences between the accounting and tax
bases of the Trust's assets and liabilities. For the year ended December 31,
2008, the Trust recognized a future income tax recovery of $20.4 million
compared to a recovery of $59.8 million in 2007.
    Under our current structure, the operating entities make interest and
royalty payments to the Trust, which transfers taxable income to the Trust to
eliminate income subject to corporate and other income taxes in the operating
entities.
    Under the SIFT legislation (as referred to below), such amounts
transferred to the Trust could be taxable beginning in 2011 as distributions
will no longer be deductible for income tax purposes. At that time, True could
claim discretionary tax deductions in its operating companies, reduce the
income transferred to the Trust, and pay all or a portion of distributions as
a return of capital. Until 2011, under the terms of its trust indenture, the
Trust is required to distribute amounts at least equal to its taxable income.
In the event that the Trust has undistributed taxable income in a taxation
year (prior to 2011), an additional special taxable distribution, subject to
certain withholding taxes for non-resident holders, would be required under
the trust indenture.
    The SIFT legislation is not expected to directly affect our cash flow
levels and distribution policies until 2011 at the earliest.

    Enactment of the Tax on Income Trusts

    On June 22, 2007, the legislation implementing a new tax (the "SIFT tax")
on publicly traded income trusts and limited partnerships, referred to as
"Specified investment flow-through" ("SIFTs") entities (Bill C-52) received
Royal Assent. As a result, the SIFT tax was considered to be enacted for
accounting purposes in June 2007, which resulted in a $1.2 million future
income tax recovery amount being recorded in 2007 to reflect current temporary
differences between the book and tax basis of assets and liabilities expected
to be remaining in the Trust in 2011. The SIFT tax announcement and the
related future income tax recovery did not affect cash flow or distributions
and is not expected to affect distribution policies until 2011 at the
earliest.
    SIFTs are certain publicly traded income and royalty trusts and limited
partnerships including True. For SIFTs in existence on October 31, 2006 the
SIFT tax will be effective in 2011, unless certain rules related to "undue
expansion" are not adhered to. Under the guidance provided, True can increase
its equity by approximately $737 million between 2006 and 2011 without
prematurely triggering the SIFT tax.
    In June 2008, Bill C-50, which contained legislation to adjust the deemed
provincial component of the tax rate on distributions from income and royalty
trusts expected to apply to the Trust commencing in 2011, received Royal
Assent. Under proposed regulations, instead of basing the provincial component
of the SIFT tax on a flat rate of 13%, the provincial component will instead
be based on the general provincial corporate income tax rate in each province
in which the SIFT has a permanent establishment. For purposes of calculating
this component of the tax, the general corporate taxable income allocation
formula will be used. Specifically, the Trust's taxable distributions will be
allocated to two provinces by taking half of the aggregate of:-   that proportion of the Trust's taxable distributions for the year
        that the Trust's wages and salaries in the province are of its total
        wages and salaries in Canada; and

    -   that proportion of the Trust's taxable distributions for the year
        that the Trust's gross revenues in the province are of its total
        gross revenues in Canada.Under the proposed regulations, the Trust would be considered to have a
permanent establishment only in Alberta, where the provincial tax rate in 2011
is expected to be 10%. As the regulations were not substantively enacted for
accounting purposes as at December 31, 2008, the 13% flat rate is used for
financial statement purposes.
    On July 14, 2008, the Department of Finance released proposed amendments
(the "Conversion Rules") to the Income Tax Act (Canada) to facilitate the
conversion of existing income trusts into corporations. In general, the
proposed amendments will permit a conversion to be tax deferred for both the
unitholders and the income trust if completed before 2013. These rules were
subsequently revised and introduced as part of Bill C-10 as part of the Budget
Implementation Act, 2009 on February 6, 2009. Further revisions are expected
as it is debated in the House of Commons.
    The True Board of Directors and Management continue to review the impact
of this tax on business strategy as well as the Conversion Rules in
considering alternatives available. At the present time, True believes some or
all of the following actions will or could result due to the enactment of the
SIFT tax:-   If structural or other similar changes are not made, the distribution
        yield net of the SIFT tax in 2011 and beyond to taxable Canadian
        investors will remain approximately the same; however, the
        distribution yield to tax-deferred Canadian investors (RRSPs, RRIFs,
        pension plans, etc.) would fall by an estimated 26.5 percent in 2011
        and 25.0 percent in 2012 and beyond. For U.S. investors, the
        distribution yield net of the SIFT and withholding taxes would fall
        by an estimated 25.3 percent in 2011 and 25.1 percent in 2012 and
        beyond;
    -   A portion of True's cash flow could be allocated to the payment of
        the SIFT tax, or other forms of tax, and would not be available for
        distribution or re-investment;
    -   True could convert to a corporate structure to facilitate investing a
        higher proportion or all of its cash flow in exploration and
        development projects. Such a conversion and change to capital
        programs could result in a significant reduction to or elimination of
        distributions and/or dividends;
    -   True might determine that it is more economic to remain in the trust
        structure, at least for a period of time, and shelter its taxable
        income using discretionary tax deductions and pay all or a portion of
        its distributions (if any) on a return of capital basis, likely at a
        lower payout ratio.The Trust is reviewing all organizational structures and alternatives to
minimize the impact of the SIFT tax on our unitholders. While there can be no
assurance that the negative effect of the tax can be minimized or eliminated,
True and its advisors will continue to work diligently on these issues.
    As at December 31, 2008, the operating subsidiaries and the Trust itself
have a total net future income tax liability balance of $43.9 million.
Canadian GAAP requires that a future income tax liability be recorded when the
book value of assets exceeds the balance of tax pools.
    At December 31, 2008, the Trust and operating subsidiaries of the Trust
had approximately $495 million in tax pools available for deduction against
future income as follows:-------------------------------------------------------------------------
                                                      Operating
    ($000s)                                  Trust subsidiaries        Total
    -------------------------------------------------------------------------
    Intangible resource pools               15,000      306,000      321,000
    Undepreciated capital cost                   -      128,000      128,000
    Loss carryforwards (expire through
     2027)                                       -       40,000       40,000
    Unit issue costs                         4,000        2,000        6,000
    -------------------------------------------------------------------------
                                            19,000      476,000      495,000
    -------------------------------------------------------------------------


    Distributions

    Trust unitholders who held their trust units throughout 2008 received
distributions of $0.46 per unit. For the year ended December 31, 2008 the
Trust declared distributions as follows:


    -------------------------------------------------------------------------
    ($000s, except per unit amount)                Distribution
    Year ended December 31, 2008                       Per Unit        Total
    -------------------------------------------------------------------------

    Distributions declared                           $     0.46   $   36,334
    -------------------------------------------------------------------------


    Distribution Paid History(1)

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


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

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

    2005 (two months)(2)                $    0.480   $    0.456   $    0.024
    2006                                $    2.640   $    2.033   $    0.607
    -------------------------------------------------------------------------
    Cumulative to Dec. 31, 2006         $    3.120   $    2.489   $    0.631
    -------------------------------------------------------------------------
    2007 year                           $    0.960   $    0.960            -
    -------------------------------------------------------------------------
    Cumulative to Dec. 31, 2007         $    4.080   $    3.449   $    0.631
    -------------------------------------------------------------------------
    2008 year                           $    0.460   $    0.460            -
    -------------------------------------------------------------------------
    Cumulative to December 31, 2008(3)  $    4.540   $    3.909   $    0.631
    -------------------------------------------------------------------------
    2009 year to date (one month)(4)    $    0.020
    -----------------------------------------------
    Cumulative to January 31, 2009      $    4.560
    -----------------------------------------------

    (1) Applies to unitholders who are residents of Canada and hold their
        trust units as capital property.
    (2) Based upon the distributions paid in the 2005 calendar year, after
        the November 2, 2005 Arrangement with TKE Energy Trust.
    (3) For Canadian tax purposes, 2008 distributions were determined to be
        100% taxable.

        In consultation with its U.S. tax advisors, True believes that its
        Trust units should be "qualified dividends" for U.S. federal
        purposes. As such, the portion of distributions made during 2008 that
        are considered dividends for U.S. federal purposes should qualify for
        the reduced rate of tax applicable to long-term capital gains.
        Unitholders or potential unitholders should consult their own legal
        or tax advisors as to their particular income tax consequences of
        holding True units. Please review our February 19, 2009 press release
        addressing this.

    (4) It is currently estimated that the approximate taxable portion of the
        January 2009 distribution to Canadian unitholders will be 100%. Any
        non-taxable amounts will be treated as a tax deferred return of
        capital, or an adjustment to the cost base of the units. Actual
        taxable amounts may vary depending on actual distributions and are
        dependent upon production, commodity prices and funds flow from
        operations experienced throughout the year.


    Monthly Distributions

    Actual distributions paid and declared per Trust unit along with relevant
payment dates for 2008 and 2009 to date are as follows:


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

                                                                Distribution
    Ex-distribution Date   Record Date          Payment Date        per unit
    -------------------------------------------------------------------------
    December 27, 2007      December 31, 2007    January 15, 2008      $ 0.08
    January 29, 2008       January 31, 2008     February 15, 2008       0.04
    February 27, 2008      February 29, 2008    March 17, 2008          0.04
    March 27, 2008         March 31, 2008       April 15, 2008          0.04
    April 28, 2008         April 30, 2008       May 15, 2008            0.04
    May 28, 2008           May 30, 2008         June 16, 2008           0.04
    June 26, 2008          June 30, 2008        July 15, 2008           0.04
    July 29, 2008          July 31, 2008        August 15, 2008         0.04
    August 27, 2008        August 29, 2008      September 15, 2008      0.04
    September 26, 2008     September 30, 2008   October 15, 2008        0.04
    October 29, 2008       October 31, 2008     November 17, 2008       0.04
    November 26, 2008      November 28, 2008    December 15, 2008       0.04
    December 29, 2008      December 31, 2008    January 15, 2009        0.02
    January 28, 2009       January 30, 2009     February 17, 2009       0.02
    -------------------------------------------------------------------------During 2008, funding requirements for distributions declared was 47% of
funds flow from operations.
    As announced on February 9, 2009, due to the continued deterioration in
economic conditions, including the significant decline in crude oil prices, a
weakening outlook for natural gas demand and heightened risk in the credit
markets at the start of 2009, True has deemed it prudent to suspend March 2009
distributions to maintain corporate liquidity during the current financial
turmoil and prevailing commodity price environment. Accordingly, no
distributions will be paid in March 2009 to unitholders of record as at
February 27, 2009.
    Distributions are to be reviewed monthly in the context of commodity
prices, among other factors, and are subject to revision by the Board of
Directors.

    Foreign Ownership Update

    Based on information from Trust records and information provided by
intermediaries holding Trust units for others, the Trust estimates that, as of
February 20, 2009 approximately 25 percent of unitholders are non-Canadian
residents with the remaining 75 percent being Canadian residents.
    In order that the Trust maintain its status as a "mutual fund trust"
under the Income Tax Act (Canada), certain provisions of the Income Tax Act
(Canada) require that the trust not be established or maintained primarily for
the benefit of non-residents of Canada ("non-residents"). The trust indenture
for the Trust provides that if the Trust or its administrator becomes aware
that the activities of the Trust and ownership of Trust units by non-residents
may threaten the status of the Trust under the Income Tax Act (Canada) as a
"unit trust" or "mutual fund trust", the Trust is authorized to take action as
may be necessary to maintain the status of the Trust as a unit trust and a
mutual fund trust, including the imposition or restrictions on the issuance by
the Trust, or the transfer of any unitholder, of Trust units to a
non-resident.

