Sound Energy Trust Announces Fourth Quarter And Year-End 2006 Results



    TSX: SND.UN

    CALGARY, March 14 /CNW/ - Sound Energy Trust ("Sound" or the "Trust")
announces its financial and operating results for the fourth quarter and year
ended December 31, 2006.

    
    Highlights

        -  NAV Energy Trust and Clear Energy Inc. merged effective August 14,
           2006 to create Sound Energy Trust and spin out an exploration
           company, Sure Energy Inc.
        -  For the year, production volumes grew from 7,736 boe/d to
           8,565 boe/d. Fourth-quarter production of 10,536 boe/d was
           36 percent higher than in Q4 2005, mainly as a result of the Clear
           merger.
        -  Sound spent $62.1 million on capital expenditures, including
           capitalized G&A and transaction costs on the Clear merger, in
           2006 and participated in 73 wells drilled that saw a 96 percent
           success rate.
        -  With commodity prices declining throughout the year, funds flow
           from operations was lower by 11 percent in 2006 compared with
           2005, and by nine percent from Q4 05 to Q4 06.
        -  Reserves grew by 9.4 MMboe, and the reserve life index at the end
           of 2006 was 8.9 years, based on forecast daily production for 2007
           of 10,200 boe/d and year-end 2006 P+P reserves of 33.1 MMboe.


    Key Performance Indicators

    ($000s except per        Three months ended           Years ended
     unit amounts)              December 31               December 31

                           2006(5)  2005  % Change   2006(5)  2005  % Change
    -------------------------------------------------------------------------
    FINANCIAL
    -------------------------------------------------------------------------
    Production revenue
     after hedging         46,524   45,060       3  158,872  158,320       -

    Funds flow from
     operations(1)         18,952   21,280     (11)  64,001   72,799     (12)
      Per unit
        - basic              0.33     0.75     (56)    1.62     2.59     (37)
        - diluted            0.30     0.74     (59)    1.46     2.54     (43)
    Net income              3,403    7,284     (53)   6,521   18,207     (64)
      Per unit
        - basic              0.06     0.26     (77)    0.17     0.65     (74)
        - diluted            0.06     0.25     (76)    0.16     0.63     (75)
    Distributions declared 17,042    8,502     100   48,281   39,424      22
      Per unit               0.30     0.30       -     1.20     1.40     (14)
      Payout ratio(2)         90%      40%       -      75%      54%       -
    Capital expenditures -
     exploration and
     development           11,040   18,414     (40)  55,675   51,993       7
    As at December 31,
     2006
      Unitholders'
       capital                                      522,211  290,182      80
      Convertible
       debentures                                   100,548   59,543      69
      Bank debt                                     102,300   47,018     118
      Working capital
       deficiency(3)                                 10,733   19,640     (45)
      Total net debt(4)                             113,033   66,658      70
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    ($000s except per        Three months ended            Years ended
     unit amounts)              December 31                December 31

                         2006(5)   2005   % Change  2006(5)   2005   % Change
    OPERATING                   (Restated)                 (Restated)
                                    (5)(9)                     (5)(9)
    -------------------------------------------------------------------------
    Daily production
      Crude oil and NGLs
       (bbl/d)              4,295    4,118       4    4,005    4,177      (4)
      Natural gas (Mcf/d)  37,446   21,835      71   27,360   21,351      28
      Oil equivalent
       (boe/d 6:1)         10,536    7,757      36    8,565    7,736      11

    Average wellhead
     prices
      Crude oil and NGLs
       ($/bbl) - before
       hedging              51.40    60.25     (15)   61.67    59.55       4
      Crude oil and NGLs
       ($/bbl) - hedging
       gain (loss)           3.61     0.10   3,510     1.05    (0.62)   (269)
      Natural gas ($/Mcf) -
       before hedging        7.13    11.48     (38)    6.69     8.95     (25)
      Natural gas ($/Mcf) -
       hedging gain (loss)   0.09    (0.45)   (120)    0.03    (0.22)   (114)
      Oil equivalent before
       hedging ($/boe 6:1)  46.20    64.37     (28)   50.23    57.02     (12)
      Oil equivalent after
       hedging ($/boe 6:1)  48.00    63.14     (24)   50.82    56.07      (9)

    Operating netback after
     hedging ($/boe)
      Commodity revenue(6)  46.20    64.37     (28)   50.23    57.02     (12)
      Hedging                1.80    (1.23)   (246)    0.59    (0.95)   (162)
      Royalties             (7.58)  (13.09)    (42)   (9.17)  (11.66)    (21)
      Production           (11.91)  (11.57)      3   (12.44)  (10.63)     17
      Transportation        (1.49)   (1.74)    (14)   (1.80)   (1.76)      2
                          ---------------------------------------------------
      Operating netback
       after hedging        27.02    36.74     (26)   27.41    32.02     (14)

    Trust units (000s)
      Weighted average -
       basic               56,781   28,332     100   39,439   28,156      40
      Weighted average -
       diluted(7)          60,370   28,870     109   41,071   28,704      43
      Total trust units
       outstanding         56,849   28,351     101   56,849   28,351     101

    Unit Trading
      High ($/unit)          7.49     9.92     (24)    9.82    10.95     (10)
      Low ($/unit)           4.45     8.25     (46)    4.45     7.30     (39)
      Close ($/unit)         5.11     9.44     (46)    5.11     9.44     (46)
      Average daily trading
       volume (000s)          435       82     430      217      158      37
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Notes
    (1)  Management uses funds flow from operations (cash flow from operating
         activities before changes in non-cash working capital and asset
         retirement obligations settled) to analyze operating performance and
         leverage and to provide investors with information on potential cash
         distributions. Funds flow from operations as presented does not have
         any standardized meaning prescribed by Canadian GAAP and therefore,
         it may not be comparable with the calculation of similar measures
         for other entities. Funds flow from operations as presented is not
         intended to represent operating activities, net earnings or other
         measures of financial performance calculated in accordance with
         Canadian GAAP. All references to funds flow from operations
         throughout the following MD&A are based on funds flow from
         operations before changes in non-cash working capital and asset
         retirement obligations settled. Netbacks equal total revenue less
         royalties and operating costs calculated on a boe basis.
    (2)  Payout ratio is a non-GAAP measurement. Payout ratio represents
         distributions declared divided by funds flow from operations. The
         payout ratio presented does not have any standardized meaning
         prescribed by Canadian GAAP and therefore may not be comparable with
         the calculation of similar measures for other entities.
    (3)  Working capital equals current assets minus current liabilities
         excluding bank debt.
    (4)  Net debt equals bank debt plus working capital.
    (5)  Includes the financial and operating results of Clear Energy Inc.
         from the date of the closing of the Plan of Arrangement, which
         occurred on August 14, 2006.
    (6)  Includes other revenue.
    (7)  Trust units weighted average diluted includes exchangeable shares.
    (8)  2005 has been restated for the changes in accounting policies -
         refer to "Changes in Accounting Policies" in the MD&A.
    (9)  The merger of NAV Energy Trust and Clear Energy Inc. has been
         accounted for as a purchase by NAV Energy Trust. Accordingly, the
         comparative figures are those of NAV Energy Trust for the same
         period in 2005.
    (10) All currency references are to Canadian dollars unless otherwise
         indicated.
    (11) Where production is stated on a boe basis, natural gas volumes have
         been converted to boes at a ratio of 6,000 cubic feet of natural
         gas to one barrel of oil.
    


    Message to Unitholders


    Fellow Unitholders,

    The past year ended December 31, 2006, was a year of significant growth
for the Trust as we completed NAV Energy Trust's merger with Clear Energy Inc.
in August. At the time of the merger, we felt the new entity merited a fresh
face, and we re-named the Trust to its current name, Sound Energy Trust.
    The merger was built upon the premise of achieving a size for the Trust
that would result in easier access to capital; higher liquidity in the trading
of our units; and improved recognition in the markets. Indeed, our larger size
allowed us to expand on our borrowing base, and the new Sound units traded at
far greater volumes than before the union of the two companies: a daily
average in 2006 for NAV of 121,000 units compared with 361,700 for Sound from
August 2006 to February 2007. We completed the full integration of the Clear
team as well as Clear's assets very quickly and efficiently, with a smooth
transition into the expanded operations.
    Shortly after the closing of the merger, which occurred on August 14, the
Trust started to face a number of unforeseen challenges, beginning with an
uninterrupted decline in natural gas prices that continued well into the first
quarter of 2007. As a result and despite the addition of approximately
4,000 boe/d of production from Clear, cash flows did not meet our
expectations.
    While the average oil and natural gas liquids ("NGLs") price per barrel
the Trust received in 2006 was $61.67 versus the $59.55 average for 2005, oil
and NGL prices declined in the last quarter of 2006, during which Sound
received an average of $51.40/bbl. The natural gas price received by Sound in
2006 averaged $6.69/Mcf compared with a 2005 average of $8.95/Mcf. As the
Trust's production is weighted towards natural gas, the effect of dropping
natural gas prices is greater than oil price fluctuations. The lower commodity
prices and, consequently, lower cash flows, resulted in a somewhat constrained
capital program during the months following the merger with Clear; despite
this obstacle, our operations group was able to maintain production levels
throughout the last quarter of the year at 10,500 boe/d. In total, the Trust
spent $62.1 million of capital in 2006.
    Our proved plus probable reserves grew from 23.8 million boe at the end
of 2005 to 33.1 million boe at December 31, 2006. This 40-percent increase in
our reserve base includes approximately 10.4 million boe resulting from the
Clear merger.
    In October, the Board authorized management to issue additional
securities in order to improve Sound's balance sheet. The Trust entered into
an agreement with a syndicate of underwriters to offer to investors, on a
bought-deal basis, $55 million of unsecured subordinated debentures,
convertible to Trust Units at a conversion price of $8.55 per Trust Unit and
with an annual coupon rate of 6.75 percent. On October 31, the federal Finance
Minister made the announcement that the government intended to impose a tax on
income trusts beginning in 2011. This news had a major negative impact on
trust unit prices, including ours, as the markets reacted to this turnaround
in policy. The fallout from the Finance Minister's October 31 announcement,
however, created an additional obstacle, and it became necessary to
re-negotiate the terms of the offering. Sound was able to ultimately sell a
total of $41.035 million of convertible debentures at a conversion price of
$6.10 per Trust Unit and with a coupon of eight percent per annum. The gross
proceeds of $41.035 million included the partial exercise by the underwriters
of the over-allotment option. The net proceeds of the offering were used to
reduce debt, fund development activities and for general Trust purposes.
    Year-end total net debt amounted to $113.0 million against an available
bank line of $146.5 million, not including a short-term $20.0 million facility
expiring on December 31. In March 2007, the Trust's syndicate of lenders
completed an interim review that resulted in a borrowing base of
$135.0 million. The lower borrowing base is mainly the result of the Trust's
fourth-quarter debenture issue, which resulted in expanding the Trust's
overall debt capacity. Sound's financing strategy is to maintain capital
expenditures and distributions within cash flow from operations.
    As part of our strategy to be a sustainable Trust with a strong balance
sheet and a low payout ratio, the Board of Directors determined in February
2007 that a distribution cut was prudent. Following a 21-month period of
monthly distributions of $0.10 per Trust Unit, we reduced these to $0.055 per
Trust Unit effective with the March 15, 2007 distribution. This cut helps to
secure our capital budget for the year, thus enabling the Trust to continue to
add value to you, our Unitholders, by utilizing the available funds for an
active drilling program. We are confident that barring a major drop in
commodity prices, we will be able to sustain this distribution level for the
foreseeable future.
    To further protect the capital program and cash distributions, the Trust
entered into a number of new hedging agreements during the first quarter of
2007. Currently, approximately 37 percent of our daily oil production and
approximately 56 percent of our daily natural gas production are protected
through costless collars. Once the latest oil hedge commences on April 1,
49 percent of our daily oil input will be protected through year-end. For
details on our current hedges, please refer to the hedging tables set out in
the MD&A.