    Liquidity and Capital Resources

    As an oil and gas business, the Trust has a declining asset base and
therefore relies on ongoing development and acquisitions to replace production
and add additional reserves. Future oil and natural gas production and
reserves are highly dependent on the success of exploiting the Trust's
existing asset base and in acquiring additional reserves. To the extent the
Trust is successful or unsuccessful in these activities, funds flow could be
increased or reduced.
    Global financial markets have recently experienced severe turmoil. This
economic crisis has spread resulting in a tightening of credit markets
characterized by a decline in liquidity and higher borrowing costs. Access to
capital markets has become constrained and significantly more expensive for
the Trust along with other oil and gas entities. The current global economic
environment has also created volatility in commodity prices, tempered somewhat
by the growing US to Canadian dollar exchange rate. Given the current
uncertain economic conditions, the Trust revised the level of capital spending
for 2009 and suspended its March 2009 distribution. The Trust plans to
continue to monitor forecasted debt levels to manage its operations within
forecasted cash flow. In addition, the Trust will continue to monitor
developments within the global economic environment to consider the impacts on
current or future lending arrangements.
    Liquidity risk is the risk that the Trust will not be able to meet its
financial obligations as they fall due. The Trust actively manages its
liquidity through daily and longer-term cash, debt and equity management
strategies. Such strategies encompass, among other factors: having adequate
sources of financing available through its bank credit facilities, estimating
future cash generated from operations based on reasonable production and
pricing assumptions, analysis of economic hedging opportunities, and
maintaining sufficient cash flows for compliance with debt covenants.
    The Trust generally relies on operating cash flows and its credit
facilities to fund capital requirements and provide liquidity. Future
liquidity depends primarily on cash flow generated from operations, existing
credit facilities and the ability to access debt and equity markets. From time
to time, the Trust accesses capital markets to meet its additional financing
needs and to maintain flexibility in funding its capital programs. There can
be no assurance that debt or equity financing, or cash generated by operations
will be available or sufficient to meet these requirements or for other
corporate purposes or, if debt or equity financing is available, that it will
be on terms acceptable to the Trust. The inability of the Trust to access
sufficient capital for its operations could have a material adverse effect on
the Trust's business financial condition, results of operations and prospects.
    Credit risk is the risk of financial loss to the Trust if a customer or
counterparty to a financial instrument fails to meet its contractual
obligations, and arises principally from the Trust's trade receivables from
joint venture partners, petroleum and natural gas marketers, and financial
derivative counterparties.
    A substantial portion of the Trust's accounts receivable are with
customers and joint interest partners in the petroleum and natural gas
industry and are subject to normal industry credit risks. The Trust sells
substantially all of its production to eight primary purchasers under standard
industry sale and payment terms. Purchasers of the Trust's natural gas, crude
oil and natural gas liquids are subject to a periodic internal credit review
to minimize the risk of non-payment. The Trust has continued to closely
monitor and reassess the creditworthiness of its counterparties, including
financial institutions. This has resulted in the Trust reducing or mitigating
its exposures to certain counterparties where it is deemed warranted and
permitted under contractual terms.
    The Trust may be exposed to third party credit risk through its
contractual arrangements with its current or future joint venture partners,
marketers of its petroleum and natural gas production and other parties. In
the event such entities fail to meet their contractual obligations to the
Trust, such failures may have a material adverse effect on the Trust's
business, financial condition, results of operations and prospects. In
addition, poor credit conditions in the industry and of joint venture partners
may impact a joint venture partner's willingness to participate in the Trust's
ongoing capital program, potentially delaying the program and the results of
such program until the Trust finds a suitable alternative partner.
    The Trust does not hold any Asset-Backed Commercial Paper investments. As
a non-operating working interest owner, True has a minor exposure of
approximately $70,000 from oil sales marketed through SemCanada Crude Company,
which filed for CCAA protection on July 22, 2008. True does not have any
exposure to Lehman Brothers, which filed for Chapter 11 bankruptcy protection
in the United States. To the best of True's knowledge, the Trust does not have
any exposure to other US financial institutions.
    During 2008 and in 2009, the Trust has been executing several strategies
for dealing with these uncertain times.
    True's corporate thrust in 2008 was to improve the Trust's balance sheet
by reducing total outstanding debt and streamlining its operating cost
structure. This strategy resulted in a reduced 2008 capital program of $43
million, from $88.9 million in 2007, and strategic divestitures which were
expected to negatively impact reserves and production.
    The consequence of this planned activity was total net debt levels
decreased by $35.3 million from $250.3 million at December 31, 2007 to $215.0
million at December 31, 2008. Total net debt excludes unrealized commodity
contract assets and liabilities, future income taxes and asset retirement
obligations. The accompanying reduction posted in reserves and production was
within the planned parameters. Combined funding requirements for distributions
declared and True's capital expenditures represented 102% of funds flow from
operations in 2008. Since December 31, 2006, the Trust has managed to reduce
total net debt by approximately $60.8 million.
    As a result of the continued deterioration in economic conditions,
including the significant decline in crude oil prices, a weakening outlook for
natural gas demand and a heightened risk in the credit markets at the start of
2009, True has deemed it prudent to suspend distributions to maintain
corporate liquidity during the current financial turmoil and prevailing
commodity price environment. Accordingly, no distributions will be paid in
March 2009 to unitholders of record as at February 27, 2009. Distributions are
to be reviewed monthly in the context of commodity prices, among other
factors, and are subject to revision by the Board of Directors.
    True continues to tighten its cost structure in the current economically
challenging climate with forecasted cuts from 2008 levels of 30% to total
operating expenses which includes general and administrative costs ("G&A") and
lease operating costs in 2009.
    As stated in the press release dated January 20, 2009 True has further
reduced its capital budget in 2009 to $15 million. True is not planning to
drill any operated wells in the first half of 2009 and will limit capital
spending to $3 million in the first six months of 2009. The first half 2009
capital spending will be limited to the tie-in of two successful Saddlelake
natural gas wells drilled in the fourth quarter of 2008, performing necessary
maintenance programs required due to extreme winter conditions in Alberta and
Saskatchewan and focusing on increasing production from existing wells through
workovers. True believes that industry costs currently do not reflect
commodity prices and netback realizations. Our capital program for 2009 which
is not expected to exceed $15 million will reflect our future view of
commodity pricing, available acquisition opportunities, and trends in
operating costs. True is forecasting 2009 production volumes to average
approximately 10,000 boe/d.
    True's operating forecast for 2009 which assumes a CAD$/US$ exchange rate
of $0.82, WTI oil price ranging from US$50.00/bbl to US$55.00/bbl, AECO
natural gas price ranging from CAD$5.46/GJ ($6.00/mcf) to CAD$5.92/GJ
($6.50/mcf) and average annual production of approximately 10,000 boe/d
generates cash flow from operations ranging from $30 million to $40 million,
after deducting royalties, all operating costs (as reduced as discussed
herein), G&A and debt servicing costs. Based on the foregoing assumptions and
assuming 2009 distributions of $1.6 million coupled with the planned capital
budget of $15 million the Trust would utilize between 40% - 60% of the Trust's
forecasted funds flow from operations.
    As an added layer of protection of its cash flow forecast, True has
hedged approximately 60% of its estimated 2009 natural gas production for the
period of March 1, 2009 to September 30, 2009 and 49% is hedged for the fourth
quarter of 2009 at a combined fixed price of $6.42 CAD per GJ ($7.06/mcf).
Approximately 18% of True's estimated natural gas production is hedged for the
first half of 2010 at an average price of $7.25 CAD per GJ ($7.96/mcf). For
the period of March 1, 2009 to December 31, 2009, True has entered into a
crude oil collar to effectively hedge approximately 13% of its estimated 2009
crude oil production with a floor price of USD $42.50/bbl and a ceiling price
of USD $65.60/bbl. True maintains an active commodity price risk management
program focused on maintaining sufficient cash flow to fund its operations.
    True's revolving term credit facility was renewed on June 27, 2008 and
consists of a $15 million demand operating facility provided by one Canadian
bank and a $137 million extendible revolving credit facility syndicated by two
Canadian chartered banks, a Canadian financial institution, one institutional
lender and a U.S. bank. $12.5 million of the syndicated facility is with a US
bank which may be required to be repaid or reallocated to one or more of the
other four current members of the syndicate or a new member on June 28, 2009.
The revolving period on the revolving term credit facility ends on June 26,
2009, unless extended for a further 364 day period. Should the facilities not
be renewed they convert to 366 day non-revolving facilities on the renewal
date. The borrowing base was renewed effective September 30, 2008 and is
currently scheduled for review by March 31, 2009. The borrowing base will be
subject to the lending syndicate's determination which is based upon the
latest reserves information, their internal commodity price decks and other
factors. In the event the borrowing base is lowered below the drawn credit
facility at that time, any shortfall would be required to be repaid within 60
days of notification, or as otherwise agreed by the lending syndicate, and
this funding would currently be expected to come from alternative sources of
debt or equity financing or the proceeds from asset dispositions as available.
As at December 31, 2008, there was approximately $19.6 million not drawn (and
was available) under these facilities.
    There are currently no capital commitments, other than those associated
with the Trust's credit facilities outlined above and its 2009 capital program
of $3 million for the first half of 2009. The Trust continually monitors its
capital spending program in light of the recent volatility with respect to
commodity prices and Canadian dollar exchange rates with the aim of ensuring
the Trust will be able to meet future anticipated obligations incurred from
normal ongoing operations with funds flow from operations and draws on the
Trust's syndicated facility, as necessary. As announced on February 9, 2009,
no Trust unit distributions will be paid in March 2009 to unitholders of
record as at February 27, 2009. Distributions are to be reviewed monthly in
the context of commodity prices, among other factors, and are subject to
revision by the Board of Directors.
    On June 15, 2006 the Trust completed a bought deal public offering of
86,250 7.5% convertible unsecured subordinated debentures at a price of $1,000
per debenture for aggregate gross proceeds of $86,250,000. The debentures have
a face value of $1,000 per debenture and a maturity date of June 30, 2011. The
debentures bear interest at an annual rate of 7.50% payable semi-annually on
June 30 and December 31 in each year commencing December 31, 2006. The
debentures are convertible at anytime at the option of the holders into Trust
units of the Trust at a conversion price of $16.00 per trust unit. The Trust
will have the right to redeem all or a portion of the debentures at a price of
$1,050 per debenture after June 30, 2009 and on or before June 30, 2010 and at
a price of $1,025 per debenture after June 30, 2010 and before the maturity
date. Upon maturity or redemption of the debentures, the Trust may, subject to
notice and regulatory approval, pay the outstanding principal and premium (if
any) on the debentures in cash or through the issue of additional Trust units
at 95% of the weighted average trading price of the Trust units.
    In November 2008, the Trust received Toronto Stock Exchange approval for
its normal course issuer bid ("NCIB") program to repurchase up to 10% of the
issued and outstanding 7.50% convertible unsecured subordinated debentures of
the Trust ("Debentures") from December 1, 2008 to November 30, 2009. True
believes that, from time to time, the market price of the Debentures may not
fully reflect the underlying value of the Debentures and that at such times
the purchase of the Debentures would be in the best interests of the Trust.
Such purchases will increase the proportionate interest of, and may be
advantageous to, all remaining holders of Debentures as well as holders of
Trust units. To date, no repurchases of the Debentures have been made under
this NCIB.
    In August 2008, the Trust announced approval of the renewal of its normal
course issuer bid program to repurchase up to 7.8 million of its outstanding
Trust units during the period August 28, 2008 through August 27, 2009, subject
to certain restrictions. As of December 31, 2008, the Trust has purchased
615,100 Trust units at a weighted average price of $2.74 per Trust unit under
the NCIB renewed on August 28, 2008. No further repurchases have been made in
2009 to date. This purchase is in response to True's belief that the current
market price for Trust units does not reflect the underlying value of the
Trust and the cancellation of the above purchased Trust Units will increase
the proportionate interest of, and be advantageous to, all remaining
unitholders. Future repurchases will be dependent on excess cash available
after consideration of the Trust's priority uses of cash and the trading price
of the Trust units.
    As at February 27, 2009, the Trust had outstanding a total of 2,107,993
incentive units exercisable at an average exercise price of $3.83 per unit,
294,026 exchangeable shares (convertible, as at February 27, 2009 into an
aggregate of 312,467 Trust units, subject to further adjustments based on
distributions made on Trust units), $86.25 million principal amount of
debentures convertible into trust units (at a conversion price of $16.00 per
Trust unit) and 78,496,581 Trust units. The details of the Trust's unit
incentive rights outstanding for the year ended December 31, 2008 are
summarized in note 9(b) of the financial statements.

    Related Party Transactions

    The Trust received legal services from a law firm in which a current
director and corporate secretary is a partner. The fees charged are based on
standard rates and time spent on matters pertaining to the Trust and its
subsidiaries. The services provided were in the normal course of operations
and have been recorded at the exchange amount. For the year ended December 31,
2008, legal fees received from the related party totaled $0.6 million (2007:
$1.2 million).

    Commitments

    The Trust has committed to various corporate sponsorships extending to
June 2011 at an estimated combined cost of up to $228,000.

    Off-Balance Sheet Arrangements

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

    The Trust is committed to payments under operating leases for office
space as follows:-------------------------------------------------------------------------
    ($000s)                                            Expected
    Year                              Gross Amount   Recoveries   Net amount
    -------------------------------------------------------------------------
    2009                                     1,824        1,034          790
    2010                                     2,146          883        1,263
    2011                                     2,207          897        1,310
    2012                                     2,218          737        1,481
    2013                                     2,218          737        1,481
    -------------------------------------------------------------------------Business Prospects and 2009 Year Outlook

    The Trust continues to develop its core assets and conduct some
exploration programs utilizing its large inventory of geological prospects. In
addition, the Trust will continue to explore potential acquisition
opportunities. Currently, the Trust's producing properties are located in
Saskatchewan, Alberta and British Columbia.
    The Trust continues to maintain a large undeveloped land base of
approximately 586,087 (377,763 net) acres containing a significant multi-year
drilling inventory.
    True continues to tighten its cost structure in the current economically
challenging climate with forecasted cuts of approximately 30% to total
operating expenses which includes general and administrative costs ("G&A") and
lease operating costs in 2009. As stated in the press release dated January
20, 2009 True has further reduced its capital budget in 2009 to $15 million
and is forecasting 2009 production volumes to average approximately 10,000
boe/d.
    As an added layer of protection of its cash flow forecast, True has
hedged approximately 60% of its estimated 2009 natural gas production for the
period of March 1, 2009 to September 30, 2009 and 49% is hedged for the fourth
quarter of 2009 at a combined fixed price of $6.42 CAD per GJ ($7.06/mcf).
Approximately 18% of True's estimated natural gas production is hedged for the
first half of 2010 at an average price of $7.25 CAD per GJ ($7.96/mcf). For
the period of March 1, 2009 to December 31, 2009, True has entered into a
crude oil collar to effectively hedge approximately 13% of its estimated 2009
crude oil production with a floor price of USD $42.50/bbl and a ceiling price
of USD $65.60/bbl.
    True's operating forecast for 2009 which assumes a CAD$/US$ exchange rate
of $0.82, WTI oil price ranging from US$50.00/bbl to US$55.00/bbl, AECO
natural gas price ranging from CAD$5.46/GJ ($6.00/mcf) to CAD$5.92/GJ
($6.50/mcf) and average annual production of approximately 10,000 boe/d
generates cash flow from operations ranging from $30 million to $40 million,
after deducting royalties, all operating costs (as reduced as discussed
herein), G&A and debt servicing costs. Based on the foregoing assumptions and
assuming 2009 distributions of $1.6 million coupled with the planned capital
budget of $15 million the Trust would utilize between 40% - 60% of the Trust's
forecasted cash flow from operations.
    True's 2009 capital program is not expected to exceed $15 million and
will limit the first half 2009 capital program to $3 million. Given the nature
of True's lands and their inherent advantage of year round access, True
currently plans to spread its 2009 capital program evenly through the full
year of 2009 to take advantage of reduced service costs during non-peak times.
True will focus on increasing its farm-out activity in non-core areas. If the
2009 outlook for commodity prices improves, True would plan to increase its
capital spending in third and fourth quarters of 2009 dependant upon cash
flow.

    Financial Reporting Update

    Capital disclosures

    The CICA issued a new accounting standard, Section 1535 "Capital
Disclosures", which requires the disclosure of both qualitative and
quantitative information that provides users of financial statements with
information to evaluate the entity's objective, policies and processes for
managing capital. This new section is effective for the Trust beginning
January 1, 2008. Refer to note 18 of the financial statements for additional
disclosure for this new section.

    Financial instruments

    Two new accounting standards were issued by the CICA, Section 3862
"Financial Instruments - Disclosures", and Section 3863 "Financial Instruments
- Presentation". These sections replaced Section 3861 "Financial Instruments -
Disclosure and Presentation" as adopted. The objective of Section 3862 is to
provide users with information to evaluate the significance of the financial
instruments on the entity's financial position and performance, the nature and
extent of risks arising from financial instruments, and how the entity manages
those risks. The provisions of Section 3863 deal with the classification of
financial instruments, related interest, dividends, losses and gains, and the
circumstances in which financial assets and financial liabilities are offset.
These new sections are effective for the Trust beginning January 1, 2008. The
additional disclosures required under these sections are included in note 18
of the financial statements.

    Goodwill and intangible assets

    In February 2008, the CICA issued a new accounting standard, Section 3064
- Goodwill and Intangible Assets, which replaces Section 3062 - Goodwill and
Other Intangible Assets, and Section 3450 - Research and Development costs.
The new section establishes standards for the recognition, measurement and
disclosure of goodwill and intangible assets. The section is effective for the
Trust beginning January 1, 2009. Application of the new section is not
currently expected to have any impact on the Trust's financial statements.

    International Financial Reporting Standards ("IFRS")

    On February 13, 2008 the CICA Accounting Standards Board announced that
Canadian public reporting issuers will be required to report under
International Financial Reporting Standards ("IFRS"), which will replace
Canadian generally accepted accounting principles ("GAAP") for years beginning
on or after January 1, 2011. The transition date of January 1, 2011 will
require restatement for comparative purposes, of amounts reported by the Trust
for its year ended December 31, 2010, and of the opening balance sheet as at
January 1, 2010. An internal project team has been set up to manage this
transition and to ensure successful implementation within the required time
frame. Current economic conditions may require re-allocation of resources
available for the IFRS conversion project. The Trust has completed a high
level analysis to determine the areas impacted by the conversion and is
assessing the financial reporting impacts on the adoption of IFRS and, at this
time, the impact on future financial position and results of operations has
not yet been determined. True is also monitoring industry discussion regarding
the replacement of the CICA's Accounting Guideline 16, which is expected to
have major implications for True's current full cost accounting policies. The
Trust anticipates a significant increase in disclosures resulting from the
adoption of IFRS and is continuing to assess the level of this disclosure
required and any necessary systems changes to gather and process the
information. We will continue to monitor any changes in the adoption of IFRS
and will update plans as necessary.

    Business Risks and Uncertainties

    General

    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.

    Environmental Regulations and Risks

    The oil and natural gas industry is currently subject to environmental
regulations pursuant to a variety of provincial and federal legislation. Such
legislation provides for restrictions and prohibitions on the release or
emission of various substances produced in association with certain oil and
gas industry operations. In addition, such legislation requires that well and
facility sites be abandoned and reclaimed to the satisfaction of provincial
authorities. Compliance with such legislation can require significant
expenditures and a breach of such requirements may result in suspension or
revocation of necessary licenses and authorizations, civil liability for
pollution damage, and the imposition of material fines and penalties.
    Environmental legislation in the Province of Alberta has been
consolidated into the Environmental Protection and Enhancement Act (Alberta)
(the "EPEA"), which came into force on September 1, 1993, and the Oil and Gas
Conservation Act (Alberta) (the "OGCA"). The EPEA and OGCA impose stricter
environmental standards, require more stringent compliance, reporting and
monitoring obligations, and significantly increased penalties. In 2006, the
Alberta Government enacted regulations pursuant to the EPEA to specifically
target sulphur oxide and nitrous oxide emissions from industrial operations
including the oil and gas industry. In addition, the reduction emission
guidelines outlined in the Climate Change and Emissions Management Amendment
Act came into effect on July 1, 2007 ("CCEMAA"). Under this legislation,
Alberta facilities emitting more than 100,000 tonnes of greenhouse gases a
year must reduce their emissions intensity by 12%. Industries have three
options to choose from in order to meet the reduction requirements outlined in
this legislation, and these are: (i) by making improvement to operations that
result in reductions; (ii) by purchasing emission credits from other sectors
or facilities that have emissions below the 100,000 tonne threshold and are
voluntarily reducing their emission; or (iii) by contributing to the Climate
Change and Emissions Management Fund (the "Fund"). Industries can either
choose one of these options or a combination thereof. Pursuant to CCEMAA and
the Specified Gas Emitters Regulation, companies were obliged to reduce their
emission intensity by 12% by March 31, 2008. Alberta industries have achieved
2.6 million tonnes of actual reduction, due to changes in operations and
investing on verified offset projects. In addition, certain companies
contributed $40 million to the Fund. The Trust will be committed to meeting
its responsibilities to protect the environment wherever it operates and
anticipates making increased expenditures of both a capital and an expense
nature as a result of the increasingly stringent laws relating to the
protection of the environment, and will be taking such steps as required to
ensure compliance with the EPEA and similar legislation in other jurisdictions
in which it operates. The Trust believes that it is in material compliance
with applicable environmental laws and regulations. It is reasonably likely
that the trend towards stricter standards in environmental legislation and
regulation will continue.
    On January 24, 2008, the Alberta Government announced a new climate
change action plan that will cut Alberta's projected 400 million tonnes of
emissions in half by 2050. This plan is based on three areas: (i) carbon
capture and storage, which will be mandatory for in situ oil sand facilities
that use heavy fuels for steam generation; (ii) energy conservation and
efficiency; and (iii) greening production through increased investment in
clean energy technology, including supporting research on new oil sands
extraction processes, as well as the funding of projects that reduce the cost
of separating carbon dioxide from other emissions supporting carbon capture
and storage. In addition to this action plan, the Provincial Energy Strategy
unveiled on December 11, 2008 is expected to, among other things, support the
upgrading, refining and petrochemical clusters existing in the Province,
market Alberta's energy internationally, review the emission targets and
carbon charges applied to large facilities, and promote the innovation of
energy technology by encouraging investment in research and development.
    British Columbia's Environmental Assessment Act became effective June 30,
1995. This legislation rolls the previous processes for the review of major
energy projects into a single environmental assessment process with public
participation in the environmental review process. On February 27, 2007 the
Government of British Columbia unveiled the Energy Plan outlining the
Province's strategy towards the environment and which includes targeting for
zero net greenhouse gas emissions, promoting new investments in innovation,
and becoming the world's leader in sustainable environmental management. For
this purpose, on December 18, 2007 proposals were sought for applications to
the Innovative Clean Energy Fund, in order to attract new technologies that
will help solve energy and environmental issues. With regards to the oil and
gas industry the objective is to achieve clean energy through conservation and
energy efficient practices, whilst competitiveness is advocated in order to
attract investment for the development of the oil and gas sector. Among the
changes to be implemented are: (i) a new of Net Profit Royalty Program; (ii)
the creation of a Petroleum Registry; (iii) the establishment of an
infrastructure royalty program (combining roads and pipelines); (iv) the
elimination of routine flaring at producing wells; (v) the creation of
policies and measures for the reduction of emissions; (vi) the development of
unconventional resources such as tight gas and coal bed gas; and (vii) new the
Oil and Gas Technology Transfer Incentive Program that encourages the
research, development and use of innovative technologies to increase
recoveries from existing reserves and promotes responsible development of new
oil and gas reserves. Furthering these initiatives, the Provincial Government
introduced on July 1, 2008, revenue-neutral carbon tax legislation that is
applied to all fossil fuels used in the Province. The tax would be phased in,
and the initial rate would be based on CO2e of $10 per tonne for the first six
months of 2009 and $15 per tonne for the last six months of 2009, following $5
per tonne increases on July of every year until 2012. Tax credits and
reductions will be used in order to offset the tax revenues that the
Government would receive otherwise. On April 3, 2008, the Government of
British Columbia introduced the Greenhouse Gas Reduction (Cap and Trade) Act
which will allow the Province to participate in the Western Climate Initiative
cap and trade systems being developed. The system establishes a limit on
emissions, and allows regulated emitters to buy/sell emission allowances or
offset emits. The emitter is obliged to obtain emission allowances (compliance
units) equal to the amount of greenhouse gases emitted within a certain period
of time, and that are supposed to be surrendered to the Government as
compliance proof.
    In December 2002, the Government of Canada ratified the Kyoto Protocol
("Kyoto Protocol"). The Kyoto Protocol calls for Canada to reduce its
greenhouse gas emissions to 6% below 1990 "business-as-usual" levels between
2008 and 2012. Given revised estimates of Canada's normal emissions levels,
this target translates into an approximately 40% gross reduction in Canada's
current emissions. It is questionable, based on the Updated Action Plan
announced by the Federal Government (see below), that the Kyoto Protocol
target of 6% below 1990 emission levels will be enforced in Canada. Bill
C-288, which is intended to ensure that Canada meets its global climate change
obligations under the Kyoto Protocol, was passed by the House of Commons on
February 14, 2007. On April 26, 2007, the Federal Government released its
Action Plan to Reduce Greenhouse Gases and Air Pollution (the "Action Plan")
also known as ecoACTION which includes the regulatory framework for air
emissions. This Action Plan covers not only large industry, but regulates the
fuel efficiency of vehicles and the strengthening of energy standards for a
number of energy using products.
    The Government of Canada and the Province of Alberta released on January
31, 2008 the final report of the Canada-Alberta ecoENERGY Carbon Capture and
Storage Task Force, which recommends among others: (i) incorporating carbon
capture and storage into Canada's clean air regulations; (ii) allocating new
funding into projects through competitive process; and (iii) targeting
research to lower the cost of technology.
    In order to strengthen the Action Plan, on March 10, 2008, the Government
of Canada released "Turning the Corner - Taking Action to Fight Climate
Change" (the "Updated Action Plan") which provides some additional guidance
with respect to the Government's plan to reduce greenhouse gas emissions by
20% by 2020 and by 60% to 70% by 2050. Details of the Updated Action Plan are
provided in the Trust's Annual Information Form for the year ended December
31, 2007.
    Given the evolving nature of the debate related to climate change and the
control of greenhouse gases and resulting requirements, it is not currently
possible to predict either the nature of those requirements or the impact on
the Trust and its operations and financial condition at this time.

    Alberta Royalty Regime

    On January 1, 2009, the Alberta Government implemented changes to royalty
rates under a New Royalty Framerwork ("NRF") previously announced on October
25, 2007. In 2008, the Alberta Government also announced, but not yet enacted
as of December 31, 2008, provisions that allow for transitional royalties
("Transitional Royalties") to the NRF for certain wells. These Transitional
Royalties are not reflected in December 31, 2008 reserve report of the Trust's
independent reserves evaluator, GLJ Petroleum Consultants Ltd. ("GLJ").
However, in conjunction with the 2008 year-end reserve evaluation, GLJ did
provide analysis of the sensitivity calculation in respect of the Transitional
Royalties for forecast drilling, utilizing the Consultants' Consensus
Methodology recommended by the Society of Petroleum Engineers, Calgary Chapter
(the "Consensus Methodology"). Based on public information available when the
Trust's reserves were evaluated, the net present value of future net revenue
of proved and proved plus probable reserves based on a 10% discount rate using
the Consultants' Methodology taking into account the Transitional Royalties
utilizing Consensus Methodology Prices would represent an increase of less
than 0.5%, in each case, as compared to the existing royalty rules which
exclude the Transitional Royalties. The proposed royalty changes are very
sensitive to production rate and natural gas prices.
    The majority of True's current Alberta wells are in the 500m to 1,000m
depth range and typically produce at lower rates. The overall impact of the
NRF is mitigated by the Trust's current Saskatchewan properties and the lower
shallow gas Alberta natural gas rate royalty production in True's Alberta
conventional oil and gas production portfolio. The NRF will impact future
drilling decisions in order for the Trust to maintain acceptable rates of
return on its capital deployed.

    Global Financial Crisis

    Recent market events and conditions, including disruptions in the
international credit markets and other financial systems and the deterioration
of global economic conditions, have caused significant volatility to commodity
prices. These conditions worsened in 2008 and are continuing in 2009, causing
a loss of confidence in the broader U.S. and global credit and financial
markets and resulting in the collapse of, and government intervention in,
major banks, financial institutions and insurers and creating a climate of
greater volatility, less liquidity, widening of credit spreads, a lack of
price transparency, increased credit losses and tighter credit conditions.
Notwithstanding various actions by governments, concerns about the general
condition of the capital markets, financial instruments, banks, investment
banks, insurers and other financial institutions caused the broader credit
markets to further deteriorate and stock markets to decline substantially.
These factors have negatively impacted company valuations and will impact the
performance of the global economy going forward.
    Petroleum prices are expected to remain volatile for the near future as a
result of market uncertainties over the supply and demand of these commodities
due to the current state of the world economies, OPEC actions and the ongoing
global credit and liquidity concerns.

    Substantial Capital Requirements

    The Trust anticipates making substantial capital expenditures for the
acquisition, exploration, development and production of oil and natural gas
reserves in the future. As the Trust's revenues may decline as a result of
decreased commodity pricing, it may be required to reduce capital
expenditures. In addition, uncertain levels of near term industry activity
coupled with the present global credit crisis exposes the Trust to additional
access to capital risk. There can be no assurance that debt or equity
financing, or cash generated by operations will be available or sufficient to
meet these requirements or for other corporate purposes or, if debt or equity
financing is available, that it will be on terms acceptable to the Trust. The
inability of the Trust to access sufficient capital for its operations could
have a material adverse effect on the Trust's business financial condition,
results of operations and prospects.

    Third Party Credit Risk

    The Trust may be exposed to third party credit risk through its
contractual arrangements with its current or future joint venture partners,
marketers of its petroleum and natural gas production and other parties. In
the event such entities fail to meet their contractual obligations to the
Trust, such failures may have a material adverse effect on the Trust's
business, financial condition, results of operations and prospects. In
addition, poor credit conditions in the industry and of joint venture partners
may impact a joint venture partner's willingness to participate in the Trust's
ongoing capital program, potentially delaying the program and the results of
such program until the Trust finds a suitable alternative partner.

    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.

    Reserves

    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.

    Asset retirement obligations

    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.

    Unit based compensation

    Units granted under the Trust Incentive Plan to employees and the Board
of Directors is accounted for in accordance with the fair-value based method
of accounting. Accordingly, the stock based compensation expense is measured
at the grant date based on the fair value, using the Black-Scholes model, and
is expensed over the vesting period of the units. Determination of the fair
value of units granted at the grant date requires judgment, including the
expected unit price volatility.