    Outlook

    Sound's capital budget is set at $31.3 million for 2007, based on a price
deck of US$55.00/bbl WTI oil and $7.00/Mcf AECO natural gas, that we
anticipate will allow us to produce an annual average of approximately
10,200 boe/d. First-quarter 2007 production levels are estimated at
approximately 10,100 boe/d. Should we continue to see a recovery in commodity
prices, the increase in cash flow will be applied to reducing debt levels and
accelerating our development program. With a multi-year inventory of already
identified drilling prospects and a large land base of currently approximately
430,000 net undeveloped acres, the Trust is in a position to grow its
production organically once additional funds become available. We have
initiated extensive efforts to lower our operating costs and are beginning to
see results, which we anticipate to further improve throughout the year. We
remain committed to increasing our reserves base and expect to see significant
reserves additions this year, mainly in Central Alberta where we are actively
expanding our coalbed methane ("CBM") programs. The Peace River Arch area as
well is largely undeveloped, and with very large natural gas reservoirs
recently discovered on lands adjacent to our properties, we expect this
property to be one of the main contributors of future growth for Sound.
    Currently, an active drilling program is underway in our winter-access
properties in Northern Alberta, and we are pleased with the results thus far.
Following spring break-up, our focus will change to our other core properties.
In particular, the waterflood expansion will continue in Southeast
Saskatchewan, our CBM program at Nevis targets a total of 17 gross (9.7 net)
wells for the year, and Glacier and Clear River in the Peace River Arch will
see extensive drilling activity.
    Sound has a very proactive approach to portfolio management. As part of
this strategy, we are constantly and very actively involved in the deal flow
in the Western Canada Sedimentary Basin and continuously seek advantageous
farm-in or farm-out opportunities. The Trust is currently in the process of
divesting a number of small, non-core properties, with the proceeds to be
applied to debt repayment and development activities in our low-risk,
high-deliverability fields in Alberta and Saskatchewan.
    It remains our objective to be known as a low-payout trust, and with the
distribution cut effected beginning in March 2007, we estimate our payout
ratio to average approximately 50 percent for the year. Based on price
assumptions of US$55.00/bbl WTI and $7.00/Mcf AECO, our cash flow projections
for 2007 are $78.1 million. These funds will enable us to cover distributions
of approximately $43.0 million and capital expenditures of $31.3 million
without issuing additional equity or increasing our debt levels. Efforts to
control costs continue. We are seeing a slight improvement in service costs in
Western Canada, which we expect to positively affect our operating expenses.
    With the looming taxation of Trusts planned to commence in 2011, a
commonly asked question addresses Sound's intentions for the future. As the
proposed legislation has not yet been passed into law and details are yet to
be published, we are carrying out business as usual and look forward to
providing you, our Unitholders, with stable monthly distributions and
increasing value on what we believe is a sound investment.
    We have a great team of individuals in place that includes the addition
of talent both from the former Clear group as well as new team members added
following the merger. I would like to take this opportunity to thank every one
of them for their hard work; it's the people that make a company succeed, and
with this team, we are on our way!

    Tom Stan
    President and Chief Executive Officer
    March 9, 2007


    
    -------------------------------------------------------------------------
                  Annual and Special Meeting of Unitholders
                         May 30, 2007, 9:00 a.m. MDT
               The Metropolitan Conference Centre, Royal Room
                             333 - 4th Avenue SW
                                 Calgary, AB
    -------------------------------------------------------------------------
    

    Operational Review

    Sound's major properties are all located within the Western Canada
Sedimentary Basin and concentrated in four core regions of Alberta and
Saskatchewan. Each region is comprised of operated properties with a
significant production and land base, infrastructure ownership and seismic
databases.
    During 2006, the Trust's drilling program encompassed a total of 73 (42.1
net) wells. We achieved a 96 percent success rate, reflecting the low risks
posed by the majority of our assets. Production for the year averaged
8,565 boe/d, 11 percent higher than last year, mainly as a result of the
merger with Clear Energy that closed in mid-August. Our output is well
balanced, with approximately 53 percent natural gas and 47 percent oil and
natural gas liquids.

    
    The following tables set out key operational statistics:

    Drilling Activity
    -----------------

                                       Three months ended       Year ended
                                          December 31          December 31
    Gross (net) number of
     wells drilled                     2006       2005       2006       2005
    -------------------------------------------------------------------------
    Natural gas                     15 (3.6)   10 (5.8)  57 (32.6)  48 (34.3)
    Oil                              5 (4.0)    8 (6.6)  14 (8.0)   22 (19.7)
    Dry and abandoned                     -          -    2 (1.5)    3 (1.5)
    -------------------------------------------------------------------------
    Total wells                     20 (7.6)  18 (12.4)  73 (42.1)  73 (55.5)
    -------------------------------------------------------------------------
    Success rate                       100%       100%        96%        97%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Production by Area
    ------------------

                           Three months ended               Year ended
                              December 31                  December 31

                         2006     2005  % change     2006     2005  % change
    -------------------------------------------------------------------------
    Northern Alberta
      Crude oil and
       NGLs (bbl/d)     1,190    1,588      (25)    1,363    1,712      (20)
      Natural
       gas (Mcf/d)      7,132   10,738      (34)    9,541   10,420       (8)
      Total (boe/d)     2,379    3,378      (30)    2,953    3,449      (14)
    -------------------------------------------------------------------------
    Peace River Arch(1)
      Crude oil and
       NGLs (bbl/d)      675         -        -       281        -        -
      Natural
       gas (Mcf/d)     8,646         -        -     3,249        -        -
      Total (boe/d)    2,116         -        -       823        -        -
    -------------------------------------------------------------------------
    Central Alberta
      Crude oil and
       NGLs (bbl/d)      437       385       14       355      412      (14)
      Natural
       gas (Mcf/d)    21,543    10,940       97    14,394   10,756       34
      Total (boe/d)    4,027     2,208       82     2,754    2,205       25
    -------------------------------------------------------------------------
    Saskatchewan
      Crude oil and
       NGLs (bbl/d)    1,993     2,145       (7)    2,006    2,053       (2)
      Natural
       gas (Mcf/d)       125       157      (20)      176      175        1
      Total (boe/d)    2,014     2,171       (7)    2,035    2,082       (2)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total (boe/d)     10,536     7,757       36     8,565    7,736       11
    -------------------------------------------------------------------------
    (1) Acquired through the merger with Clear effective August 14, 2006.
    


    Properties
    ----------

    Northern Alberta

    With an average daily output of 9,541 Mcf/d of natural gas and
1,363 bbl/d of mostly light oil and liquids (2,953 boe/d), the Northern
Alberta region represented 34 percent of the Trust's total production volume
in 2006. Our net undeveloped land holdings in the area amount to 86,766 acres,
in which we hold an average working interest of 80 percent. During 2006, we
participated in the drilling of 25 (19.7 net) wells, resulting in 23
(17.7 net) natural gas wells, 1 (1.0 net) oil well and 1 (1.0 net) dry hole.
This area is winter-access only, and the vast majority of the drilling takes
place during the winter months. For 2007, the Trust plans to drill 5 (5.0 net)
new wells on its Northern Alberta properties, and field activities are
currently well underway to reach that objective.
    The capital program of approximately $9.5 million in Northern Alberta for
2007 represents a combination of step-out and infill drilling, with
corresponding infrastructure expansion. The major focus areas of Zama Lake and
Rainbow are comprised of Keg River oil pools with natural gas reservoirs in
the Sulphur and Slave Point formations, among others. In addition, Bluesky and
Gething sandstone reservoirs provide longer-life, sweet gas potential.

    Peace River Arch

    The Peace River Arch area was added to our portfolio through the Clear
acquisition in August of 2006. The Trust's production from the region averaged
3,249 Mcf/d of natural gas and 281 bbl/d of mostly light, sweet crude and
natural gas liquids for 2006. On an equivalent boe basis, the output from our
Peace River Arch properties, with the main producing property at Clear River,
totaled 823 boe/d in 2006, or approximately 10 percent of the Trust's total
production. Our land holdings in this area are extensive at 124,133 gross
(99,474 net) acres.
    This region is geologically very promising as it provides multi-zone
natural gas potential from many geological horizons. Since acquiring this
property, we have participated in the drilling of 5 (2.2 net) wells resulting
in 3 (1.2 net) natural gas wells, 2 (1.0 net) oil wells and no dry holes. For
2007, we are targeting high-impact, medium-depth formations and plan to
participate in 6 gross (2.7 net) wells on a capital budget allocated to the
area of approximately $6.7 million.
    At Clear River, the Trust has successfully delineated an existing oil
pool, with plans to further expand the pool. The Glacier area remains
prospective with extensive development opportunity in several zones, including
the Dunvegan, Montney and Nikanassin formations.

    Central Alberta

    Our Central Alberta properties contributed 32 percent towards the Trust's
total daily production volume in 2006, with 14,394 Mcf/d of natural gas and
355 bbl/d of mostly light oil and liquids, for a total of 2,754 boe/d. In
2006, we participated in the drilling of 29 (13.7 net) wells, all of which are
natural gas wells. Our land holdings in this area cover 406,548 gross
(224,125 net) acres, and we operate our own pipelines and compression. This
high level of operatorship provides us control over well-optimization and
pipeline access.
    The Nevis area is one of our most significant natural gas assets where we
focus on liquids-rich Mannville gas and have continued to develop our coalbed
methane ("CBM") potential from the Horseshoe Canyon formation in the Nevis
area. The Trust also added CBM production and potential from the Horseshoe
Canyon formation in Nevis through the Clear acquisition.
    Central Alberta remains a focus area for the Trust in adding natural gas
production from other gas-bearing horizons, including the long-life Edmonton
Sands and Belly River formations. Our plans for 2007, that encompass capital
allocations of approximately $8.3 million, include the drilling of 19 gross
(10.3 net) wells and continued development of our CBM opportunities, which
will also include gas from the Mannville coal formation.

    Saskatchewan

    In 2006, our Saskatchewan core area represented approximately 24 percent
of our total production volume, with a contribution of 2,035 boe/d consisting
of 2,006 bbl/d of mainly heavy and medium-gravity oil and 176 Mcf/d of natural
gas. We hold 148,564 net acres of undeveloped land, with an average working
interest of 89 percent. During the reporting period, we participated in
14 (6.5 net) wells resulting in 2 (0.05 net) natural gas wells, 11 (6.0 net)
oil wells and 1 (0.5 net) dry hole.
    Our main property in southeast Saskatchewan is Wapella, where we have
initiated a staged waterflood program to enhance reserves and productivity.
The capital program for 2007 of approximately $6.8 million will allow for
continued delineation and development of the existing pools at Wapella and
East Lloyd. In 2007, we plan to drill 15 (13.0 net) wells in the area and to
expand our waterflood scheme at Wapella.

    Reserves
    --------

    The following tables summarize certain information contained in the
year-end report by Sound's independent engineers, GLJ Petroleum Consultants
Ltd. ("GLJ"). More detailed information on Sound's year-end reserves will be
included in the Annual Information Form, which will be filed on SEDAR on or
before March 30, 2007.