    Fair value of derivatives

    The fair value or mark-to-market value of commodity contracts is based on
the estimated amount that would have been received or paid to settle the
contracts as at December 31, 2008, and may be different from what will
eventually be realized. Changes in the fair value of the commodity contracts
are recognized in the Consolidated Statements of Loss within the financial
statements. The actual gains and losses realized on eventual cash settlement
can vary due to subsequent fluctuations in commodity prices.

    Accounts receivable

    The Trust employs judgment to estimate the carrying value of accounts
receivable. After making assessments of credit risk from customers and joint
venture partners, the Trust may provide for an allowance for doubtful accounts
as required. Actual accounts receivable amounts collected in future periods
may differ from these estimates.

    Income taxes

    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.

    Litigation outcomes

    The Trust is involved in various claims and litigation arising in the
normal course of business. While the outcome of these matters is uncertain and
there can be no assurance that such matters will be resolved in the Trust's
favor, the Trust does not currently believe that the outcome of adverse
decisions in any pending or threatened proceeding related to these and other
matters or any amount which it may be required to pay by reason thereof would
have a material adverse impact on its financial position or results of
operations.
    With the above risks and uncertainties the reader is cautioned that
future events and results may vary substantially from that which True
currently foresees.

    Legal, Environmental Remediation and Other Contingent Matters

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

    Controls and Procedures

    Disclosure Controls and Procedures

    The Trust's Chief Executive Officer and Chief Financial Officer have
designed, or caused to be designed under their supervision, disclosure
controls and procedures to provide reasonable assurance that: (i) material
information relating to the Trust is made known to the Trust's Chief Executive
Officer and Chief Financial Officer by others, particularly during the period
in which the annual and interim filings are being prepared; and (ii)
information required to be disclosed by the Trust in its annual filings,
interim filings or other reports filed or submitted by it under securities
legislation is recorded, processed, summarized and reported within the time
period specified in securities legislation. Such officers have evaluated, or
caused to be evaluated under their supervision, the effectiveness of the
Trust's disclosure controls and procedures at the financial year end of the
Trust and have concluded that the Trust's disclosure controls and procedures
are effective at the financial year end of the Trust for the foregoing
purposes.

    Internal Control over Financial Reporting

    The Trust's Chief Executive Officer and Chief Financial Officer have
designed, or caused to be designed under their supervision, internal control
over financial reporting to provide reasonable assurance regarding the
reliability of the Trust's financial reporting and the preparation of
financial statements for external purposes in accordance with the Canadian
GAAP. Such officers have evaluated, or caused to be evaluated under their
supervision, the effectiveness of the Trust's internal control over financial
reporting at the financial year end of the Trust and concluded that the
Trust's internal control over financial reporting is effective, at the
financial year end of the Trust, for the foregoing purpose.
    The Trust is required to disclose herein any change in the Trust's
internal control over financial reporting that occurred during the period
beginning on October 1, 2008 and ended on December 31, 2008 that has
materially affected, or is reasonably likely to materially affect, the Trust's
internal control over financial reporting. No material changes in the Trust's
internal control over financial reporting were identified during such period,
that has materially affected, or are reasonably likely to materially affect,
the Trust's internal control over financial reporting.
    It should be noted that a control system, including the Trust's
disclosure and internal controls and procedures, no matter how well conceived,
can provide only reasonable, but not absolute, assurance that the objectives
of the control system will be met and it should not be expected that the
disclosure and internal controls and procedures will prevent all errors or
fraud.

    Standardized Distributable Cash

    The Canadian Securities Administrators revised and re-issued in July 2007
National Policy 41-201 "Income Trusts and Other Indirect Offerings", which
includes disclosures regarding distributable cash for Income Trusts. Further,
the Canadian Institute of Chartered Accountants ("CICA") issued the
Interpretive Release "Standardized Distributable Cash in Income Trusts and
Other Flow-Through Entities: Guidance on Preparation and Disclosure" (the
"Release"). In the new guidance, sustainability concepts are discussed and
standardized distributable cash is defined as cash flow from operating
activities less adjustments for productive capacity maintenance, long-term
unfunded contractual obligations and the effect of any foreseeable financing
matters, related to debt covenants, which could impair True's ability to pay
distributions or maintain productive capacity. This Management Discussion and
Analysis is in all material respects in accordance with the recommendations
provided in CICA's Release and NP 41-201.-------------------------------------------------------------------------
                                                     Years ended December 31,
    ($000s, except per unit amounts and ratios)            2008         2007
    -------------------------------------------------------------------------

    Net loss                                            (19,590)     (24,267)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Cash flow from operating activities                  78,784       82,206
    Productive capacity maintenance(1)                  (36,699)     (86,291)
    -------------------------------------------------------------------------
    Standardized distributable cash                      42,085       (4,085)

    Proceeds on sale of property, plant and
     equipment                                           44,340       31,808
    Corporate and property acquisition and other
     capital expenditures                                (6,303)      (2,561)
    Net proceeds from issue of trust units                    -       54,375
    Repurchase of trust units under normal course
     issuer bid                                          (2,536)      (1,658)
    Bank borrowings (debt repayment) and working
     capital changes and other                          (41,252)      (4,428)
    -------------------------------------------------------------------------
    Cash Distributions declared                          36,334       73,451
    Accumulated distributions, beginning of year        215,167      141,716
    -------------------------------------------------------------------------
    Accumulated distributions, end of year              251,501      215,167
    -------------------------------------------------------------------------
    Standardized distributable cash per unit
     - basic                                              $0.53       $(0.05)
    Standardized distributable cash per unit
     - diluted                                            $0.53       $(0.05)
    -------------------------------------------------------------------------
    Standardized distributable cash payout ratio(2)        0.86          N/A
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Distributions declared per unit for outstanding
     units in the period                                   0.46         0.96

    Accumulated distributions per unit, beginning of
     year                                                  4.08         3.12
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Accumulated distributions per unit, end of year        4.54         4.08
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Excess (shortfall) of net income over cash
     distributions declared                             (55,924)     (97,718)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Excess of cash flow from operating activities
     over cash distributions declared                    42,450        8,755
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Please refer to the discussion of productive capacity maintenance
        below
    (2) Represents cash distributions declared divided by standardized
        distributable cashTrue strives to fund both distributions and maintenance capital primarily
from funds flow from operations. True's 2008 capital budget was initially set
at approximately 40% to 60% of annual funds flow. Actual 2008 capital
expenditures represented 55% of 2008 funds flow, which was impacted by
drastically lower prices in the fourth quarter of 2008. Property dispositions,
equity issues or additional borrowings may be required from time to time to
fund a portion of the distributions and/or capital expenditures to maintain or
increase productive capacity may be required based on forecast levels of cash
flow, capital efficiency and debt levels.
    Productive capacity is the amount of capital funds required in a period
for an enterprise to maintain its ability to generate future cash flow from
operating activities at a constant level. As commodity prices can be volatile
and short-term variations in production levels are often experienced in the
oil and gas industry, True defines production capacity as production on a
barrel of oil equivalent basis. A quantifiable measure for these short-term
variations is not objectively determinable or verifiable due to various
factors including the inability to distinguish natural production declines
from the effect of production additions resulting from capital and
optimization programs, and the effect of temporary production interruptions.
As a result, the adjustment for productive capacity maintenance in True's
calculation of standardized distributable cash is True's capital expenditures
excluding the cost of any asset acquisition, corporate asset acquisitions or
proceeds of any asset disposition. True believes that its capital programs
based on 40% to 60% of forecasted funds flow including its current view of
True's assets and opportunities and True's outlook for commodity prices and
industry conditions in the medium term, should be sufficient to maintain
True's productive capacity in the medium term. True sets its hurdle rates for
evaluating potential development and optimization projects according to these
parameters. Due to the risks inherent in the oil and natural gas industry,
particularly True's exploration and development activities and inherent
variations in commodity prices, there can be no assurance that capital
programs, whether limited to excess of cash flow over distributions or not,
will be sufficient to maintain or increase True's production levels or cash
flow from operating activities. True's capital expenditures and production can
be impacted by the timing of the capital program and spring break up
associated with certain operating areas of its properties. As True strives to
maintain sufficient credit facilities and appropriate levels of bank debt,
this seasonality is not expected to influence True's distribution policies.
    True's calculation of standardized distributable cash has no adjustment
for long-term unfunded contractual obligations. True's only material long-term
unfunded contractual obligation at this time is for asset retirement
obligations. True's abandonment obligations are being funded on an annual
basis with cash flow from operating activities. Cash flow from operating
activities, used in our standardized distributable cash calculation, includes
a deduction for abandonment expenditures incurred in the year. True currently
has no financing restrictions on distributions arising from compliance with
its debt covenants. True regularly monitors its current forecast debt levels
to ensure debt covenants are not exceeded.
    Distributions typically exceed net income as a result of non-cash items
such as unit-based compensation, depletion, depreciation and accretion,
unrealized loss (gain) on commodity contracts, and future income tax expense
(recovery). These non-cash items generally result in a reduction to net
income, with no impact to cash flow from operating activities. Therefore,
distributions will exceed net income in most periods. In the event
distributions exceed cash flow from operating activities and the requirements
of True's capital program, the shortfall will typically be funded by a
combination of available bank facilities, equity or debt issues, or the sale
proceeds from non-core assets.
    The Board of Directors and management regularly review the level of
distributions. The board considers a number of factors, including expectations
of future current commodity prices, hedge positions, production volumes,
capital expenditure requirements, market conditions, the availability of debt
and equity capital and other factors. As a result of the volatility in
commodity prices, changes in production levels and capital expenditure
requirements, there can be no certainty that True will be able to maintain
current levels of distributions and distributions can and may fluctuate in the
future.
    Further to the announcement on February 9, 2009, as a result of the
continued deterioration in economic conditions, including the significant
decline in crude oil prices, a weakening outlook for natural gas demand and
heightened risk in the credit markets at the start of 2009, the Trust has
suspended its March 2009 distribution. Distributions are to be reviewed
monthly in the context of commodity prices, among other factors, and are
subject to revision by the Board of Directors.-------------------------------------------------------------------------

    ($000s, except ratios)                              To December 31, 2008
    -------------------------------------------------------------------------
    Cumulative distributable cash from operations(1)                  66,433
    Proceeds on sale of property, plant and equipment                100,662
    Corporate and property acquisitions and other
     capital expenditures                                            (26,186)
    Net proceeds from issue of trust units                            54,375
    Proceeds from issue of convertible debentures,
     net of issue costs                                               82,261
    Repurchase of trust units under normal course
     issuer bid                                                       (4,194)
    Funding from DRIP                                                 42,909
    Bank borrowings (debt repayment) and working
     capital changes and other                                       (64,759)
    -------------------------------------------------------------------------
    Cumulative cash distributions declared(1)                        251,501
    -------------------------------------------------------------------------
    Standardized distributable cash payout ratio(2)                     3.79
    -------------------------------------------------------------------------

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

    The table below shows sensitivities to funds flow as a result of product
price and operational changes. This is based on actual average prices received
for the fourth quarter of 2008 and average production volumes of 10,750 boe/d
during that period, as well as the same level of debt outstanding at December
31, 2008. Diluted weighted average trust units is based upon the fourth
quarter of 2008. These sensitivities are approximations only, and not
necessarily valid under other significantly different production levels or
product mixes. Hedging activities can significantly affect these
sensitivities. Changes in any of these parameters will affect funds flow as
shown in the table below:-------------------------------------------------------------------------
                                                                  Funds Flow
                                                     Funds Flow         from
                                                           from   Operations
                                                     Operations  Per Diluted
                                                    (annualized)        Unit
    -------------------------------------------------------------------------
    Sensitivity Analysis                                 ($000s)          ($)
    -------------------------------------------------------------------------
    Change of US $1/bbl WTI                               1,400         0.02
    Change of $0.10/mcf                                   1,100         0.01
    Change of US $0.01 Cdn/US exchange rate                 550            -
    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
2008.