    It should not be assumed that the estimates of future net revenues
presented in the tables below represent the fair market value of the reserves.
There is no assurance that the forecast prices and costs assumptions will be
attained, and variances could be material. The recovery and reserve estimates
of Sound's crude oil, natural gas liquids and natural gas reserves provided
herein are estimates only, and there is no guarantee that the estimated
reserves will be recovered. Actual crude oil, natural gas and natural gas
liquids reserves may be greater than or less than the estimates provided
herein.

    
             Summary of Company Interest(1) Oil and Gas Reserves
                       using Forecast Prices and Costs

                        -------------------------- --------------------------
                            December 31, 2005          December 31, 2006
                                Reserves                   Reserves
                        -------------------------- --------------------------
                           Oil                        Oil
                           and   Natural              and   Natural
    Reserves Category     NGLs     gas      Boe      NGLs     gas      Boe
    ------------------- -------- -------- -------- -------- -------- --------
                         (Mbbls)   (Bcf)   (Mbbls)  (Mbbls)   (Bcf)    (Mboe)
    Proved
      Developed
       Producing          6,592     31.7   11,878    5,843     49.8   14,144
      Non-Producing       1,733     16.2    4,430    3,266     19.7    6,541
                        -------- -------- -------- -------- -------- --------
    Total Proved          8,325     47.9   16,308    9,109     69.5   20,685
    Probable              3,830     21.7    7,443    5,654     40.8   12,463
                        -------- -------- -------- -------- -------- --------
    Total Proved Plus
     Probable(2)         12,155     69.6   23,751   14,763    110.3   33,148
                        -------- -------- -------- -------- -------- --------
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Supplementary information to the requirements stipulated in
        NI 51-101.
    (2) Numbers may not add due to rounding.



           Summary of Net (After Royalties)(1) Oil and Gas Reserves
                       using Forecast Prices and Costs

                        -------------------------- --------------------------
                            December 31, 2005          December 31, 2006
                                Reserves                   Reserves
                        -------------------------- --------------------------
                           Oil                        Oil
                           and   Natural              and   Natural
    Reserves Category     NGLs     gas      Boe      NGLs     gas      Boe
    ------------------- -------- -------- -------- -------- -------- --------
                         (Mbbls)   (Bcf)   (Mbbls)  (Mbbls)   (Bcf)    (Mboe)
    Proved
      Developed
       Producing          5,607     26.7   10,064    4,975     41.8   11,940
      Non-Producing       1,460     13.1    3,633    2,830     16.1    5,520
                        -------- -------- -------- -------- -------- --------
    Total Proved          7,067     39.8   13,697    7,805     57.9   17,460
    Probable              3,263     18.0    6,268    4,886     33.9   10,525
                        -------- -------- -------- -------- -------- --------
    Total Proved Plus
     Probable(2)         10,330     57.8   19,965   12,691     91.8   27,985
                        -------- -------- -------- -------- -------- --------
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) In accordance with the requirements stipulated in NI 51-101.
    (2) Numbers may not add due to rounding.



                         Reconciliation of Reserves
                          by Principal Product Type
                          Forecast Prices and Costs

    Factors                   Company Interest(1)           Net

                                        Proved +                    Proved +
                      Proved  Probable  Probable  Proved  Probable  Probable
                      (Mboe)   (Mboe)    (Mboe)   (Mboe)   (Mboe)    (Mboe)
    -------------------------------------------------------------------------
    December 31,
     2005             16,308     7,443    23,751  13,697     6,268    19,965
    -------------------------------------------------------------------------
    Discoveries           72        24        96      59        19        78
    Extensions           769       813     1,582     625       646     1,271
    Infill drilling(2)   172       237       409     154       201       355
    Improved recovery    126       342       468     108       288       396
    Technical revisions  233      (663)     (430)    308      (380)      (72)
    Acquisitions       6,138     4,269    10,407   5,023     3,485     8,508
    Dispositions          (7)       (2)       (9)     (6)       (2)       (8)
    Economic factors       0         0         0       0         0         0
    Production        (3,126)        0    (3,126) (2,508)        0    (2,508)
    -------------------------------------------------------------------------
    December 31,
     2006             20,685    12,463    33,148  17,460    10,525    27,985
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Supplementary information to the requirements stipulated in
        NI 51-101.
    (2) The above change categories correspond to standards set out in the
        Canadian Oil and Gas Evaluation Handbook. For reporting under NI 51-
        101, reserves additions under "infill drilling" and "improved
        recovery" should be combined and reported as "improved recovery"
    (3) Numbers may not add due to rounding.


    Net Asset Value
    ---------------

    Despite the significant declines in the Trust's unit price over the last
several months, management remains focused on strengthening net asset value
through 2007. A lower payout ratio will allow for continued reinvestment of
cash flow into an extensive development project inventory.


                    Net Asset Value at December 31, 2006
                          Forecast Prices and Costs

    $000s, except per-unit data                 Discount rate per year

                                                5%          8%         10%
    -------------------------------------------------------------------------
    Proved plus probable reserves(1)         582,906     507,551     467,794
    Undeveloped land(2)                       40,812      40,812      40,812
    Convertible debentures                  (100,548)   (100,548)   (100,548)
    Long-term debt plus working capital     (113,033)   (113,033)   (113,033)
    -------------------------------------------------------------------------
    Net asset value ("NAV")                  410,137     334,782     295,025
    -------------------------------------------------------------------------
    Units outstanding, basic(3)           58,432,934  58,432,934  58,432,934
    NAV per trust unit, basic                   7.02        5.73        5.05
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Based on the December 31, 2006 GLJ Report.
    (2) Based on 3rd-party evaluation dated December 31, 2006; does not
        include seismic value, internally estimated to be $29.8 million.
    (3) Comprised of 56,849,413 Trust units outstanding plus the conversion
        of 1,361,074 exchangeable shares.


    Finding and Development Costs
    -----------------------------

    Finding and development ("F&D") costs for 2006 were disappointing and
significantly higher than in 2005. The higher costs were primarily the result
of increased facilities expansions that were required in several major
producing areas to support future drilling activity and maintain control over
exploration and development expenses in 2007. The F&D costs on a proved basis
are expected to improve in 2007, with further development plans and new wells
anticipated to result in higher proved reserve bookings. As well, increased
exposure to high-impact plays in the Peace River Arch is expected to
contribute to a reduction in F&D costs in future years.


    $000s except per boe amounts               2006                2005

                                                  Proved              Proved
                                                    plus                plus
                                        Proved  probable    Proved  probable
    -------------------------------------------------------------------------
    Exploration and development
     expenditures                       55,675    55,675    51,993    51,993
    Add changes in future capital(1)      (579)   12,925     9,288    10,005
    -------------------------------------------------------------------------
    Total capital                       55,096    77,600    61,281    61,998
    Reserve additions(2) (Mboe)          1,372     2,125     3,006     3,342
    Finding costs ($/boe)
      Based on capital                   40.58     26.20     17.30     15.56
      Based on capital and
       changes in future capital         40.16     36.52     20.39     18.55
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) GLJ estimated change in future development capital required to
        recover reserves.
    (2) Based on company interest discovered reserves and
        extensions, net of revisions and before deduction of royalties.


    Finding, Development and Acquisition Costs
    ------------------------------------------

    $000s except per boe amounts              2006                2005

                                                  Proved              Proved
                                                    plus                plus
                                        Proved  probable    Proved  probable
    -------------------------------------------------------------------------
    Exploration, development and
     acquisition expenditures(1)       340,320   340,320    52,393    52,393
    Add changes in future capital(2)      (579)   21,925     9,288    10,005
    -------------------------------------------------------------------------
    Total capital                      339,741   362,245    61,681    62,398
    Reserve additions(3) (Mboe)          7,503    12,523     2,977     3,269
    Finding costs ($/boe)
      Based on capital                   45.36     27.18     17.60     16.03
      Based on capital and
       changes in future capital         45.28     28.93     20.72     19.09
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) 2006 exploration, development and acquisition expenditures of
        $55,675,000, $1,517,000 of acquisitions excluding the Clear
        Acquisition, the Clear Acquisition consideration of $239,633,000, and
        Clear Energy debt assumed, net of working capital of $43,495,000 per
        Note 3 to the Trust's 2006 consolidated financial statements.

    (2) GLJ estimated change in future development capital required to
        recover reserves.
    (3) Based on company interest discovered reserves and extensions, net of
        revisions and before deduction of royalties.


    Land Holdings
    -------------

    Sound has an extensive land base that includes an inventory of 445,000 net
undeveloped acres; this asset will provide the Trust with years of
exploitation and development opportunities. As at December 31, 2006, the Trust
had an assessment of fair value of non-reserve oil and gas properties prepared
by Seaton-Jordan & Associates Ltd. ("Seaton-Jordan"), a Calgary-based
independent firm of land evaluators, according to which Sound's land value
totals $40.8 million:

                    Developed acres    Undeveloped acres       Total acres

                     Gross       Net     Gross       Net     Gross       Net
    -------------------------------------------------------------------------
    Alberta        384,876   231,302   424,515   299,655   809,391   530,957
    Saskatchewan    19,505    14,594   161,955   144,942   181,460   159,536
    -------------------------------------------------------------------------
    Total          404,381   245,895   586,470   444,597   990,851   690,493
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Seaton-Jordan determines fair value based on i) acquisition cost, provided
that there have been no material changes in the unproved property, the
surrounding properties, or the general oil and gas climate since the
acquisition; ii) recent sales by others of interests in the same unproved
property; iii) terms and conditions, expressed in monetary terms, of recent
farm-in agreements; iv) terms and conditions, expressed in monetary terms, of
recent work commitments related to the unproved property; and v) recent sales
of similar properties in the same general area. This approach complies with
the Securities Commission Standards of Disclosure as described in NI51-101.

    ADVISORY: Certain information regarding Sound Energy Trust including
management's assessment of future plans and operations, may constitute
forward-looking statements under applicable securities law and necessarily
involve risks associated with oil and gas exploration, production, marketing
and transportation. These statements relate to future events or the Trust's
future performance. All statements other than statements of historical fact
may be forward-looking statements. Forward-looking statements are often, but
not always, identified by the use of words such as "seek", "anticipate",
"budget", "plan", "continue", "estimate", "expect", "forecast", "may",
"project", "predict", "potential", "targeting", "intend", "could", "might",
"should", "believe" and similar expressions. These statements involve known
and unknown risks, uncertainties and other factors that may cause actual
results or events to differ materially from those anticipated in such
forward-looking statements. We believe the expectations reflected in those
forward-looking statements are reasonable but no assurance can be given that
these expectations will prove to be correct and such forward-looking
statements included in, or incorporated by reference into, this report should
not be unduly relied upon.

    In particular, this news release, and the documents incorporated by
reference, contain forward-looking statements pertaining to the following:
    -  the performance characteristics of our oil and natural gas properties;
    -  oil and natural gas production levels;
    -  the size of the oil and natural gas reserves;
    -  projections of market prices and costs;
    -  supply and demand for oil and natural gas;
    -  expectations regarding the ability to raise capital and to continually
       add to reserves through acquisitions and development;
    -  treatment under governmental regulatory regimes and tax laws; and
    -  capital expenditure programs.

    The actual results could differ materially from those anticipated in these
forward-looking statements as a result of the risk factors set forth below and
elsewhere in this news release:
    -  volatility in market prices for oil and natural gas;
    -  liabilities inherent in oil and natural gas operations;
    -  uncertainties associated with estimating oil and natural gas reserves;
    -  competition for, among other things, capital, acquisitions of
       reserves, undeveloped lands and skilled personnel;
    -  incorrect assessments of the value of acquisitions;
    -  geological, technical, drilling and processing problems; and
    -  changes in income tax laws or changes in tax laws and incentive
       programs relating to the oil and gas industry and income trusts.
    