    -------------------------------------------------------------------------
    2008 - Quarter ended (unaudited)
    ($000s, except
     per unit amounts)             March 31    June 30   Sept. 30    Dec. 31
    -------------------------------------------------------------------------
    Revenues before royalties
     and hedging                     70,033     82,074     72,225     41,053
    Funds flow from operations(1)    24,233     26,304     21,491      5,865
    Funds flow from operations
     per unit(1)
      Basic                           $0.31      $0.33      $0.27      $0.07
      Diluted                         $0.30      $0.33      $0.27      $0.07
    Net loss                        (18,621)   (21,374)    29,939     (9,534)
    Net loss per unit
      Basic                          $(0.24)    $(0.27)     $0.38     $(0.12)
      Diluted                        $(0.24)    $(0.27)     $0.38     $(0.12)
    Net capital expenditures (cash)   2,862    (34,450)    13,779     16,471
    Distributions declared            9,507      9,505      9,474      7,848
    Distributions per unit            $0.12      $0.12      $0.12      $0.10
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    2007 - Quarter ended (unaudited)
    ($000s, except
     per unit amounts)             March 31    June 30   Sept. 30    Dec. 31
    -------------------------------------------------------------------------
    Revenues before royalties
     and hedging                     71,196     74,991     50,547     61,756
    Funds flow from operations(1)    29,988     34,192     17,478     19,514
    Funds flow from operations
     per unit(1)
      Basic                           $0.43      $0.47      $0.22      $0.25
      Diluted                         $0.42      $0.45      $0.22      $0.25
    Net income (loss)                (8,571)     1,741    (17,003)      (434)
    Net income (loss) per unit
      Basic                          $(0.12)     $0.02     $(0.21)    $(0.01)
      Diluted                        $(0.12)     $0.02     $(0.21)    $(0.01)
    Net capital expenditures (cash)  27,915      6,739      7,562     14,828
    Distributions declared           16,866     18,376     19,132     19,077
    Distributions per unit            $0.24      $0.24      $0.24      $0.24
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Refer to "Non-GAAP Measures" in respect of the term "funds flow from
        operations" and "funds flow from operations per unit".The quarterly results for 2008 compared to 2007 were impacted by
dispositions, fluctuating commodity prices, higher operating costs and reduced
capital spending.
    During the first half of 2008, True was successful in completing the
divestiture of its Dodsland-Stranraer property located in Saskatchewan and
other non-core properties in Alberta for net proceeds of $44.3 million; the
net proceeds from the dispositions were used to pay down debt. The
dispositions reduced production volumes by approximately 1,000 boe/d. In the
fourth quarter of 2008, True closed the purchase of further working interests
in the Mantario, Saskatchewan area for $4.3 million in cash after adjustments.
The tuck-in acquisition added approximately 225 bbls/d of heavy oil
production. 2007 production volumes reflected the acquisitions of Shellbridge
and Prairie Schooner completed in 2006, as well as dispositions made
throughout the year, totaling approximately $31.8 million in net proceeds.
    In 2007, True invested $87.3 million in exploration and development of
which approximately 70% was spent by the first half of the year. This compares
to True's expenditures in exploration and development in 2008 of $36.7 million
of which approximately 66% was spent in the second half of the year.
    True's revenues, net loss, and funds flow from operations in 2007 and
2008 reflect its production base after considering the above noted
acquisitions and dispositions, results of exploration and development
expenditures, timing of plant turnarounds and other operational challenges, as
well as fluctuations in commodity prices. In 2007, natural gas prices
increased through to the second quarter; and after declining in the third
quarter, natural gas prices were on the rise again. Crude oil prices in 2007
experienced increases throughout the year. In 2008, natural gas prices
increased in the first and second quarters and experienced a down turn in the
third and fourth quarters of 2008. Crude oil prices in 2008 experienced
significant increases up to the third quarter before decreasing to lows not
experienced since 2004.
    The fluctuation in commodity prices, and production volumes over these
periods resulted in a corresponding increase or decrease in the Trust's
petroleum and natural gas revenue, net income and funds flow from operations
in the respective periods. The net loss for 2007 reflects an increase in DD&A
rates due to acquisitions closed in 2006 in conjunction with increased
production volumes as well as a loss on commodity contracts largely composed
of unrealized losses arising from fair value accounting as commodity prices
increased in the fourth quarter. In 2008, the net loss reflects a decrease in
the DD&A rates due to dispositions closed in 2007 and 2008 in combination with
lower production volumes. The loss on commodity contracts increased in 2008
due to the strong commodity prices experienced in the year.

    Selected Annual Information-------------------------------------------------------------------------
    Years ended December 31,
    ($000s, except per unit amounts)
     (unaudited)                              2008         2007         2006
    -------------------------------------------------------------------------
    Revenues before royalties and
     hedging                               265,385      258,490      220,913
    Funds flow from operations(1)           77,893      101,172       90,391
    Funds flow from operations per unit(1)
      Basic                                  $0.99        $1.33        $1.91
      Diluted                                $0.98        $1.33        $1.87
    Net loss                               (19,590)     (24,267)    (233,564)
    Net loss per unit
      Basic                                 $(0.25)      $(0.32)      $(4.95)
      Diluted                               $(0.25)      $(0.32)      $(4.95)
    Net capital expenditures (cash)         (1,338)      57,094       91,498
    Total assets                           736,117      880,252    1,016,658
    Total net debt(2)                      215,004      250,313      275,816
    Long-term financial liabilities
      Future income taxes                   42,777       67,366      123,861
      Asset retirement obligations          33,682       28,373       26,605
      Exchangeable shares of subsidiary      2,887        3,922        4,153
    Production (boe/d)                      11,867       16,139       13,861
    Distributions declared                  36,334       73,451      124,355
    Distributions per unit(3)                $0.46        $0.96        $2.64
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Refer to "Non-GAAP Measures" in respect of the term "funds flow from
        operations" and "funds flow from operations per unit".
    (2) Net debt includes the net working capital deficiency before
        short-term commodity contract assets and liabilities and short-term
        future income tax assets and liabilities. Total net debt also
        includes the liability component of convertible debentures and
        excludes asset retirement obligations and the future income tax
        liability.
    (3) Restated for changes in accounting policies and to reflect the
        consolidation of units effective November 2, 2005.



    TRUE ENERGY TRUST
    CONSOLIDATED BALANCE SHEETS
    As at December 31 (unaudited)
    -------------------------------------------------------------------------
    ($000s)                                                2008         2007
    -------------------------------------------------------------------------

    ASSETS
    Current assets
      Accounts receivable                             $  27,845    $  48,522
      Marketable securities (note 4)                        120          850
      Deposits and prepaid expenses                       5,969        6,096
      Capital taxes recoverable                             274          626
      Commodity contract asset (note 18)                  3,726        1,061
      Future income taxes (note 13)                           -        3,116
                                                      -----------------------
                                                         37,934       60,271
    Property, plant and equipment (note 5)              698,183      819,981
                                                      -----------------------
    Total assets                                      $ 736,117    $ 880,252
                                                      -----------------------
                                                      -----------------------

    LIABILITIES
    Current liabilities
      Accounts payable and accrued liabilities        $  34,128    $  52,188
      Distribution payable to unitholders                 1,570        6,337
      Commodity contract liability  (note 18)                 -       11,404
      Future income taxes (note 13)                       1,100            -
                                                      -----------------------
                                                         36,798       69,929
    Long-term debt (note 6)                             132,388      168,475
    Convertible debentures (note 7)                      81,124       79,407
    Asset retirement obligations (note 8)                33,682       28,373
    Future income taxes (note 13)                        42,777       67,366
                                                      -----------------------
    Total liabilities                                   326,769      413,550
                                                      -----------------------

    NON-CONTROLLING INTEREST
      Exchangeable shares of subsidiary (note 9)          2,887        3,922

    UNITHOLDERS' EQUITY
      Unitholders' capital (note 10)                    917,012      925,573
      Equity component of convertible debentures          5,119        5,119
      Contributed surplus (note 11)                      28,240       19,454

      Accumulated other comprehensive income               (620)           -
      Deficit                                          (543,290)    (487,366)
                                                      -----------------------
                                                       (543,910)    (487,366)
                                                      -----------------------

                                                      -----------------------
    Total unitholders' equity                           406,461      462,780
                                                      -----------------------
     Total liabilities and unitholders' equity        $ 736,117    $ 880,252
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    COMMITMENTS (note 17)

    See accompanying notes to the consolidated financial statements.



    TRUE ENERGY TRUST
    CONSOLIDATED STATEMENTS OF LOSS  AND COMPREHENSIVE LOSS
    For the years ended December 31 (unaudited)

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

    REVENUES
      Petroleum and natural gas sales                 $ 265,385    $ 258,490
      Royalties                                         (54,562)     (47,004)
      Loss on commodity contracts (note 18)             (14,154)      (3,852)
                                                      -----------------------
                                                        196,669      207,634

    EXPENSES
      Production                                         66,573       68,282
      Transportation                                      7,047        7,938
      General and administrative                         15,958       18,186
      Interest and financing charges                     14,822       18,108
      Unit-based compensation (notes 10 and 11)           1,395        2,001
      Depletion, depreciation and accretion             128,932      171,484
      Special meeting costs (note 14)                         -        3,805
                                                      -----------------------
                                                        234,727      289,804

    LOSS BEFORE TAXES                                   (38,058)     (82,170)

    TAXES
      Capital taxes                                       2,025        2,039
      Future income tax recovery (note 13)              (20,410)     (59,847)
                                                      -----------------------
                                                        (18,385)     (57,808)

    NET LOSS BEFORE NON-CONTROLLING INTEREST            (19,673)     (24,362)

      Non-controlling interest                              (83)         (95)
                                                      -----------------------
                                                      -----------------------

    NET LOSS                                            (19,590)     (24,267)
                                                      -----------------------

    Net changes in cash flow hedges
    (net of tax of $1.8 million) (note 18)                    -       (3,749)
    Unrealized loss on available for sale marketable
     securities (net of tax recovery of $0.1 million)
     (note 4)                                              (620)           -
                                                      -----------------------
                                                           (620)      (3,749)

    COMPREHENSIVE LOSS                                $ (20,210)   $ (28,016)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Net loss per trust unit
      Basic                                              $(0.25)      $(0.32)
      Diluted                                            $(0.25)      $(0.32)
    -------------------------------------------------------------------------

    See accompanying notes to the consolidated financial statements.



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

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

    UNITHOLDERS' CAPITAL
      Balance, beginning of year                      $ 925,573    $ 876,904
      Issued for cash (net of issue costs of
       $3.1 million)                                          -       54,375
      Repurchased under normal course issuer bid         (9,513)      (5,842)
      Exchangeable shares converted                         952          136
                                                      -----------------------
      Balance, end of year                              917,012      925,573
                                                      -----------------------

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

    CONTRIBUTED SURPLUS
      Balance, beginning of year                         19,454       12,818
      Unit-based compensation expense (note 10 and 11)    1,869        4,249
      Incentive units voluntarily surrendered               466            -
      Reversal of prior period unit-based compensation
       expense for forfeitures of unvested
       incentive units                                     (526)      (1,797)
      Adjustment for repurchase of units under
       normal course issuer bid                           6,977        4,184
                                                      -----------------------
      Balance, end of year                               28,240       19,454
                                                      -----------------------

    DEFICIT
      Balance, beginning of year                       (487,366)    (389,745)
      Net loss                                          (19,590)     (24,267)
      Impact of changes in accounting policy for
       financial instruments (net of tax of
       $0.05 million) (note 7)                                -           97
      Distributions declared                            (36,334)     (73,451)
                                                      -----------------------
      Balance, end of year                             (543,290)    (487,366)
                                                      -----------------------

    ACCUMULATED OTHER COMPREHENSIVE INCOME
      Balance, beginning of year                              -            -
      Impact of new cash flow hedge accounting
       standards (net of tax of $1.8 million)
       (note 18)                                              -        3,749
      Reclassification to earnings of net hedging
       gains on commodity contracts
       (net of tax of $1.8 million)(note 18)                  -       (3,749)
      Unrealized loss on available for sale
       marketable securities (net of tax recovery
       of $0.1 million)(note 4)                            (620)           -
                                                      -----------------------
      Balance, end of year                                 (620)           -
                                                      -----------------------

    -------------------------------------------------------------------------
    TOTAL UNITHOLDERS' EQUITY                         $ 406,461    $ 462,780
    -------------------------------------------------------------------------

    See accompanying notes to the consolidated financial statements.



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

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

    Cash provided by (used in):
    CASH FLOW FROM OPERATING ACTIVITIES
    Net loss                                          $ (19,590)   $ (24,267)
    Items not involving cash:
      Non-controlling interest (note 9)                     (83)         (95)
      Depletion, depreciation and accretion             128,932      171,484
      Unit-based compensation (notes 10 and 11)           1,395        2,001
      Unrealized loss (gain) on commodity
       contracts (note 18)                              (14,068)      10,343
      Accretion on convertible debentures                 1,717        1,553
      Future income tax recovery (note 13)              (20,410)     (59,847)
                                                       ----------------------
                                                         77,893      101,172

      Asset retirement costs incurred (note 8)           (2,603)        (835)
      Change in non-cash working capital (note 12)        3,494      (18,131)
                                                       ----------------------
                                                         78,784       82,206

    CASH FLOW FROM (USED IN) FINANCING ACTIVITIES
      Increase (decrease) in bank debt                  (36,087)      11,591
      Obligations under capital lease                         -         (111)
      Issue of trust units for cash                           -       57,523
      Unit issue costs                                        -       (3,148)
      Repurchase of trust units under normal course
       issuer bid                                        (2,536)      (1,658)
      Distributions declared                            (36,334)     (73,451)
                                                       ----------------------
                                                        (74,957)      (9,254)
      Change in non-cash working capital (note 12)       (4,873)      (2,060)
                                                       ----------------------
                                                        (79,830)     (11,314)

    CASH FLOW FROM (USED IN) INVESTING ACTIVITIES
      Additions to property, plant and equipment        (43,002)     (88,852)
      Proceeds on sale of property,
       plant and equipment                               44,340       31,808
      Purchase of marketable securities (note 4)              -          (50)
                                                       ----------------------
                                                          1,338      (57,094)
      Change in non-cash working capital (note 12)         (292)     (13,798)
                                                       ----------------------
                                                          1,046      (70,892)

      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
    (unaudited)
    -------------------------------------------------------------------------

    1.  STRUCTURE OF THE TRUST

        True Energy Trust ("True" or the "Trust") is an open-ended,
        unincorporated investment trust governed by the laws of the Province
        of Alberta.

        The purpose of the Trust is to indirectly explore for, develop and
        hold interests in petroleum and natural gas properties, through
        investments in securities of subsidiaries and net profits interests
        in oil and natural gas properties. The business of the Trust is
        carried on by True Energy Inc. and its indirect wholly owned
        subsidiary True Energy Peru S.A.C. The Trust owns, directly and
        indirectly, 100% of the common shares, (excluding the exchangeable
        shares - see note 9) of True Energy Inc. and True Energy Peru S.A.C.
        The activities of True Energy Inc. are financed through interest
        bearing notes from the Trust and third party debt as described in the
        notes to the financial statements.

        Pursuant to the terms of Net Profit Interest Agreements (the "NPI
        Agreements"), the Trust is entitled to a payment from True Energy
        Inc. each month equal to the amount by which 99% of the gross
        proceeds from the sale of production exceed certain deductible
        expenditures (as defined). Under the terms of the NPI 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. as applicable.

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

    2.  SIGNIFICANT ACCOUNTING POLICIES

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

        a. Principles of Consolidation

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

        b. Revenue Recognition

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

        c. Joint Interests

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

        d. Petroleum and Natural Gas Properties

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

        e. Depletion and Depreciation

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

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

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

        f. Ceiling Test

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

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

        g. 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.

        h. Environmental Liabilities

           The Trust records liabilities on an undiscounted basis for
           environmental remediation efforts that are likely to occur and
           where the cost can be reasonably estimated. The estimates,
           including associated legal costs, are based on available
           information using existing technology and enacted laws and
           regulations. The estimates are subject to revision in future
           periods based on actual costs incurred or new circumstances. Any
           amounts expected to be recovered from other parties, including
           insurers, are recorded as an asset separate from the associated
           liability.

        i. Unit-based Compensation Plan

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

        j. Income Taxes

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

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

        k. Exchangeable Shares of Subsidiary

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

        l. Financial Instruments

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

           ------------------------------------------------------------------
           Financial Assets and Liabilities            Category
           ------------------------------------------------------------------
           Accounts receivable                         Loans and receivables
           ------------------------------------------------------------------
           Marketable securities                       Available-for-sale
           ------------------------------------------------------------------
           Risk management contracts                   Held-for-trading
           ------------------------------------------------------------------
           Accounts payable and accrued liabilities    Other liabilities
           ------------------------------------------------------------------
           Distribution payable                        Other liabilities
           ------------------------------------------------------------------
           Long-term debt                              Other liabilities
           ------------------------------------------------------------------
           Convertible debentures                      Other liabilities
           ------------------------------------------------------------------

           Transaction costs attributable to financial instruments classified
           as other than held-for-trading are included in the recognized
           amount of the related financial instrument and recognized over the
           life of the resulting financial instrument.

           The Trust utilizes financial derivatives and non-financial
           derivatives, such as commodity sales contracts requiring physical
           delivery, to manage the price risk attributable to anticipated
           sale of petroleum and natural gas production and foreign exchange
           exposures. 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 has elected to account for its commodity sales and
           purchase contracts, which were entered into and continue to be
           held for the purpose of receipt or delivery of non-financial items
           in accordance with its expected purchase, sale or usage
           requirements as executory contracts on an accrual basis rather
           than as derivatives. As such, physical sales and purchase
           contracts are not recorded at fair value on the balance sheet with
           changes in fair value included in earnings.

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

        m. Capital Disclosures

           The Trust considers its capital structure to include unitholders'
           equity, bank debt, convertible debentures and working capital.
           Handbook Section 1535, "Capital Disclosures" specify the
           disclosure of (i) an entity's objectives, policies and processes
           for managing capital; (ii) quantitative data about what the entity
           regards as capital; (iii) whether the entity has complied with any
           capital requirements; and (iv) if it has not complied, the
           consequences of such non-compliance.

        n. 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.

        o. Measurement Uncertainty

           The amounts recorded for depletion, depreciation and accretion
           expense, asset retirement obligations and amounts used in the
           impairment test for 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.

        p. Financial Presentation and Disclosure

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

    3.  CHANGES IN ACCOUNTING POLICIES AND RECENT ACCOUNTING PRONOUNCEMENTS

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

        a. Capital disclosures

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

        b. Financial instruments

           Two new accounting standards were issued by the CICA, Section 3862
           "Financial Instruments - Disclosures", and Section 3863 "Financial
           Instruments - Presentation". These sections replace Section 3861
           "Financial Instruments - Disclosure and Presentation" and are
           effective for the Trust beginning January 1, 2008. The objective
           of Section 3862 is to provide users with information to evaluate
           the significance of the financial instruments on the entity's
           financial position and performance, the nature and extent of risks
           arising from financial instruments, and how the entity manages
           those risks. The provisions of Section 3863 deal with the
           classification of financial instruments, related interest,
           dividends, losses and gains, and the circumstances in which
           financial assets and financial liabilities are offset. The
           additional disclosures required under these sections are included
           in note 18.

        Goodwill and intangible assets

        In February 2008, the CICA issued a new accounting standard, Section
        3064 - "Goodwill and Intangible Assets", which replaces Section 3062
        - "Goodwill and Other Intangible Assets", and Section 3450 -
        "Research and Development costs". The new section establishes
        standards for the recognition, measurement and disclosure of goodwill
        and intangible assets. The section is effective for the Trust
        beginning January 1, 2009. Application of the new section is not
        currently expected to have any impact on the Trust's financial
        statements.

        International Financial Reporting Standards ("IFRS")

        On February 13, 2008 the CICA Accounting Standards Board announced
        that Canadian public reporting issuers will be required to report
        under International Financial Reporting Standards ("IFRS"), which
        will replace Canadian generally accepted accounting principles for
        years beginning on or after January 1, 2011. Currently, we are
        assessing the effects of adoption and developing a plan accordingly.
        We will continue to monitor any changes in the adoption of IFRS and
        will update plans as necessary.

    4.  MARKETABLE SECURITIES

        The Trust's investment in Veraz Petroleum Ltd. is classified as
        available-for-sale and has been recorded at fair value. Changes in
        the fair value of the marketable securities are recorded net of the
        income tax effect to other comprehensive income.

    5.  PROPERTY, PLANT AND EQUIPMENT

        ($000s)
        ---------------------------------------------------------------------
                                                   Accumulated
                                                     depletion
                                                           and      Net book
        December 31, 2008                   Cost  depreciation         value
        ---------------------------------------------------------------------
        Petroleum and natural gas
         properties                  $ 1,375,331   $   679,196   $   696,135
        Office furniture and
         equipment                         3,955         1,907         2,048
        ---------------------------------------------------------------------
                                     $ 1,379,286   $   681,103   $   698,183
        ---------------------------------------------------------------------

        December 31, 2007
        ---------------------------------------------------------------------
        Petroleum and natural gas
         properties                  $ 1,370,219   $   552,899   $   817,320
        Office furniture and
         equipment                         4,092         1,431         2,661
        ---------------------------------------------------------------------
                                     $ 1,374,311   $   554,330   $   819,981
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The Trust has included $62.8 million (2007: $56.6 million) for future
        development costs and excluded $31.3 million (2007: $37.8 million)
        for undeveloped land and $42.5 million (2007: $47.6 million) for
        estimated salvage from the depletion calculation during the year
        ended December 31, 2008.

        For the year ended December 31, 2008, the Trust capitalized
        $2.4 million of general and administrative expenses and $0.6 million,
        including the future tax effect thereon of $0.1 million, of
        unit-based compensation expense directly related to exploration and
        development activities.

        The Trust performed a ceiling test calculation at December 31, 2008
        resulting in undiscounted cash flows from proved reserves and the
        undeveloped properties not exceeding the carrying value of oil and
        gas assets. Consequently, True performed stage two of the ceiling
        test assessing whether discounted future cash flows from the
        production of proved plus probable reserves plus the carrying cost of
        undeveloped properties, net of any impairment allowance, exceeds the
        carrying value of its petroleum and natural gas properties. No
        impairment in oil and gas assets was identified as at December 31,
        2008 and 2007.

        The prices used in the ceiling test evaluation of the Trust's crude
        oil and natural gas reserves at December 31, 2008 were based on the
        following benchmark price forecasts adjusted for quality and
        transportation differentials:

        ---------------------------------------------------------------------
                                        Hardisty      Edmonton
                                           Heavy   Light Sweet  AECO Natural
        Year                           Crude Oil     Crude Oil           Gas
                                          ($/bbl)       ($/bbl)     ($/mmbtu)
        ---------------------------------------------------------------------
        2009                               45.72         67.85          7.05
        2010                               53.48         78.24          7.46
        2011                               58.70         84.96          7.67
        2012                               63.59         90.46          7.92
        2013                               67.41         95.73          8.16
        2014                               68.80         97.68          8.18
        2015                               70.34         99.66          8.19
        2016                               71.77        101.66          8.18
        2017                               73.23        103.66          8.20
        2018                               74.70        105.78          8.22
        2019                               76.21        107.90          8.23
        Percentage increase each year
         after 2019                           2%            2%           nil
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    6.  LONG-TERM DEBT

        ---------------------------------------------------------------------
        ($000s)                                           2008          2007
        ---------------------------------------------------------------------
        Operating facility                           $   7,388     $  10,475
        Revolving term facility                        125,000       158,000
        ---------------------------------------------------------------------
        Balance, end of year                         $ 132,388     $ 168,475
        ---------------------------------------------------------------------

        The credit facility was renewed on June 27, 2008 and consists of a
        $15 million demand operating facility provided by one Canadian bank
        and $137 million extendible revolving term credit facility syndicated
        by two Canadian chartered banks, a Canadian financial institution,
        one institutional lender and a U.S. bank. 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 0.10% and 2.05%, 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 0.150% and 0.400%
        on the undrawn portion of the facility, depending on the Trust's debt
        to cash flow ratio.

        As at December 31, 2008, approximately $19.6 million was not drawn
        under the existing facilities.

        The revolving period on the revolving term credit facility ends on
        June 26, 2009, unless extended for a further 364 day period. Should
        the facilities not be renewed they convert to 366 day non-revolving
        term facilities on the renewal date. The borrowing base was renewed
        effective September 30, 2008 and is currently scheduled for review on
        March 31, 2009. The borrowing base will be subject to the lending
        syndicate's determination which is based upon the latest reserves
        information, their internal commodity price decks and other factors.
        In the event the borrowing base is lowered below the drawn credit
        facility at that time, any shortfall would be required to be repaid
        within 60 days of notification, or as otherwise agreed by the lending
        syndicate, and this funding would currently be expected to come from
        alternative sources of debt or equity financing or the proceeds from
        asset dispositions as available.

        Payment will not be required under the revolving term facility for
        more than 365 days from the balance sheet date as at December 31,
        2008 as 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.
        $12.5 million of the syndicated facility is with a US bank which may
        be required to be repaid or reallocated to one or more of the other
        four current members of the syndicate or a new member on June 28,
        2009, if not renewed by the US bank.

    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. The debentures are convertible at
        anytime at the option of the holders into trust units of the Trust at
        a conversion price of $16.00 per Trust unit. The Trust will have the
        right to redeem all or a portion of the debentures at a price of
        $1,050 per debenture after June 30, 2009 and on or before June 30,
        2010 and at a price of $1,025 per debenture after June 30, 2010 and
        before the maturity date. Upon maturity or redemption of the
        debentures, the Trust may, subject to notice and regulatory approval,
        pay the outstanding principal and premium (if any) on the debentures
        in cash or through the issue of additional Trust units at 95% of a
        weighted average trading price of the Trust units.

        The debentures were initially recorded at the fair value of the
        obligation without the conversion feature. This fair value to make
        future payments of principal and interest was initially determined to
        be $81.1 million. The difference between the principal amount of
        $86.3 million and the fair value of the obligation is $5.1 million
        and has been recorded in unitholders' equity as the fair value of the
        conversion feature of the debentures. Issue costs of $4.0 million
        were classified as deferred financing charges, and prior to
        January 1, 2007, were amortized on a straight-line basis over the
        term of the debentures. As a consequence of adopting new financial
        instruments standards effective January 1, 2007, the balance of
        deferred financing charges or transaction costs were recorded against
        the debt component of convertible debentures and restated as if the
        effective interest rate method had always been applied over the life
        of the debentures with a resulting $0.1 million adjustment (net of
        tax of $0.05 million) against the deficit. The adjustment to
        debentures is noted in the table below. The debt component of the
        convertible debentures will accrete up to the principal balance at
        maturity. The accretion and the interest paid are expensed as
        interest and financing charges in the consolidated statement of
        operations.

        The following table shows the convertible debenture activities for
        the years ended December 31, 2008 and 2007:

        Convertible debentures
        ---------------------------------------------------------------------
                                                          Debt        Equity
                                       Number of     Component     Component
                                      Debentures        ($000s)       ($000s)
        ---------------------------------------------------------------------
        Balance, December 31, 2006        86,250     $  81,551     $   5,119
        Impact of change in accounting
         policy for financial
         instruments on January 1, 2007        -        (3,697)            -
        Accretion                              -         1,553             -
        ---------------------------------------------------------------------
        Balance, December 31, 2007        86,250     $  79,407     $   5,119
        Accretion                              -         1,717             -
        ---------------------------------------------------------------------
        Balance, December 31, 2008        86,250     $  81,124     $   5,119
        ---------------------------------------------------------------------

        In November 2008, the Trust received Toronto Stock Exchange approval
        for its normal course issuer bid program ("NCIB") to repurchase up to
        10% of the issued and outstanding 7.50% convertible unsecured
        subordinated debentures of the Trust from December 1, 2008 to
        November 30, 2009. As of December 31, 2008 there were no repurchases
        of convertible debentures under the NCIB.

    8.  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 $77.6 million which will be
        incurred between 2009 and 2053. A credit-adjusted risk-free rate of
        8 percent and an inflation rate of 2.4 percent were used to calculate
        the fair value of the asset retirement obligation.

        ---------------------------------------------------------------------
        ($000s)                                           2008          2007
        ---------------------------------------------------------------------
        Balance, beginning of year                   $  28,373     $  26,605
        Liabilities incurred on development
         activities                                        784           433
        Changes in prior period estimates                8,302           960
        Liabilities released on dispositions            (3,333)         (927)
        Liabilities settled during the year             (2,603)         (835)
        Accretion expense                                2,159         2,137
        ---------------------------------------------------------------------
        Balance, end of year                         $  33,682     $  28,373
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    9.  EXCHANGEABLE SHARES OF SUBSIDIARY/NON-CONTROLLING INTEREST

        Authorized:

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

        ---------------------------------------------------------------------
                                  December 31, 2008       December 31, 2007
                                  Number     Amount       Number     Amount
                                             ($000s)                 ($000s)
        ---------------------------------------------------------------------
        Balance, beginning
         of year                 390,276   $   3,922     403,536   $   4,153
        Non-controlling
         interest recovery             -         (83)          -         (95)
        Exchanged for trust
         units                   (96,250)       (952)    (13,260)       (136)
        ---------------------------------------------------------------------
        Balance, end of year     294,026   $   2,887     390,276   $   3,922
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

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

        As at December 31, 2008, the exchange ratio was 1.0218 (2007 -
        0.8604)

        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.

    10. UNITHOLDERS' CAPITAL

        a. Trust Units

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

           ------------------------------------------------------------------
                                         2008                    2007
                                  Number     Amount       Number     Amount
                                             ($000s)                 ($000s)
           ------------------------------------------------------------------
           Balance, beginning
            of year           79,216,046  $  925,573  70,275,703   $ 876,904
           Issued for cash
            (net of issue costs
            of $3.1 million)           -           -   9,430,000      54,375
           Repurchased under
            normal course
            issuer bid          (814,300)     (9,513)   (500,000)     (5,842)
           Exchangeable shares
            converted             94,835         952      10,343         136
           ------------------------------------------------------------------
           Balance, end
            of year           78,496,581   $ 917,012  79,216,046   $ 925,573
           ------------------------------------------------------------------

           In August 2008, the Trust announced approval of the renewal of its
           normal course issuer bid ("NCIB") program to repurchase up to
           7.8 million of its outstanding trust units during the period
           August 28, 2008 through August 27, 2009, subject to certain
           restrictions. As of December 31, 2008, the Trust has purchased
           615,100 trust units at a weighted average price of $2.74 per trust
           unit under the NCIB renewed on August 28, 2008.