    Additional information on these and other factors that could affect
Sound's operations or financial results are included in Sound's reports on
file with Canadian securities regulating authorities and may be accessed
through the SEDAR website (www.sedar.com), Sound's website
(www.soundenergytrust.com) or by contacting Sound.
    Statements relating to "reserves" or "resources" are deemed to be
forward-looking statements, as they involve the implied assessment, based on
certain estimates and assumptions, that the resources and reserves described
can be profitably produced in the future. Readers are cautioned that the
foregoing lists of factors are not exhaustive. The forward looking statements
contained in this report and the documents incorporated by reference herein
are expressly qualified by this cautionary statement. Furthermore, the
forward-looking statements contained in this report are made as of the date of
this report, and Sound 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 expressly required
by securities law. We do not undertake any obligation to publicly update or
revise any forward-looking statements.

    CAUTIONARY: Boe is derived by converting natural gas to oil at the ratio
of six thousand cubic feet ("Mcf") of gas to one barrel ("bbl") of oil. Boe
may be misleading, particularly if used in isolation. A boe conversion ratio
of 1 bbl: 6 Mcf is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value equivalency at the
well head.


    Management's Discussion and Analysis ("MD&A")

    The following discussion and analysis of financial and operating results
includes information to March 9, 2007 and should be read in conjunction with
the audited consolidated financial statements of Sound Energy Trust ("Sound"
or the "Trust") for the year ended December 31, 2006. The Trust is an open-end
unincorporated investment trust created under the laws of Alberta pursuant to
a trust indenture dated November 12, 2003. The consolidated financial
statements for Sound at December 31, 2006 include the Sound accounts and its
directly or indirectly wholly-owned subsidiaries, trust and partnership. The
former NAV Energy trust ("NAV") was renamed Sound Energy Trust pursuant to the
Plan of Arrangement effective August 14, 2006 as a result of the merger
between Navigo Energy Inc. ("Navigo") and Clear Energy Inc. ("Clear Energy").
This merger has been accounted for as an acquisition of Clear with prior
periods reflecting the financial positions and operational results of NAV. As
a result of the Plan of Arrangement, a new junior oil and gas company, known
as Sure Energy Inc. ("Sure Energy") was created. The Trust disposed of certain
oil and gas properties to Sure Energy as part of the Plan of Arrangement.
Sound has no interest in Sure Energy.

    Basis of Presentation - The financial data presented below have been
prepared in accordance with Canadian generally accepted accounting principles
("GAAP"). The reporting and the measurement currency is the Canadian dollar.
For the purpose of calculating unit costs, natural gas is converted to a
barrel of oil equivalent ("boe") using six thousand cubic feet ("Mcf") of
natural gas equal to one barrel of oil ("bbl") unless otherwise stated. Boe
may be misleading, particularly if used in isolation. A boe conversion ratio
of 1 bbl: 6 Mcf is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value equivalency at the
wellhead.

    Non-GAAP Measurements - Within this MD&A, references are made to terms
commonly used in the oil and gas industry. Management uses funds flow from
operations (cash flow from operating activities before changes in non-cash
working capital and asset retirement obligations settled) to analyze operating
performance and leverage and to provide investors with information on
potential cash distributions. Funds flow from operations as presented does not
have any standardized meaning prescribed by Canadian GAAP and therefore may
not be comparable with the calculation of similar measures for other entities.
Funds flow from operations as presented is not intended to represent operating
activities, net earnings or other measures of financial performance calculated
in accordance with Canadian GAAP. Netbacks equal total revenue less royalties
and operating costs calculated on a boe basis. Total boe is calculated by
multiplying the daily production by the number of days in the period. Payout
ratio equals distributions declared, divided by funds flow from operations.
Net debt equals bank debt plus working capital. Management uses these terms to
analyze operating performance and leverage.

    Overview

    The year 2006 was highlighted by the conversion of NAV to Sound through
the acquisition of Clear Energy (the "Clear Acquisition"). The Clear
Acquisition was completed to ensure the Trust's ability to provide a
sustainable distribution to its Unitholders for the long term as the resulting
increase in market capitalization improved its access to capital. In addition,
the diversification of the existing asset base was crucial to improve the
existing project inventory with higher-impact plays, increase the Trust's
exposure to longer-life resource plays and reduce the proportion of the
winter-access properties in Northern Alberta.
    On October 31, 2006, the Government of Canada announced proposed new tax
legislation for income trusts creating uncertainty over the trust sector and
eroding market capitalization at the same time. Until the rules are supported
with legislation, Sound will continue to face challenges with access to
capital and valuation of its unit price. The Trust remains focused on
improving net asset value per unit. In February 2007, management announced a
reduction of the monthly cash distribution per unit, reducing the payout ratio
to approximately 50 percent. This measure will allow for prudent reinvestment
of cash flow from operations with the objective of continuous development and
expansion of the Trust's reserves and production base. This strategy is
necessary to improve production base stability, extend Sound's reserve life
and ensure sustainable cash distributions to Unitholders.
    The fourth quarter of 2006 was the first complete quarter with the
inclusion of production and cash flow from the Clear Acquisition. Production
and cash flow from the Clear Energy assets have been included from the
effective date of the acquisition of August 14, 2006, which resulted in a
17 percent production increase in the fourth quarter over the prior quarter.
Current production amounts are approximately 10,100 boe/d. The improved
financial position and increased size of operations are complemented with a
land position of approximately 445,000 net acres of undeveloped land,
providing a significant prospect inventory for future growth.
    The growth in production and cash flow for the quarter was dampened by a
significant drop in crude oil prices and little recovery in natural gas prices
compared with the prior quarter. The combination of lower-than-expected cash
flow as a result of lower commodity prices and increased distributions in
conjunction with the higher number of units outstanding has created a
higher-than-expected payout ratio of 90 percent. The Trust will remain prudent
in managing capital expenditures within cash flow over the winter months while
monitoring volatile natural gas prices.

    
    Production

                           Three months ended             Years ended
                              December 31                 December 31

                         2006     2005  % Change     2006     2005  % Change
    -------------------------------------------------------------------------
    Crude oil &
     NGLs (bbl/d)       4,295    4,118         4    4,005    4,177        (4)
    Natural
     gas (Mcf/d)       37,446   21,835        71   27,360   21,351        28
    -------------------------------------------------------------------------
    Oil equivalent
     (boe/d)           10,536    7,757        36    8,565    7,736        11
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Combined average production volumes increased 36 percent to 10,536 boe/d
for the three months ended December 31, 2006 from 7,757 boe/d for the same
period in 2005. The increase in production is mainly due to the inclusion, for
the first complete quarter, of the Clear Acquisition, which also changed the
product mix to a 59-percent natural gas weighting. For the year ended
December 31, 2006, combined average production increased to 8,565 boe/d from
7,736 boe/d in 2005.

    Selected Financial Information

                                              2006                2005
    Years ended December 31
    -------------------------------------------------------------------------
                                         $000s     $/boe     $000s     $/boe
    -------------------------------------------------------------------------
    Production revenue before hedging  157,023     50.23   161,006     57.02
    Hedging gain (loss)                  1,849      0.59    (2,686)    (0.95)
    -------------------------------------------------------------------------
    Production revenue after hedging   158,872     50.82   158,320     56.07
    Royalties, net of ARTC             (28,673)    (9.17)  (32,925)   (11.66)
    Production                         (38,897)   (12.44)  (30,010)   (10.63)
    Transportation                      (5,627)    (1.80)   (4,979)    (1.76)
    -------------------------------------------------------------------------
    Net operating income                85,675     27.41    90,406     32.02
    Payout settlement                        -         -    (2,400)    (0.85)
    Cash G&A(1)                         (9,763)    (3.12)   (6,435)    (2.28)
    Interest on convertible debentures  (5,573)    (1.78)   (5,210)    (1.85)
    Interest on bank debt               (5,209)    (1.67)   (2,153)    (0.76)
    Capital taxes                       (1,129)    (0.37)   (1,409)    (0.50)
    -------------------------------------------------------------------------
    Funds flow from operations          64,001     20.47    72,799     25.78
    Unit-based compensation(1)          (3,750)    (1.20)   (1,782)    (0.63)
    Non-cash G&A(1)                          -         -      (552)    (0.20)
    Unrealized derivatives gain          1,522      0.49         -         -
    Accretion of asset retirement
     obligation                         (2,171)    (0.69)   (1,440)    (0.50)
    Depletion, depreciation and
     amortization                      (69,203)   (22.14)  (52,023)   (18.42)
    Future income tax recovery          16,238      5.19     1,483      0.52
    -------------------------------------------------------------------------
                                         6,637      2.12    18,485      6.55
    Non-controlling interest              (116)    (0.03)     (278)    (0.10)
    -------------------------------------------------------------------------
    Net income                           6,521      2.09    18,207      6.45
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Cash flow from operations           59,037     18.88    73,222     25.93
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Included in general & administrative expenses ("G&A") in the
        Statement of Operations.


    Reconciliation of Funds Flow from Operations to Cash Flow from Operations

                                              2006                2005
    Years ended December 31
    -------------------------------------------------------------------------
                                         $000s     $/boe     $000s     $/boe
    -------------------------------------------------------------------------
    Cash flow from operations           59,037     18.88    73,222     25.93

    Asset retirement
     obligations settled                 1,519      0.49       840      0.30
    Change in non-cash operating
     working capital                     3,445      1.10    (1,263)    (0.45)
    -------------------------------------------------------------------------
    Funds flow from operations          64,001     20.47    72,799     25.78
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



                                              2006                2005
    Three months ended December 31
    -------------------------------------------------------------------------
                                         $000s     $/boe     $000s     $/boe
    -------------------------------------------------------------------------
    Production revenue before hedging   44,779     46.20    45,937     64.37
    Hedging gain (loss)                  1,745      1.80      (877)    (1.23)
    -------------------------------------------------------------------------
    Production revenue after hedging    46,524     48.00    45,060     63.14
    Royalties, net of ARTC              (7,343)    (7.58)   (9,343)   (13.09)
    Production                         (11,553)   (11.91)   (8,256)   (11.57)
    Transportation                      (1,441)    (1.49)   (1,245)    (1.74)
    -------------------------------------------------------------------------
    Net operating income                26,187     27.02    26,216     36.74
    Cash G&A(1)                         (3,613)    (3.72)   (2,848)    (4.00)
    Interest on convertible debentures  (1,655)    (1.71)   (1,292)    (1.81)
    Interest on bank debt               (1,763)    (1.82)     (580)    (0.81)
    Capital taxes                         (204)    (0.22)     (216)    (0.30)
    -------------------------------------------------------------------------
    Funds flow from operations          18,952     19.55    21,280     29.82
    Unit-based compensation(1)          (2,419)    (2.50)       62      0.09
    Non-cash G&A(1)                          -         -      (110)    (0.15)
    Unrealized derivative gain            (140)    (0.14)        -         -
    Accretion of asset retirement
     obligation                           (944)    (0.97)     (370)    (0.52)
    Depletion, depreciation
     and amortization                  (23,680)   (24.43)  (13,979)   (19.59)
    Future income tax recovery          11,734     12.10       524      0.73
    -------------------------------------------------------------------------
                                        3,503       3.61     7,407     10.38
    Non-controlling interest             (100)     (0.10)     (123)    (0.17)
    -------------------------------------------------------------------------
    Net income                          3,403       3.51     7,284     10.21
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Cash flow from operations          13,558      13.99    22,787     31.93
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Included in G&A in the Statement of Operations.