        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, provided, however, that such decrease in the exercise
           price will not exceed the amount of Trust unit distributions. In
           no case may the exercise price be less than $0.001 per Trust Unit
           and a participant may elect to have the exercise price equal the
           Grant Price. Incentive Rights are non-transferable or assignable
           except in accordance with the Incentive Plan and the holding of
           Incentive Rights shall not entitle a holder to any rights as a
           Unitholder of True Energy Trust. Incentive rights, entitling the
           holder to purchase units from the Trust, have been granted to
           directors, officers, employees and service providers of the Trust.
           One third of the initial grant of trust unit incentive rights
           normally vest on each of the first, second, and third anniversary
           from the date of grant.

           The following tables summarize information regarding trust unit
           incentive rights for the years ended December 31, 2008 and 2007:

           Unit Rights Continuity
           ------------------------------------------------------------------
                                              Weighted Average
                                              Exercise Price(a)       Number
           ------------------------------------------------------------------
           Balance, December 31, 2006                  $ 14.18     5,429,831
           Granted                                     $  5.06     3,181,500
           Forfeited and cancelled                     $ 12.50    (2,679,334)
           ------------------------------------------------------------------
           Balance, December 31, 2007                  $  9.18     5,931,997
           Granted                                     $  2.89       578,500
           Forfeited and cancelled(b)                  $ 11.35    (3,809,997)
           ------------------------------------------------------------------
           Balance, December 31, 2008                  $  3.97     2,700,500
           ------------------------------------------------------------------
           (a) Exercise prices reflect grant prices less reduction in
               exercise prices.
           (b) Total forfeited and cancelled in the year ended December 31,
               2008 includes 2,191,250 incentive units which were voluntarily
               surrendered by existing employees, directors, and consultants
               of the Trust and were cancelled in July 2008.


    Unit Rights Outstanding, December 31, 2008
    -------------------------------------------------------------------------
                                           Outstanding
                                                       Weighted
                                                        Average
                                                       Exercise     Weighted
                                                          Price      Average
    Exercise            Exercise Price          At       Net of    Remaining
    Price Before                Net of     Dec. 31,       Price  Contractual
    Price Reductions        Reductions        2008   Reductions         Life
    -------------------------------------------------------------------------
    $ 1.68 - $ 2.92    $ 1.66 - $ 2.49   1,018,000      $  2.30          4.2
    $ 3.02 - $ 4.55    $ 2.60 - $ 4.31     279,500      $  3.54          4.5
    $ 4.98 - $ 6.70    $ 4.25 - $ 5.59   1,378,000      $  5.06          3.4
    $20.40 - $20.40    $16.97 - $16.97      25,000      $ 16.97          1.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    $ 1.68 - $20.40    $ 1.66 - $16.97   2,700,500      $  3.97          3.8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


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

                                      Exercise
    Exercise                  At     Price Net
    Price Before         Dec. 31,     of Price
    Price Reductions        2008    Reductions
    -------------------------------------------
    $ 1.68 - $ 2.92      252,981       $  2.49
    $ 3.02 - $ 4.55            -             -
    $ 4.98 - $ 6.70      459,316       $  5.06
    $20.40 - $20.40       25,000       $ 16.97
    -------------------------------------------
    -------------------------------------------
    $ 1.68 - $20.40      737,297       $  3.73
    -------------------------------------------
    -------------------------------------------


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


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

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

        c. Employee Trust Unit Savings Plan

           Effective October 1, 2006, the Trust introduced an employee trust
           unit savings plan for the benefit of all employees. Under the
           savings plan, employees may elect to contribute up to 10 percent
           of their salary and contributions are used to fund the acquisition
           of trust units. The Trust matches employee contributions at a rate
           of $1.00 for each $1.00 contributed. Trust units are purchased in
           the open market by the plan administrator, an investment firm, on
           behalf of the participants in the plan. For the year ended
           December 31, 2008, the Trust matched $0.5 million (2007 -
           $0.5 million) under the plan. Effective for March 2009, the Trust
           has suspended matching contributions under the plan until further
           notice.

    11. CONTRIBUTED SURPLUS

        ---------------------------------------------------------------------
        ($000s)                                           2008          2007
        ---------------------------------------------------------------------
        Balance, beginning of year                   $  19,454     $  12,818
        Unit-based compensation expense                  1,869         4,249
        Incentive units voluntarily surrendered            466             -
        Reversal of prior period unit-based
         compensation expense for forfeitures of
         unvested incentive units                         (526)       (1,797)
        Adjustment for repurchase of units
         under NCIB                                      6,977         4,184
        ---------------------------------------------------------------------
        Balance, end of year                         $  28,240     $  19,454
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Unit-based Compensation Expense

        During the year ended December 31, 2008, the Trust granted 578,500
        (2007: 3,181,500) unit incentive rights to employees. During the year
        ended December 31, 2008, the Trust recorded unit-based compensation
        of $1.8 million, of which $0.4 million was capitalized to property,
        plant and equipment.

        The fair values of all incentive rights granted are estimated on the
        date of grant using the Black-Scholes option-pricing model. The
        weighted average fair market value of incentive rights granted during
        the years ended December 31, 2008 and 2007 and the assumptions used
        in their determination are as noted below:

        ---------------------------------------------------------------------
                                                          2008          2007
        ---------------------------------------------------------------------
        Assumptions:
          Risk free interest rate (%)                        3             4
          Expected life (years)                              5             5
          Expected volatility (%)                        26-57         24-26
        ---------------------------------------------------------------------
        Results:
          Weighted average fair value of each
           incentive right granted                      $ 1.10        $ 1.85
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    12. SUPPLEMENTAL CASH FLOW INFORMATION

        Cash Interest and Taxes Paid
        ---------------------------------------------------------------------
        ($000s)                                           2008          2007
        ---------------------------------------------------------------------

        Cash paid:
          Interest                                   $  14,041     $  16,566
          Taxes (net of refunds)                     $   1,409     $   4,378
        ---------------------------------------------------------------------

        Change in Non-cash Working Capital
        ---------------------------------------------------------------------
        ($000s)                                           2008          2007
        ---------------------------------------------------------------------
        Changes in non-cash working capital items:
          Accounts receivable                        $  20,677     $  24,677
          Deposits and prepaid expenses                    127           812
          Accounts payable and accrued liabilities     (18,060)      (55,243)
          Capital taxes recoverable                        352        (2,139)
          Distribution payable to unitholders           (4,767)       (2,096)
        ---------------------------------------------------------------------
                                                     $  (1,671)    $ (33,989)
        ---------------------------------------------------------------------
        Changes related to:
          Operating activities                       $   3,494     $ (18,131)
          Financing activities                          (4,873)       (2,060)
          Investing activities                            (292)      (13,798)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
                                                     $  (1,671)    $ (33,989)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    13. INCOME TAXES

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

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

        In accordance with generally accepted accounting principles, prior to
        the enactment, the Trust did not record taxes on its temporary
        differences. As at December 31, 2008, the total "temporary
        difference" (tax basis exceeds accounting basis) in the Trust is
        $9.8 million. As at December 31, 2008, the Trust's subsidiaries have
        a tax basis of approximately $476 million that is available to
        shelter future taxable income. Included in this tax basis are
        estimated non-capital loss carry forwards of approximately
        $39.7 million that expire in years through 2027. In addition, the
        Trust itself has approximately $18.6 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 30.10% (2007: 32.98%) to earnings before taxes.
        This difference results from the following items.

        ---------------------------------------------------------------------
        Years ended December 31 ($000s)                   2008          2007
        ---------------------------------------------------------------------
        Expected income tax expense (recovery)       $ (11,456)    $ (27,099)
        Distributions deducted for tax purposes        (11,276)      (22,857)
        Impact of SIFT legislation                           -        (1,165)
        Unit based compensation expense                    420           660
        Change in enacted tax rates                      3,133        (9,444)
        Other                                           (1,231)           58
        ---------------------------------------------------------------------
        Future income tax recovery                   $ (20,410)    $ (59,847)
        ---------------------------------------------------------------------

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

        ---------------------------------------------------------------------
        ($000s)                                           2008          2007
        ---------------------------------------------------------------------
        Future income tax liabilities:
          Petroleum and natural gas properties       $ (64,478)    $ (87,564)
          Commodity contract asset                      (1,100)            -
          Other                                           (565)         (565)
        Future income tax assets:
          Future site restoration/asset retirement
           obligation                                    9,053         7,682
          Share issue costs                                656         1,345
          Non-capital losses                            11,331        10,502
          Attributed Canadian Royalty Income             1,209         1,209
          Commodity contract liability                       -         3,116
          Other                                             17            25
        ---------------------------------------------------------------------
        Net future income tax liability              $ (43,877)    $ (64,250)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    14. SPECIAL MEETING COSTS

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

    15. PER TRUST UNIT AMOUNTS

        ---------------------------------------------------------------------
                                                          2008          2007
        ---------------------------------------------------------------------
        Basic trust units outstanding,
         as at December 31                          78,496,581    79,216,046
        Dilutive effect of:
          Trust unit incentive rights outstanding    2,700,500     5,931,997
          Units issuable for exchangeable shares       300,433       335,793
          Units issuable for convertible
           debentures                                5,390,625     5,390,625
        ---------------------------------------------------------------------
        Diluted trust units outstanding             86,888,139    90,874,461
        ---------------------------------------------------------------------
        Weighted average trust units outstanding    78,985,481    75,792,488
        Dilutive effect of exchangeable shares,
         trust unit incentive plan and
         convertible debentures(1)                           -             -
        ---------------------------------------------------------------------
        Diluted weighted average trust units
         outstanding                                78,985,481    75,792,488
        ---------------------------------------------------------------------

        (1) A total of 2,700,500 (2007: 5,931,997) trust incentive units,
            300,433 (2007: 335,793) exchangeable shares and 5,390,625 (2007:
            5,390,625) trust units issuable pursuant to the conversion of
            convertible debentures were excluded from the calculation for the
            year ended December 31, 2008 as they were not dilutive.


    16. RELATED PARTY TRANSACTIONS

        During the year ended December 31, 2008, the Trust recorded fees of
        $0.6 million (2007: $1.2 million) for legal services provided by a
        firm in which a current director and corporate secretary is a
        partner. The services provided were made in the normal course of
        operations, on commercial terms, and therefore were recorded at the
        exchange amount. As at December 31, 2008, an amount due to this firm
        of $0.1 million was included in accounts payable (2007:
        $0.2 million).

    17. COMMITMENTS

        The Trust has committed to various corporate sponsorships extending
        to June 2011 at an estimated combined cost of up to $228,000.

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

        ---------------------------------------------------------------------
        ($000s)                            Gross      Expected
        Year                              Amount    Recoveries    Net amount
        ---------------------------------------------------------------------
        2009                               1,824         1,034           790
        2010                               2,146           883         1,263
        2011                               2,207           897         1,310
        2012                               2,218           737         1,481
        2013                               2,218           737         1,481
        ---------------------------------------------------------------------

    18. FINANCIAL RISK MANAGEMENT

        a.  Overview

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

           -  Credit risk
           -  Liquidity risk
           -  Market risk

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

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

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

        b.  Credit risk

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

        A substantial portion of the Trust's accounts receivable are with
        customers and joint interest partners in the petroleum and natural
        gas industry and are subject to standard 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.

        The Trust has continued to closely monitor and reassess the
        creditworthiness of its counterparties, including financial
        institutions. This has resulted in the Trust reducing or mitigating
        its exposures to certain counterparties where it is deemed warranted
        and permitted under contractual terms.

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

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

        ---------------------------------------------------------------------
        ($000s)
        ---------------------------------------------------------------------
        Trade accounts receivable                                      8,092
        Accrued and other accounts receivable                         19,753
        ---------------------------------------------------------------------
                                                                      27,845
        ---------------------------------------------------------------------

        The carrying amount of accounts receivable and derivative assets
        represents the maximum credit exposure. The Trust has an allowance
        for doubtful accounts as at December 31, 2008 of $0.5 million.

        As at December 31, 2008 the Trust estimates its trade accounts
        receivables to be aged as follows:

        ---------------------------------------------------------------------
        Aging ($000s)
        ---------------------------------------------------------------------
        Not past due (less than 90 days)                               3,128
        Past due (90 or more days)                                     4,964
        ---------------------------------------------------------------------
        Total                                                          8,092
        ---------------------------------------------------------------------

        After considering December 31, 2008 trade accounts payable from the
        same companies and cash receipts received subsequent to December 31,
        2008, the Trust's trade receivables aged 90 or more days of
        approximately $5.0 million are reduced to a net balance of
        approximately $3.3 million.

        Included in accrued and other accounts receivable are approximately
        $6.9 million of amounts aged 90 or more days.

        c.  Liquidity risk

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

        The Trust prepares annual capital expenditure budgets and determines
        unitholder distributions on a monthly basis. Capital expenditure
        budgets and levels of monthly unitholder distributions are regularly
        monitored and updated as considered necessary. Further, the Trust
        utilizes authorizations for expenditures on both operated and non-
        operated projects to further manage capital expenditures. To
        facilitate the capital expenditure program, the Trust has a revolving
        reserve based credit facility, as outlined in note 6, which is at
        least reviewed annually by the lender. The Trust attempts to match
        its payment cycle with collection of petroleum and natural gas
        revenues on the 25th of each month. The Trust also mitigates
        liquidity risk by maintaining an insurance program to minimize
        exposure to insurable losses.