    Reconciliation of Funds Flow from Operations to Cash Flow from Operations

                                              2006                2005
    Three months ended December 31
    -------------------------------------------------------------------------
                                         $000s     $/boe     $000s     $/boe
    -------------------------------------------------------------------------
    Cash flow from operations           13,558     13.99    22,787     31.93
    Asset retirement
     obligations settled                   708      0.73       391      0.55
    Change in non-cash
     operating working capital           4,686      4.83    (1,898)    (2.66)
    -------------------------------------------------------------------------
    Funds flow from operations          18,952     19.55    21,280     29.82
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Production Revenue

    Production revenue before hedging decreased three percent to $44.8 million
for the three months ended December 31, 2006 from $45.9 million for the three
months ended December 31, 2005. The slight drop in revenues occurred despite
higher production volumes as a result of the sharp decline in natural gas
prices. Hedging gains of $1.7 million in the fourth quarter of 2006 somewhat
reduced the effects of declining commodity prices. In the prior-year reporting
period, the Trust recorded hedging losses of $0.9 million.
    Production revenue before hedging decreased two percent to $157.0 million
for the year ended December 31, 2006, from $161.0 million in 2005, mainly as a
result of lower commodity prices year-over-year. For the year ended
December 31, 2006, hedging gains of $1.8 million were realized, while for
2005, the Trust recorded hedging losses of $2.7 million.

    Crude Oil and Natural Gas Prices

                                  Three months ended         Years ended
                                     December 31             December 31
                                                 %                       %
                                2006    2005  Change    2006    2005  Change
    -------------------------------------------------------------------------
    WTI average - US$/bbl      59.43   60.04      (1)  66.04   56.61      17
    US$/Cdn$ exchange
     rate average               0.88    0.85       4    0.88    0.83       6
    Edmonton par price
     average - $/bbl           64.63   71.18      (9)  72.94   68.77       6
    AECO - C price - $/Mcf      7.54   11.45     (34)   6.74    8.78     (23)
    Company crude oil price
     received - $/bbl
     before hedging            51.77   60.30     (14)  61.94   60.24       3
    Company natural gas price
     received - $/Mcf
     before hedging             7.13   11.48     (38)   6.69    8.95     (25)
    Company price
     received - $/boe
     before hedging            46.20   64.37     (28)  50.23   57.02     (12)
    Company price
     received - $/boe
     after hedging             48.00   63.14     (24)  50.82   56.07      (9)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    The benchmark West Texas Intermediate ("WTI") price per barrel of crude
and thus the average oil price received by the Trust in the fourth quarter of
2006 compared with that of 2005 decreased slightly. The WTI price average of
US$59.43/bbl in the fourth quarter of 2006 was lower by US$0.61/bbl or one
percent than in the fourth quarter of 2005. This decrease was magnified by a
three-cent increase in the average US$/Cdn$ exchange rate in the fourth
quarter of 2006 over the fourth quarter of 2005 that resulted in the Edmonton
par price declining by nine percent in the fourth quarter of 2006 over the
prior-year period. Overall, the Trust saw a decrease of $8.53/bbl or 14
percent year-over-year in the average oil price received. The AECO index price
for natural gas fell 34 percent in the fourth quarter of 2006 compared with
the fourth quarter of 2005, resulting in a 38-percent decrease in the STET
average natural gas price received by the Trust. After accounting for hedging,
prices per boe received dropped 24 percent in the fourth quarter of 2006 over
the prior-year period.
    The price for WTI crude averaged US$66.04/bbl in the year ended
December 31, 2006, an increase of US$9.43/bbl or 17 percent over the year
ended December 31, 2005. This lift in the average oil price for the year was
offset by a five-cent increase in the average US$/Cdn$ exchange rate for 2006.
The Edmonton par price rose six percent in 2006 over 2005. These changes
resulted in an overall year-over-year increase of $1.70/bbl or three percent
in the average oil price received by the Trust before hedging. The average
natural gas prices received by the Trust decreased by 25 percent or $2.26/Mcf
for 2006 as compared to 2005. After accounting for hedging, prices per boe
received were lower by nine percent in 2006 compared with 2005.

    Royalties

    Royalties in the fourth quarter of 2006 amounted to $7.3 million or
16.4 percent of production revenue before hedging, compared with $9.3 million
or 20.3 percent of production revenue before hedging in the fourth quarter of
2005. Due to royalty recoveries, royalties for the fourth quarter of 2006 were
lower than anticipated. Going forward, royalties are expected to be 20 to
22 percent of gross production revenue.
    Royalties for the year ended December 31, 2006 were $28.7 million or
18.3 percent of production revenue before hedging, compared with $32.9 million
or 20.4 percent of production revenue before hedging in the prior-year period.
For 2006, royalties were lower than anticipated due to gas cost allowance
adjustments that created a lower effective royalty rate for natural gas.

    
                                                    % of                % of
                                              Production          Production
    Three months ended                           revenue             revenue
     December 31                        2006      before    2005      before
                                      ($000s)    hedging  ($000s)    hedging
    -------------------------------------------------------------------------
    Crown royalties & mineral taxes    5,534        12.3   6,069        13.2
    ARTC                                 (58)       (0.1)   (125)       (0.3)
    -------------------------------------------------------------------------
    Net Crown royalties                5,476        12.2   5,944        12.9
    Freehold & overriding royalties    1,115         2.5   2,930         6.4
    First Nations royalties              752         1.7     469         1.0
    -------------------------------------------------------------------------
    Total royalties                    7,343        16.4   9,343        20.3
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

                                                    % of                % of
                                              Production          Production
    Years ended                                  revenue             revenue
     December 31                        2006      before    2005      before
                                      ($000s)    hedging  ($000s)    hedging
    -------------------------------------------------------------------------
    Crown royalties & mineral taxes   20,113        12.8  21,577        13.4
    ARTC                                (427)       (0.3)   (496)       (0.3)
    -------------------------------------------------------------------------
    Net Crown royalties               19,686        12.5  21,081        13.1
    Freehold & overriding royalties    6,633         4.3   8,493         5.2
    First Nations royalties            2,354         1.5   3,351         2.1
    -------------------------------------------------------------------------
    Total royalties                   28,673        18.3  32,925        20.4
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    


    Production Expenses

    Production expenses in the fourth quarter of 2006 grew to $11.6 million
from $8.3 million in the fourth quarter of 2005, averaging $11.91/boe and
$11.57/boe, respectively, and increasing by three percent year-over-year on a
boe basis. Higher costs for the quarter are mainly the result of workovers and
plant turnarounds.
    For the year ended December 31, 2006, production expenses increased to
$38.9 million from $30.0 million in the prior year. Production expenses in
2006 averaged $12.44/boe, a 17 percent increase from the $10.63/boe recorded
in 2005. A combination of higher service costs and outages in 2006 contributed
to this overall increase.

    
    Operating Netbacks

    Three months
     ended
     December 31                          2006                          2005
                   ----------------------------------------------------------
                    Light  Medium   Heavy         Natural
                      oil     oil     oil    NGLs     gas  Combined  Combined
                   ($/bbl) ($/bbl) ($/bbl) ($/bbl) ($/Mcf)   ($/boe)  ($/boe)
    -------------------------------------------------------------------------

    Production
     revenue
     before
     hedging        53.72   48.97   51.11   46.87    7.13     46.20    64.37
    Hedging          8.44       -       -       -    0.09      1.80    (1.23)
    -------------------------------------------------------------------------
                    62.16   48.97   51.11   46.87    7.22     48.00    63.14

    Royalties      (12.75)  (9.68)  (9.49) (11.82)  (0.86)    (7.58)  (13.09)
    Production
     expenses      (12.26) (13.60) (19.37)      -   (1.81)   (11.91)  (11.57)
    Transportation  (0.41)  (2.08)  (5.29)      -   (0.17)    (1.49)   (1.74)
    -------------------------------------------------------------------------

    Operating
     netback,
     after
     hedging        36.74   23.61   16.96   35.05    4.38     27.02    36.74
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Royalty as
     percent of
     production
     revenue
     before
     hedging          24%     20%     19%     25%     12%       16%      20%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    Years
     ended
     December 31                          2006                          2005
                   ----------------------------------------------------------
                    Light  Medium   Heavy         Natural
                      oil     oil     oil    NGLs     gas  Combined  Combined
                   ($/bbl) ($/bbl) ($/bbl) ($/bbl) ($/Mcf)   ($/boe)  ($/boe)
    -------------------------------------------------------------------------

    Production
     revenue
     before
     hedging        67.73   57.69   51.31   56.98    6.69     50.23    57.02
    Hedging          2.05       -       -       -    0.03      0.59    (0.95)
    -------------------------------------------------------------------------
                    69.78   57.69   51.31   56.98    6.72     50.82    56.07

    Royalties      (14.14) (14.38)  (8.39) (12.26)  (0.95)    (9.17)  (11.66)
    Production
     expenses      (16.45) (11.78) (13.39)      -   (1.88)   (12.44)  (10.63)
    Transportation  (2.21)  (2.28)  (4.86)      -   (0.19)    (1.80)   (1.76)
    -------------------------------------------------------------------------

    Operating
     netback,
     after
     hedging        36.98   29.25   24.67   44.72    3.70     27.41    32.02
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Royalty as
     percent of
     production
     revenue
     before
     hedging          21%     25%     16%     22%     14%       18%      20%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    General and Administrative


    $000s
    except per           Three months ended               Years ended
     boe amounts            December 31                   December 31
                  -----------------------------------------------------------
                            Per            Per            Per            Per
                    2006    boe    2005    boe    2006    boe    2005    boe
    -------------------------------------------------------------------------
    Gross G&A      8,621   8.89   5,072   7.11  21,215   6.79  14,822   5.25
    Overhead
     recoveries     (817) (0.84)   (660) (0.92) (2,812) (0.90) (2,148) (0.76)
    Capitalized
     G&A          (1,772) (1.83) (1,516) (2.13) (4,890) (1.57) (3,905) (1.38)
    -------------------------------------------------------------------------
    Net G&A        6,032   6.22   2,896   4.06  13,513   4.32   8,769   3.11
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    G&A expense for the fourth quarter of 2006 was $6.0 million or $6.22/boe,
increasing 108 percent from $2.9 million or $4.06/boe in the corresponding
quarter of 2005. This increase was mainly caused by the $2.4 million of
unit-based compensation related to the Unit Award Incentive Plan. Excluding
unit-based compensation, G&A expenses were $3.6 million or $3.72/boe and $7.6
million or $2.44/boe for the three months and year ended December 31, 2006,
respectively.
    G&A expense for the year ended December 31, 2006 was $13.5 million or
$4.32/boe, a 54 percent increase from $8.8 million or $3.11/boe for the year
ended December 31, 2005.
    As of December 31, 2006, the Trust recognizes compensation expense on a
go-forward basis related to the Unit Award Incentive Plan approved as part of
the Plan of Arrangement on August 14, 2006. The Trust will no longer record
unit-based compensation expense related to the Trust Units Rights Plan and
Long-Term Incentive Plan as these costs were previously fully recognized.
    As of December 31, 2006, no performance trust units ("PTUs") have been
granted. Based upon the number of restricted trust units ("RTUs") outstanding
at December 31, 2006 and limited by the Unit Award Incentive Plan, the maximum
number of PTUs that may be granted at a future date is 600,000. Had the
maximum PTUs under the Unit Award Incentive Plan been granted and immediately
vested at December 31, 2006, the Trust, using the December 31, 2006 closing
price of $5.11/unit, would have recorded additional compensation expenses of
$3.1 million.

    Interest on Convertible Debentures

    Interest on the 8.0% and the 8.75% Convertible Debentures was
$1.7 million for the three months ended December 31, 2006 as compared to
$1.3 million for the same period in 2005, and $5.6 million for the year ended
December 31, 2006 as compared to $5.2 million for 2005. The increase was due
to the issue of the $41.0 million of 8.0% Convertible Debentures in November
2006.

    Interest on Bank Debt

    Interest expense for the fourth quarter of 2006 was $1.8 million, an
increase of 204 percent over the $0.6 million recorded in the fourth quarter
of 2005. Average bank debt balances were approximately $74.1 million higher
during the three months ended December 31, 2006 than during the prior-year
period. Net proceeds from the 8.0% Convertible Debentures, which closed on
November 21, 2006, were used to repay outstanding bank debt, fund the Trust's
capital expenditure program and for general Trust purposes. The effective
interest rate on bank debt balances was approximately 6.0 percent during the
fourth quarter of 2006, compared with approximately 5.3 percent during the
fourth quarter of 2005. The increase in interest expense for the fourth
quarter of 2006 is mainly due to the average bankers' acceptance balance for
the period increasing by $51.3 million to approximately $87.3 million compared
with $36.0 million in the same period in 2005.
    Interest expense increased 142 percent to $5.2 million in the year ended
December 31, 2006, compared with $2.2 million in 2005. Debt balances averaged
approximately $43.7 million more for 2006 than in 2005. The effective interest
rate on bank debt balances was approximately 5.9 percent for 2006 as compared
to approximately 4.8 percent for 2005.

    Depletion, Depreciation and Amortization ("DD&A")

    DD&A in the fourth quarter of 2006 increased 69 percent to $23.7 million
or $24.43/boe from $14.0 million or $19.59/boe in the fourth quarter of 2005.
For the year ended December 31, 2006, DD&A grew 33 percent to $69.2 million or
$22.14/boe over the $52.0 million or $18.42/boe recorded in 2005. This rise in
DD&A for both the three months and year ended December 31, 2006 is mainly a
result of a higher capital asset base in the current period due to the Clear
Acquisition that closed in the third quarter.

    Taxes

    Capital taxes for both the fourth quarter of 2006 and 2005 amounted to
$0.2 million; the 2005 number includes both Large Corporations Tax and the
Saskatchewan surcharge, whereas only the latter was applicable in 2006. For
2006, capital taxes were $1.1 million as compared to $1.4 million for 2005.
The year-over-year decrease is mainly due to the elimination of the Large
Corporations Tax in 2006.
    As at December 31, 2006, the Trust and its affiliated subsidiaries have
$431.6 million of tax pools available to reduce taxable income for future
periods. Based upon the proposed legislation, the Trust's distributable income
will not be taxed until 2011.

    
    Year ended December 31
    $000s                                                               2006
    -------------------------------------------------------------------------
    Canadian exploration expenditures                                 30,285
    Canadian development expenditures                                 78,776
    Canadian oil and gas property expense                            154,451
    Undepreciated capital cost                                       136,823
    Non capital losses                                                19,990
    Other                                                             11,300
    -------------------------------------------------------------------------
    Total tax pools                                                  431,625
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    A future income tax recovery of $11.7 million was recorded in the three
months ended December 31, 2006, with $0.5 million reported for the prior-year
period. For the year ended December 31, 2006, a future income tax recovery of
$16.2 million was recorded, compared with $1.5 million for the year ended
December 31, 2005.
    On October 31, 2006, the federal government announced its intentions to
change the tax treatment for income trusts, introducing a tax on publicly
traded income trusts and altering the personal tax treatment of trust
distributions. The proposals were tabled through a Ways and Means Motion
passed in the House of Commons on November 7, 2006 as the first step in the
parliamentary review process.
    Under the proposals effectively all distributions other than those
comprising a return of capital to Unitholders would be subject to a
31.5 percent tax at the trust level as all distributions would no longer be
deductible in computing trust taxable income. The personal tax on
distributions would be reduced to a level similar to the tax paid on a
dividend received from a taxable Canadian corporation. The proposals would
effectively reduce income being distributed to Sound's Unitholders, with the
end result being a two-tiered tax structure similar to that of corporations.
At present, Canadian Pension Funds, Registered Retirement Savings Plans and
Registered Retirement Income Funds ("Canadian Tax Deferral Entities") are not
subject to tax on distributions. Under the proposals, Canadian Tax Deferral
Entities would be subject to tax as a result of the tax imposed at the trust
level. The proposals would also significantly increase the tax for
non-resident Unitholders due to the tax imposed at the trust level. If
enacted, the proposals would apply to Sound effective January 1, 2011. As the
proposals are not yet enacted or considered substantively enacted, no
adjustment to the future income tax liability has been recorded.

    
    Quarterly Information

    Year ended December 31                               2006

                                              4th      3rd      2nd      1st
                                          Quarter  Quarter  Quarter  Quarter
    -------------------------------------------------------------------------
    Production revenue before hedging
    ($000s, except per unit amounts)       44,779   41,093   36,394   34,757

    Funds flow from operations             18,952   15,541   15,206   14,302
      Per unit - basic                       0.33     0.35     0.53     0.58
      Per unit - diluted                     0.30     0.34     0.52     0.49
    Net income (loss)                       3,403     (575)   3,000      693
      Per unit - basic                       0.06    (0.01)    0.11     0.02
      Per unit - diluted                     0.06    (0.01)    0.10     0.02
    Total assets                          648,822  663,502  347,930  352,639
    -------------------------------------------------------------------------
    Capital expenditures                   11,040    5,179    7,498   31,958
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Production
      Crude oil (bbl/d)                     2,857    3,083    3,124    3,261
      Heavy oil (bbl/d)                     1,118      667      504      504
      Natural gas (Mcf/d)                  37,446   30,326   21,890   19,549
      NGLs (bbl/d)                            320      206      185      187
    -------------------------------------------------------------------------
      Combined (boe/d)                     10,536    9,010    7,461    7,210
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Average selling price
      Crude oil ($/bbl)                     52.03    72.37    71.25    61.00
      Heavy oil ($/bbl)                     51.11    55.57    59.31    37.92
      Natural gas ($/Mcf)                    7.13     5.70     6.09     8.07
      NGLs ($/bbl)                          46.87    65.63    65.26    56.90
    -------------------------------------------------------------------------
      Combined ($/boe)                      46.20    49.57    53.61    53.56
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    Year ended December 31                               2005

                                              4th      3rd      2nd      1st
                                          Quarter  Quarter  Quarter  Quarter
    -------------------------------------------------------------------------
    Production revenue before hedging
    ($000s, except per unit amounts)       45,937   45,865   36,650   32,554

    Funds flow from operations             21,280   20,501   16,842   14,176
      Per unit - basic                       0.75     0.73     0.60     0.51
      Per unit - diluted                     0.74     0.71     0.59     0.50
    Net income                              7,284    6,585    3,425      913
      Per unit - basic                       0.26     0.23     0.12     0.03
      Per unit - diluted                     0.25     0.23     0.12     0.03
    Total assets                          332,305  327,177  323,993  332,194
    Capital expenditures                   18,414    9,989    6,304   17,286
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Production
      Crude oil (bbl/d)                     3,356    3,507    3,540    3,175
      Heavy oil (bbl/d)                       508      497      499      458
      Natural gas (Mcf/d)                  21,835   22,252   20,591   20,704
      NGLs (bbl/d)                            254      284      277      351
    -------------------------------------------------------------------------
      Combined (boe/d)                      7,757    7,996    7,748    7,435
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Average selling price
      Crude oil ($/bbl)                     62.10    71.67    60.04    57.19
      Heavy oil ($/bbl)                     40.46    52.95    38.12    36.36
      Natural gas ($/Mcf)                   11.48     9.21     7.66     7.24
      NGLs ($/bbl)                          58.10    56.07    48.46    38.69
    -------------------------------------------------------------------------
      Combined ($/boe)                      64.39    62.36    51.98    48.65
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Funds Flow from Operations and Net Income

    In the fourth quarter of 2006, the Trust recorded funds flow from
operations of $19.0 million or $0.33/unit as compared to $21.3 million or
$0.75/unit in the fourth quarter of 2005. Production revenue after hedging
increased for the fourth quarter of 2006, while the per-boe price received
decreased. In addition, production expenses were $3.3 million higher for the
same period in 2006 over 2005, resulting in the lower funds flow from
operations for the reporting period. For the fourth quarter of 2006, the Trust
recorded net income of $3.4 million or $0.06/unit, which included an income
tax recovery of $11.7 million. This compares with net income of $7.3 million
or $0.26/unit in the same period of 2005.
    For the year ended December 31, 2006, the Trust recorded funds flow from
operations of $64.0 million or $1.62/unit as compared to $72.8 million or
$2.59/unit for the year ended December 31, 2005. For the year ended
December 31, 2006, the Trust's net income was $6.5 million or $0.17/unit,
compared with $18.2 million or $0.65/unit in the prior-year period.

    
    Capital Expenditures

                                        Three months ended     Years ended
                                             December 31       December 31

    ($000s)                                  2006     2005     2006     2005
    -------------------------------------------------------------------------
    Land and lease                            796      299    2,131    2,064
    Geological and geophysical                 85       13      188      407
    Drilling and completions                4,544    9,013   24,843   28,006
    Equipment and facilities                3,600    8,143   22,512   17,753
    Overhead and office equipment           2,015      946    6,001    3,763
    -------------------------------------------------------------------------
    Total exploration and development      11,040   18,414   55,675   51,993

    Transaction costs                           -        -    4,950        -
    Property acquisitions                     291      291    1,517      467
    Property dispositions                      36        -        -      (67)
    -------------------------------------------------------------------------
    Total capital expenditures             11,367   18,705   62,142   52,393
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Exploration and development expenditures excluding acquisitions increased
seven percent from $52.0 million in 2005 to $55.7 million in 2006. The capital
program for 2006 was heavily weighted to first-quarter drilling activity.
Exploration and development in 2006 took place in all four main producing
regions created since the acquisition of Clear Energy: Northern Alberta, Peace
River Arch, Central Alberta and Saskatchewan. In Northern Alberta, the Trust
invested $23.5 million, drilling a total of 25 wells, with a focus on Keg
River oil pools and Bluesky/Gething natural gas reservoirs. The Peace River
Arch is a region that was added to the Trust's portfolio through the Clear
Acquisition. In this area, $3.2 million was spent on facility expansion and
the drilling of one oil well in the Clear River Area. In Central Alberta, the
Trust invested $21.9 million, drilling a total of 29 natural gas wells. In
this area, the main focus was on a mixture of longer-life and
higher-deliverability natural gas and the initiation of a substantial coalbed
methane ("CBM") project. The Saskatchewan region is primarily a medium to
heavy-gravity oil area for the Trust, where Sound invested $7.1 million in
2006, drilling 14 wells as part of a continuous development/infill program and
initiating a staged waterflood program at Wapella.

    Liquidity and Capital Resources

    The Trust's capital expenditures of $62.1 million; distributions totaling
$45.4 million; settlement of asset retirement obligations of $1.5 million in
2006, were funded by $64.0 million in funds flow from operations; the addition
of convertible debentures in the amount of $39.3 million; an increase of
$9.1 million in bank debt; and $5.3 million in proceeds from the issuance of
trust units and rights. The Clear Acquisition included the assumption of
$46.2 million of bank debt.
    The Trust's capital expenditures of $52.4 million; distributions totaling
$40.7 million; settlement of asset retirement obligations of $0.8 million in
2005, were funded by $72.8 million in funds flow from operations; the increase
of $17.0 million in bank debt, and $1.9 million in proceeds from the issuance
of trust units and rights.