        The following are the contractual maturities of financial liabilities
        as at December 31, 2008:

        ---------------------------------------------------------------------
        Financial liability   (less than)
         ($000s)                  1 Year   1-2 Years   2-5 Years  Thereafter
        ---------------------------------------------------------------------
        Accounts payable and
         accrued liabilities      34,128           -           -           -
        Distribution payable
         to unitholders            1,570           -           -           -
        Bank debt - principal(1)       -     132,388           -           -
        Convertible debentures -
         principal                     -           -      86,250           -
        ---------------------------------------------------------------------
        Total                     35,698     132,388      86,250           -
        ---------------------------------------------------------------------

        (1) Bank debt is based on a revolving term which is reviewed annually
            and converts to a 366 day non-revolving facility if not renewed.

        The Trust's convertible debentures outstanding at December 31, 2008
        bear interest at a coupon rate of 7.5%, which currently requires
        total annual interest payments of $6.5 million. Interest due on the
        bank credit facility is calculated based upon floating rates.

        d.  Market risk

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

        Foreign currency exchange rate risk

        Foreign currency exchange rate risk is the risk that the fair value
        of future cash flows will fluctuate as a result of changes in foreign
        exchange rates. Although substantially all of the Trust's petroleum
        and natural gas sales are denominated in Canadian dollars, the
        underlying market prices in Canada for petroleum and natural gas are
        impacted by changes in the exchange rate between the Canadian and
        United States dollar. As at December 31, 2008, if the Canadian/US
        dollar exchange rate had decreased by US$0.01 with all other
        variables held constant, after tax net earnings for the year ended
        December 31, 2008 would have been approximately $0.4 million lower.

        An equal and opposite impact would have occurred to net earnings had
        the Canadian/US dollar exchange rate increased by US$0.01.

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

        Commodity price risk

        Commodity price risk is the risk that the fair value or future cash
        flows will fluctuate as a result of changes in commodity prices.
        Commodity prices for petroleum and natural gas are impacted by not
        only the relationship between the Canadian and United States dollar,
        as outlined above, but also world economic events that dictate the
        levels of supply and demand.

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

        The Trust's formal risk management policy permits management to use
        specified price risk management strategies for up to 50% of crude
        oil, natural gas and NGL production including fixed price contracts,
        costless collars and the purchase of floor price options, other
        derivative financial instruments, and physical delivery sales
        contracts 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 funds flows from operations, as well as, to ensure True
        realizes positive economic returns from its capital developments and
        acquisition activities.

        As at December 31, 2008, the Trust had entered into commodity price
        risk management arrangements as follows:

    -------------------------------------------------------------------------
                                                  Price        Price
    Type                 Period       Volume      Floor      Ceiling   Index
    -------------------------------------------------------------------------
    Natural Gas    Nov. 1, 2008 to    5,275  $ 7.61 CDN   $ 7.61 CDN    AECO
     fixed          March 31, 2009     GJ/day

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

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

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

    Natural Gas    July 1, 2009 to    5,000  $ 7.49 CDN   $ 7.49 CDN    AECO
     fixed          Sept. 30, 2009     GJ/day

    Natural Gas    Oct. 1, 2009 to    5,000  $ 8.09 CDN   $ 8.09 CDN    AECO
     fixed           Dec. 31, 2009     GJ/day

    Natural Gas    Jan. 1, 2010 to    5,000  $ 8.00 CDN   $ 8.00 CDN    AECO
     fixed          March 31, 2010     GJ/day
    -------------------------------------------------------------------------

        Subsequent to December 31, 2008, the Trust entered into commodity
        price risk management arrangements as follows:

    -------------------------------------------------------------------------
                                                  Price        Price
    Type                 Period       Volume      Floor      Ceiling   Index
    -------------------------------------------------------------------------
    Natural Gas   March 1, 2009 to    5,000  $ 4.89 CDN   $ 4.89 CDN    AECO
     fixed           June 30, 2009     GJ/day

    Natural Gas   March 1, 2009 to    4,500  $ 5.00 CDN   $ 5.00 CDN    AECO
     fixed          Sept. 30, 2009     GJ/day

    Natural Gas   March 1, 2009 to    5,000  $ 5.90 CDN   $ 5.90 CDN    AECO
     fixed           Dec. 31, 2009     GJ/day

    Natural Gas    July 1, 2009 to    5,000  $ 5.41 CDN   $ 5.41 CDN    AECO
     fixed          Sept. 30, 2009     GJ/day

    Natural Gas    Oct. 1, 2009 to    5,000  $ 6.26 CDN   $ 6.26 CDN    AECO
     fixed           Dec. 31, 2009     GJ/day

    Natural Gas    Jan. 1, 2010 to    5,000  $ 7.16 CDN   $ 7.16 CDN    AECO
     fixed          March 31, 2010     GJ/day

    Natural Gas   April 1, 2010 to    5,000  $ 6.59 CDN   $ 6.59 CDN    AECO
     fixed           June 30, 2010     GJ/day

    Natural Gas    Jan. 1, 2010 to    5,000           -   $ 8.05 CDN    AECO
     call option     Dec. 31, 2010     GJ/day

    Oil collar    March 1, 2009 to      500  $ 42.50 US   $ 65.60 US     WTI
                     Dec. 31, 2009     bbl/d
    -------------------------------------------------------------------------


        For the years ended December 31, 2008 and 2007, the gain (loss) on
        commodity contracts was comprised of the following:

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

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

        Gain (loss) on commodity contracts
          Realized(1)                                $ (28,222)    $   6,491
          Unrealized(2)                                 14,068       (10,343)
        ---------------------------------------------------------------------
                                                     $ (14,154)    $  (3,852)
        ---------------------------------------------------------------------

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

        Effective January 1, 2007, True adopted accounting standards related
        to the new financial instruments accounting framework, which
        encompasses three new Canadian Institute of Chartered Accountant
        ("CICA") Handbook Sections: 3855 "Financial Instruments - Recognition
        and Measurement", 3865 "Hedges", and 1530 "Comprehensive Income".

        On January 1, 2007, the Trust discontinued hedge accounting for all
        existing financial derivatives. As a result, a mark-to-market gain on
        the financial derivatives of $3.7 million, net of existing
        unamortized deferred commodity contract premiums and the tax effect
        thereon was included in accumulated other comprehensive income as of
        January 1, 2007. These net derivative gains in accumulated other
        comprehensive income at January 1, 2007 were reclassified to income
        throughout 2007 as the original hedged transactions affected net
        earnings. From January 1, 2007 forward, the changes in fair value of
        such derivatives are recognized in net income when incurred.

        The Trust has entered into a natural gas physical delivery sales
        contract to sell 5,275 GJ/day at a fixed price of $7.29/GJ and
        $7.90/GJ for the third and fourth quarter of 2009, respectively.

        As at December 31, 2008, if oil and natural gas liquids prices had
        been US$1 per barrel and natural gas prices $0.10 per mcf lower, with
        all other variables held constant, after tax net earnings for the
        year ended December 31, 2008 would have been approximately $1.8
        million lower. An equal and opposite impact would have occurred to
        net earnings had oil and natural gas liquids prices been US$1 per
        barrel and natural gas $0.10 per mcf higher.

        Interest rate risk

        Interest rate risk is the risk that future cash flows will fluctuate
        as a result of changes in market interest rates. The Trust is exposed
        to interest rate fluctuations on its bank debt which bears a floating
        rate of interest. As at December 31, 2008, if interest rates had been
        1% lower with all other variables held constant, after tax net
        earnings for the year ended December 31, 2008 would have been
        approximately $0.9 million higher, due to lower interest expense. An
        equal and opposite impact would have occurred to net earnings had
        interest rates been 1% higher.

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

        e. Capital management

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

        The Trust monitors capital based on the ratio of total net debt to
        annualized funds flow (the "ratio"). This ratio is calculated as
        total net debt, defined as outstanding bank debt, plus the liability
        component of convertible debentures, plus or minus working capital
        (excluding commodity contract assets and liabilities and future
        income tax assets or liabilities), divided by funds flow from
        operations (cash flow from operating activities before changes in
        non-cash working capital and deductions for asset retirement costs)
        for the most recent calendar quarter, annualized (multiplied by
        four). The total net debt to annualized funds flow ratio may increase
        at certain times as a result of acquisitions, fluctuations in
        commodity prices, timing of capital expenditures and other factors.
        In order to facilitate the management of this ratio, the Trust
        prepares annual capital expenditure budgets and sets unitholder
        distributions on a monthly basis. Capital expenditure budgets and
        levels of monthly unitholder distributions are reviewed and updated
        as necessary depending on varying factors including current and
        forecast prices, successful capital deployment and general industry
        conditions. The annual and updated budgets and monthly unitholder
        distributions are approved by the Board of Directors.

        Given the current uncertain economic conditions, the Trust revised
        the level of capital spending for 2009 and suspended its March 2009
        distribution in order to increase financial flexibility. The Trust
        plans to continue to monitor forecasted debt levels to manage its
        operations within forecasted funds flow. The Trust expects the total
        net debt to annualized funds flow ratio to reflect the economic
        burdens experienced as a result of the recent downturn in the global
        economic environment. The Trust will continue to monitor developments
        within the global economic environment to consider the impacts on the
        current or future lending arrangements.

        The Trust's long-term strategy, under a more stable economic
        environment, is to target a total net debt to annualized funds flow
        ratio of 2.0 times. As at December 31, 2008, the Trust's ratio of
        total net debt to annualized funds flow based on fourth quarter
        results and annual funds flow was 9.2 times and 2.8 times,
        respectively. The total net debt to annualized funds flow ratio as at
        December 31, 2008 increased from that at September 30, 2008 of 2.3
        times due to lower funds flow from operations in the fourth quarter,
        which was significantly impacted by the decline in commodity prices,
        in addition to slightly higher total net debt due partially to the
        timing of the capital program in the second half of 2008. The Trust
        expects this ratio to decrease through 2009 as total net debt levels
        are reduced; True continues to take a balanced approach to the
        priority use of funds flows. The Debentures have a maturity date of
        June 30, 2011, upon maturity, the Trust may settle the principal in
        cash or issuance of additional Trust units. Excluding Debentures, net
        debt to annualized funds flow based on fourth quarter results and
        annual funds flow was 5.7 times and 1.7 times, respectively.

        The calculation of total net debt and total net debt to cash flow is
        as follows:

        ---------------------------------------------------------------------
                                                     Years ended December 31,
        ($000s, except where noted)                       2008          2007
        ---------------------------------------------------------------------
        Long-term debt                                 132,388       168,475
        Convertible debentures
         (liability component)                          81,124        79,407
        Working capital deficiency                       1,492         2,431
        ---------------------------------------------------------------------
        Total net debt(1) at year end                  215,004       250,313

        Debt to funds flow from
         operations ratio annualized
        Funds flow from operations annualized(2)        23,460        78,056
        Total net debt to periods funds flow
         from operations ratio annualized                 9.2x          3.2x

        Net debt(1) (excluding convertible
         debentures) at quarter end                    133,880       171,006
        Net debt to periods funds flow
         from operations ratio annualized(2)              5.7x          2.2x

        Debt to funds flow from operations ratio
        Total net debt(1) at year end                  215,004       250,413
        Funds flow from operations for the year         77,893       101,172
        Total net debt to funds flow
         from operations ratio for the year               2.8x          2.5x

        Net debt(1) (excluding convertible
         debentures) at year end                       133,880       171,006
        Net debt to funds flow
         from operations ratio                            1.7x          1.7x
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

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

        (2) Debt to funds flow from operations ratio annualized is calculated
            based upon fourth quarter funds flow from operations annualized.


        The Trust's credit facility is based on petroleum and natural gas
        reserves (see note 6). The credit facility outlines limitations on
        percentages of forecasted production, from external reserve engineer
        data, which may be hedged through financial commodity risk management
        contracts. The Trust also has outstanding normal course issuer bids
        for its convertible debentures and trust units, as detailed in note 7
        and 10, respectively.

        The Trust's ability to issue trust units is subject to external
        restrictions as a result of the Specified Investment Flow-Through
        Entities Legislation (the "SIFT tax") whereby the Trust may lose the
        benefit of a four year grandfathering period if the Trust exceeds the
        limits on the issuance of new trust units and convertible debt that
        constitute normal growth during the grandfathering period (subject to
        certain exceptions). The normal growth limits are calculated as a
        percentage of the Trust's market capitalization of approximately $737
        million on October 31, 2006, which the Trust may currently issue in
        additional equity without offending the normal growth guidelines
        between now and 2011. The normal growth restriction on trust unit
        issuance is monitored by management as part of the overall capital
        management objectives. The Trust is in compliance with the normal
        growth restrictions.

        f. Fair value of financial instruments

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

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

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

        The fair value of the convertible debentures of $58.9 million is
        based on exchange traded values.

        ADDITIONAL INFORMATION

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

        Reconciliation of Proved Reserves(2)
        ---------------------------------------------------------------------
                               Crude oil    Coal bed     Natural  Equivalent
                                   & NGL     methane         gas       units
                                   (mbbl)      (mmcf)      (mmcf)      (mboe)
        ---------------------------------------------------------------------
        December 31, 2007         10,778       1,812      99,036      27,587
        Revision of
         previous estimates          100          41       4,200         806
        Discoveries,
         extensions, infill
         drilling and
         improved recovery           489          52       4,768       1,291
        Dispositions, net
         of acquisitions              82           -     (12,878)     (2,064)
        Production                (1,581)       (249)    (16,157)     (4,314)
        ---------------------------------------------------------------------
        December 31, 2008          9,868       1,656      78,969      23,306
        ---------------------------------------------------------------------

        Proved plus
         probable reserves
        December 31, 2008         17,781       2,090     126,892      39,278
        December 31, 2007         18,862       2,398     156,866      45,405
        ---------------------------------------------------------------------

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

        (2) Forecast prices before royalties.


        True Energy Trust is a Calgary-based oil and natural gas trust. True
        is an open-ended, incorporated investment trust governed by the laws
        of the Province of Alberta. The purpose of the Trust is to indirectly
        explore for, develop and hold interests in petroleum and natural gas
        properties, through investments in securities of subsidiaries and net
        profits interests. The trust structure allows individual unitholders
        to participate in the cash flow of the business. Cash flow is
        realized from the Trust's subsidiaries' ownership of natural gas and
        petroleum properties and related facilities. Trust units and
        convertible debentures of True trade on the Toronto Stock Exchange
        ("TSX") under the symbols TUI.UN and TUI.DB, respectively.%SEDAR: 00021401E



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