    
    Distributable cash

    Years ended December 31                                 2006        2005
    -------------------------------------------------------------------------
      Funds flow from operations                          64,001      72,799
      Asset retirement obligations                        (1,519)       (840)
      Change in non-cash operating working capital        (3,445)      1,263
    -------------------------------------------------------------------------
      Cash flow from operations                           59,037      73,222
    -------------------------------------------------------------------------
      Cash distributions                                 (45,431)    (40,666)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    The above table demonstrates that the Trust had sufficient distributable
cash to fund the cash distributions for 2006 and 2005.
    The Trust had, through a syndicate of lenders, a $166.5 million revolving
term production facility, which included a $20.0 million short-term facility
that expired on December 31, 2006. At December 31, 2006, the Trust had
$102.3 million drawn down on this facility (December 31, 2005 - $47.0 million
on a facility of $90.0 million). In March of 2007, the same syndicate of
lenders reduced the Trust's credit facilities, which are subject to interim
borrowing-base reviews, to $135.0 million. The primary reduction was the
expiration of the $20.0 million short-tern facility, with the remaining
borrowing base shrinking as a result of the issuance of subordinate debt in
the fourth quarter of 2006. The subordinate debenture issue allowed Sound to
expand its overall debt capacity to $236.0 million for 2007.
    On October 25, 2006, Sound announced it had entered into an agreement
with a syndicate of underwriters to issue to the public, on a bought-deal
basis, convertible unsecured subordinated debentures for $1,000 per debenture
for gross proceeds of $55.0 million. On November 9, 2006, the Trust announced
that it and its underwriters were reconsidering the deal in light of proposed
changes to the taxation of income trusts and the ensuing impact on the capital
markets. On November 10, 2006, the Trust announced that it had entered into an
agreement with its underwriters to amend the terms of the bought-deal
financing. Under the terms of the revised agreement, a syndicate of
underwriters offered a $40.0 million principal amount of convertible unsecured
subordinated debentures. The debentures have a face value of $1,000 per
debenture, a coupon rate of eight percent, a maturity date of December 31,
2011 and will be convertible into trust units at the option of the holder at a
conversion price of $6.10 per trust unit. Sound also granted the underwriters
an over-allotment option to purchase up to an additional $6.0 million
principal amount of debentures on the same terms, exercisable in whole or in
part for a period of 30 days following closing.
    Closing of the offering occurred on November 21, 2006 with the over-
allotment option, which was partially exercised, closing on December 11, 2006.
Gross proceeds from the offering, including the additional 1,035 units issued
under the over-allotment option, totaled $41.035 million. The net proceeds of
the offering were used to reduce outstanding indebtedness of the Trust, which
may be re-drawn, applied to fund development activities, and for general Trust
purposes.
    Pursuant to various agreements with the Trust's lenders, the Trust is
restricted from making distributions to its Unitholders under such agreements
in the following circumstances: (i) after the Trustee has received notice of a
default or event of default or demand for repayment under any of the credit
facilities has occurred and is continuing or will be caused by such
distribution; (ii) outstanding loans under the facility exceed the borrowing
base set by the lenders thereunder until such time as such outstanding loans
are reduced below such borrowing base; or (iii) where distributions are in
excess of 100 percent of distributable cash as defined by funds flow from
operations less certain capital requirements of $4.2 million for 2007 in the
GLJ engineering report at December 31, 2006.
    For 2007, the Trust anticipates funding capital expenditures and cash
distributions entirely from funds flow from operations. Effective February 19,
2007, Sound announced a 45 percent reduction to its monthly cash distributions
from $0.10 per unit to $0.055 per unit in order to ensure Unitholders that the
distribution will be sustainable over future periods. The anticipated
50 percent payout ratio will allow more flexibility for more substantial
reinvestment of excess funds flow from operations into the assets with the
objective of stabilizing the production base.
    For 2007, capital expenditures are budgeted at $31.3 million. The Trust
has established the capital expenditure program based on an annual budget
review process, which includes budgeted funds flow from operations, and
closely monitors changes throughout the year. A substantial amount of the
Trust's capital spending is discretionary in nature. The Trust generally has a
high working interest and operatorship of its major properties. Therefore, the
Trust is in a position to control the timing of expenditures to match
financial resources. The Trust also engages in commodity price hedging in
order to reduce the volatility of cash flow available for its capital program.
    The Trust's growth has resulted from acquisitions, and Sound regularly
evaluates opportunities to acquire properties or oil and gas producing
companies. The Trust believes that funds generated from operations, together
with borrowings under the credit facility and proceeds from property
dispositions, will be sufficient to finance Sound's current operations and
planned capital expenditure program. Future acquisitions will be financed with
debt and/or equity financings. The Trust anticipates that annual capital
expenditures over the next few years will vary based on development
opportunities and the strength of commodity prices.

    Financial Instruments and Hedging

    The Trust has established a well-defined hedging strategy that focuses on
protection of the cash distributions and maintenance capital program. Target
hedging levels are set at approximately 50 percent of production, with target
prices to be determined according to the Trust's budgets and forecasts.
    At December 31, 2006, the Trust had the following financial instruments
outstanding to which hedge accounting has been applied:

    
                       Period              Volume      Hedged Price    Index
    -------------------------------------------------------------------------
    Oil price collar   Jan. 1, 2007 to     500 bbl/d   US$70.00/bbl to  WTI
                        Dec. 31, 2007                   US$74.30/bbl
    Gas price collar   Nov. 1, 2006 to  5,000 GJ/d(1)  $8.00/GJ to      AECO
                        Mar. 31, 2007                   $11.40/GJ(1)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) GJs convert to Mcf at a rate of 1.055056:1.
    

    At December 31, 2006, settlement of the oil price collar would have
resulted in gains of US$1.3 million and settlement of the gas price collar
would have resulted in a gain of $0.7 million.
    At December 31, 2006, the Trust had the following financial instruments
outstanding where hedge accounting has not been applied, and the
mark-to-market impact is reflected in the financial statements:

    
                          Period           Volume      Hedged Price    Index
    -------------------------------------------------------------------------
    Gas price collar   Nov. 1, 2006 to   5,000 GJ/d(1)  $8.00/GJ to     AECO
                        Mar. 31, 2007                   $9.17/GJ(1)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) GJs convert to Mcf at a rate of 1.055056:1.
    

    Through March 31, 2007, the Trust has hedged 46 percent of its net daily
production, with 36 percent of its net daily production protected from
April 1, 2007 to December 31, 2007 following the expiration of contracts put
in place in 2006. As of March 9, 2007, the Trust has the following financial
instruments outstanding:

    
                          Period           Volume      Hedged Price    Index
    -------------------------------------------------------------------------
    Oil price collar   Apr. 1, 2007 to      500 bbl/d   US$60.00/bbl to  WTI
                        Dec. 31, 2007                   US$71.50/bbl

    Oil price collar   Jan. 1, 2007 to      500 bbl/d   US$70.00/bbl to  WTI
                        Dec. 31, 2007                   US$74.30/bbl

    Oil price collar   Mar. 1, 2007 to    1,000 bbl/d   US$57.00/bbl to  WTI
                        Dec. 31, 2007                   US$70.00/bbl

    Gas price collar   Nov. 1, 2006 to   5,000 GJ/d(1)  $8.00/GJ to     AECO
                        Mar. 31, 2007                   $11.40/GJ(1)

    Gas price collar   Nov. 1, 2006 to   5,000 GJ/d(1)  $8.00/GJ to     AECO
                        Mar. 31, 2007                   $9.17/GJ(1)

    Gas price collar   Mar. 1, 2007 to  10,000 GJ/d(1)  $7.50/GJ to     AECO
                        Dec. 31, 2007                   $9.00/GJ(1)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) GJs convert to Mcf at a rate of 1.055056:1.
    


    Contractual Obligations and Contingencies

    Contractual Obligations
    The Trust has ongoing obligations related to regulatory requirements to
abandon and restore wells and facility locations in the future. At
December 31, 2006, the Trust has estimated the total undiscounted asset
retirement obligation to be $62.5 million, which will be funded from general
Trust resources at the time of settlement.

    The Trust has assumed the following commitments:

    
    $000s              Total    2007    2008    2009    2010    2011   After
    -------------------------------------------------------------------------
    Transportation
     agreements        3,165   1,895     970     300       -       -       -
    Operating leases   7,351   1,527   1,417   1,325   1,330     701   1,051
    -------------------------------------------------------------------------
                      10,516   3,422   2,387   1,625   1,330     701   1,051
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Contingencies
    The Trust is party to various outstanding claims arising from the normal
course of business. In management's opinion, none of the claims, either
individually or in total, is expected to have a material impact on the Trust's
operations or financial position.

    Related-Party Transactions

    Pursuant to agreements dated December 31, 2003, three senior executives
were entitled to receive a total of $1.5 million in retention bonuses payable
in trust units based on the market price at the time of issue, payable in 
semi-annual payments over the following two years subject to certain
conditions. During the first quarter of 2006, 29,212 trust units were issued
in settlement of the last semi-annual payment for two senior executives. All
of the third senior executive's retention bonus was settled during 2004.
    Sure Energy is a related party of Sound as three directors of Sure Energy
sit on the Board of Directors of Sound and the same director serves as
Chairman for both companies. The Trust is the operator of several properties
in which Sure is a joint venture partner. Amounts paid and to be paid by the
Trust to Sure Energy totaled $397,000 for the year ended December 31, 2006. As
at December 31, 2006, $168,000 was included in accounts payable in respect of
these amounts. Also, during 2006, Sure Energy was charged $129,000 for rent
and parking by Sound, of which $57,000 was payable at December 31, 2006.
Amounts charged by or payable by the Trust to Sure Energy are on the same
terms and conditions as charged to any other third party or third-party joint
venture partner.

    Critical Accounting Estimates

    Reserve Estimates
    Estimates of oil and natural gas reserves, by necessity, are projections
based on geologic and engineering data, and there are uncertainties inherent
to the interpretation of such data as well as the projection of future rates
of production and the timing of development expenditures. Reserve engineering
is an analytical process of estimating underground accumulations of oil and
natural gas that can be difficult to measure. The accuracy of any reserve
estimate is a function of the quality of available data, engineering and
geological interpretation and judgment. Estimates of economically recoverable
oil and natural gas reserves and future net cash flows necessarily depend upon
a number of variable factors and assumptions, such as historical production
from the area compared with production from other producing areas, the assumed
effects of regulations by governmental agencies and assumptions governing
future oil and natural gas prices, future royalties and operating costs,
development costs and workover and remedial costs, all of which may in fact
vary considerably from actual results. For these reasons, estimates of the
economically recoverable quantities of oil and natural gas attributable to any
particular group of properties, classifications of such reserves based on risk
recovery, and estimates of the future net cash flows expected therefrom may
vary substantially. Any significant variance in the assumptions could
materially affect the estimated quantity and value of the reserves, which
could affect the carrying value of the Trust's oil and natural gas properties
and the rate of depletion of the oil and natural gas properties.
    The Trust's estimated quantities of proved and probable reserves at
December 31, 2006 were evaluated by independent petroleum engineers GLJ
Petroleum Consultants Ltd. who have been evaluating the Trust's reserves for
five consecutive years.

    Full Cost Accounting
    The Trust follows the full-cost method of accounting whereby all costs
relating to the exploration for and development of petroleum and natural gas
reserves are capitalized in one Canadian cost centre and charged against
income, as set out below. Such costs include land acquisition, drilling,
geological and geophysical, production facilities and overhead expenses
related to exploration and development activities. These costs are depleted
and depreciated on a unit-of-production method, using estimated gross proved
petroleum and natural gas reserves as determined by independent engineers. For
purposes of this calculation, petroleum and natural gas reserves are converted
to a common unit of measurement on the basis of six thousand cubic feet of
natural gas equating to one barrel of oil. Costs of acquiring and evaluating
unproved properties are excluded from costs subject to depletion and
depreciation until it is determined whether proved reserves are attributable
to the properties or impairment occurs. Costs of production facilities are
depreciated on a unit-of-production basis.
    Gains or losses on sales of properties are recognized only when crediting
the proceeds to costs would result in a change of 20 percent or more in the
depletion rate.
    Oil and gas assets are evaluated in each reporting period to determine
that the costs are recoverable and do not exceed the fair value of the
properties. The costs are assessed to be recoverable if the sum of the
undiscounted cash flows expected from the production of proved reserves and
the lower of cost and market of unproved properties exceed the carrying value
of the oil and gas assets. If the carrying value of the oil and gas assets is
not assessed to be recoverable, an impairment loss is recognized to the extent
that the carrying value exceeds the sum of the discounted cash flows expected
from the production of proved and probable reserves and the lower of cost and
market of unproved properties. The cash flows are calculated using estimated
future product prices and costs and are discounted using the risk-free rate.
    By their nature, these estimates noted for depletion and depreciation,
and those related to the assessment of future cash flows used to assess
impairment, are subject to measurement uncertainty, and the impact on the
financial statements of future periods could be material.

    Goodwill
    The Trust recognizes goodwill on corporate acquisitions when the total
purchase price exceeds the fair value of net identifiable assets and
liabilities of the acquired entity. Goodwill is tested annually at year-end
for impairment or as events occur that could result in impairment. Impairment
is recognized based on the fair value of the Trust compared with the book
value of the Trust. If the fair value of the Trust is less than the book
value, impairment is measured by allocating the fair value to the identifiable
assets and liabilities as if the Trust had been acquired in a business
combination for its fair value. The excess of the fair value over the amounts
assigned to the identifiable assets and liabilities is the fair value of the
goodwill. Any excess of the book value over this implied fair value of
goodwill is the impairment amount. Impairment is charged to earnings in the
period in which it occurs. Goodwill is stated at cost less impairment and is
not amortized.

    Asset Retirement Obligation
    The asset retirement obligation is estimated based on existing laws,
contracts or other policies. The fair value of the obligation is based on
estimated future costs for abandonment and reclamation discounted at a credit
adjusted risk free rate. The liability is adjusted each reporting period to
reflect the passage of time and for revisions to the estimated future cash
flows, with the accretion charged to earnings. By their nature, these
estimates are subject to measurement uncertainty and the impact on the
financial statements could be material.

    Income Taxes
    The determination of the Trust's income and other tax liabilities
requires interpretation of complex laws and regulations often involving
multiple jurisdictions. All tax filings are subject to audit and potential
reassessment after the lapse of considerable time. Accordingly, the actual
income tax liability may differ significantly from that estimated and
recorded.

    Unit-based Compensation
    The Trust has a Unit Award Incentive Plan for directors, officers,
employees and consultants of the Trust. Under the terms of the plan, a holder
may elect, subject to consent of the Trust, to receive cash upon vesting in
lieu of the number of rights held. These rights are issued in the form of RTUs
and PTUs. Compensation expense associated with rights granted under the plan
is measured at the date of grant. The value is determined as the difference
between the market price at the grant date and the exercise price of the
rights ($Nil) and amortized over the vesting period of the rights.
    Trust unit rights related to the Trust Units Rights Incentive Plan are
granted at the market price of the units at the time of grant, vest over three
years and have a term of five years. The rights allow for the exercise price
of rights to be reduced in future periods by a portion of the future
distributions. Compensation expense is accounted for using the fair value
method. See Note 14 for a description of the plans.

    Comprehensive Income, Financial Instruments and Hedges

    In 2005 the Canadian Institute of Chartered Accountants issued three new
accounting standards: Comprehensive Income, Financial Instruments -
Recognition, and Measurement and Hedges. These standards were intended to
harmonize Canadian GAAP with U.S. GAAP and with International Financial
Reporting Standards. These accounting standards are effective for Sound on
January 1, 2007.

    Comprehensive income
    The new comprehensive income standard provides guidance for the reporting
and presentation of other comprehensive income. Comprehensive income
represents the change in equity of an enterprise during a period from
transactions and other events arising from non-owner sources. Examples of some
items that would be included in other comprehensive income are changes in the
fair value of available for sale assets and the effective portion of the
changes in fair value of cash flow hedging instruments. The Trust has one
designated held-to-maturity cash flow hedge in place subsequent to March 31,
2007 and will not designate any further of these financial instruments as
hedges. Also, the Trust does not expect to designate financial assets as
available for sale. The Trust does expect to recognize adjustments through
other comprehensive income in 2007 related to the effective portion of the
fair value of the one designated held-to-maturity cash flow hedge instrument.

    Financial instruments
    The new financial instruments standards require that all financial assets
and liabilities be classified into categories based on their attributes. The
categories determined for each of the financial assets and liabilities will
determine their measurement, either at fair value or amortized cost, and how
gains or losses are recognized. The standards also require all derivatives,
and derivatives that are embedded in non-derivative contracts, to be
recognized in the financial statements and measured at fair value.
    Based on the Trust's preliminary review, Sound expects to classify its
financial assets and liabilities in categories that will result in
measurements based on amortized cost, which we do not expect to be materially
different than carrying values of these items. Under the new standards,
deferred financing costs are no longer recognized as a deferred asset and
Sound expects to recognize unamortized deferred financing costs as an offset
to its debt balances. These costs are required to be amortized using the
effective-interest method versus the straight-line method used prior to 2007.
The change in amortization methodology is not expected to have a material
impact on the Trust's earnings.
    The Trust is in the process of finalizing its assessment of contracts for
embedded derivatives.

    Hedges
    The Trust currently has one designated cash flow hedge instrument but has
chosen to account for further cash flow hedge instruments at fair value with
gains and losses recognized immediately to net income. The Trust does expect
to recognize adjustments through other comprehensive income in 2007 related to
the effective portion of the fair value of the one designated held-to-maturity
cash flow hedge instrument. Other than this one designated held-to-maturity
cash flow hedge instrument, this standard is not expected to have an impact on
the Trust in 2007.

    Disclosure Controls and Procedures

    The President and Chief Executive Officer and the Senior Vice President
and Chief Financial Officer, together with management, have established and
maintained disclosure controls and procedures for the Trust in order to
provide reasonable assurance that material information relating to the Trust
is made known to them in a timely manner, particularly during the period in
which the annual filings are being prepared. Management has evaluated the
effectiveness of the Trust's disclosure controls and procedures as of
December 31, 2006, and based on that evaluation has concluded that these
controls are effective in providing such reasonable assurance.

    Internal Controls over Financial Reporting

    The President and Chief Executive Officer and the Senior Vice President
and Chief Financial Officer are also responsible for the design of internal
controls over financial reporting within the Trust in order to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
Canadian GAAP. These officers, together with management, have evaluated the
design of the Trust's internal controls and procedures over financial
reporting as of December 31, 2006, and based on that evaluation have concluded
that the design is effective to provide such reasonable assurance.
    There has been no change in the Trust's internal control over financial
reporting that occurred during the fourth quarter of fiscal 2006 that has
materially affected, or is reasonably likely to materially affect, the Trust's
internal control over financial reporting.
    Because of their inherent limitations, disclosure controls and procedures
and internal controls over financial reporting may not prevent or detect
misstatements, errors or fraud. Control systems, no matter how well conceived
or operated, can provide only reasonable, not absolute assurance that the
objectives of the controls systems are met.

    Recent Events and Outlook

    On October 31, 2006, the Canadian government announced its intention to
change the way that royalty trusts and income funds are taxed. The proposed
changes are not yet enacted and accordingly, there was no impact on the
Trust's December 31, 2006 financial statements. If the proposals are enacted
as currently written, they will result in taxation of distributions of certain
income at the Trust level at a rate of 31.5 percent effective January 1, 2011.
As Sound is an existing trust, there will be no impact on cash flow during the
four-year transition period. The Trust is currently assessing the proposals
and their potential implications to Sound.

    Business Risks

    The business of exploring, developing, acquiring and producing oil and
natural gas is subject to a variety of financial, operational and regulatory
risks.
    Financial risks include commodity prices, interest rates and the
Canadian/U.S. dollar exchange rate, all of which are beyond the control of the
Trust. The Trust's earnings and funds flow from operations are highly
sensitive to changes in factors that are beyond its control. The Trust's
approach to management of these risks is to maintain a prudent level of debt
and a strong financial position to fund exploration and development activities
and acquisitions through fluctuations in these variables. The Trust uses
financial instruments to manage exposures related to petroleum and natural gas
prices, interest rates and exchange rates. Such financial instruments are not
used by the Trust for trading or speculative purposes.
    Operational risks include finding and developing oil and natural gas
reserves on an economic basis, reservoir production performance, marketing,
production, hiring and retaining employees, and accessing contract services on
a cost-effective basis. In September 2006, specifically in response to
attracting and retaining employees, the Trust put in place a Unit Award
Incentive Plan that is believed to be in line with other corporate
compensation plans. However, this and other bonus or incentive plans will
continue to be reviewed to ensure the Trust remains competitive. Currently
Sound has a team of highly skilled individuals in the technical operations,
engineering and geological areas.
    The Trust maintains an insurance program consistent with industry
practice to protect against destruction of assets, well blowouts, pollution
and other business interruptions. The Trust generally follows a strategy of
acquiring and exploiting producing assets and maximizing these assets through
relatively low-risk development drilling while farming out highly exploratory-
type plays. The Trust makes appropriate use of advanced technology, such as
three-dimensional seismic, to reduce the risk of its drilling programs.
    Changes in government regulation with respect to taxation, royalties and
environmental and safety regulation are beyond the control of the Trust. On
October 31, 2006, the Canadian government proposed changes in the taxation of
income trusts; these have not yet been enacted and accordingly, have not
impacted the Trust's December 31, 2006 financial statements. If the proposed
changes are enacted as currently written, the Trust's distributions will be
taxed at a rate of 31.5 percent effective January 11, 2011. As the Trust is an
existing trust, there will be no impact on cash flow during the four-year
transition period. The Trust is currently assessing the proposed changes and
potential implications. This proposed change in the tax structure of income
trusts has caused uncertainty in the markets and therefore more volatility in
the unit prices. Should any more changes to existing tax rules occur, there
may be further negative implications to the Trust and its Unitholders.
    Government regulation impacts all aspects of the Trust's business,
including the way environmental issues are addressed. The Trust mitigates
risks with respect to environmental and safety matters by being proactive.
This approach includes conducting environmental reviews on all material
acquisitions the Trust contemplates, constructing modern facilities that meet
or exceed current environmental standards, and enforcing high safety standards
for its employees and contractors.
    The Trust also has an operational emergency response plan in place and is
substantially in compliance with current environmental legislation. In
addition, the Trust has significant financial exposure related to the future
costs of abandoning and restoring producing properties and facilities at the
end of their economic life.
    For a detailed discussion on business risks associated with the oil and
gas sector, please refer to the Trust's Annual Information Form, which will be
filed on SEDAR (www.sedar.com) on or before March 30, 2007.

    Outstanding Unit Information

    At March 9, 2007, there were 56.9 million units, 0.3 million Series A
exchangeable shares, 3,145 Series B exchangeable shares and 1.1 million
Series D exchangeable shares outstanding. The exchange ratio at March 9, 2006
for the Series A exchangeable shares was 1.64398 trust units per exchangeable
share, the exchange ratio for the Series B exchangeable shares was 1.61952,
and the exchange ratio for the Series D exchangeable shares was 1.10430. RTUs
of 2,062,200 and Trust rights of 105,417 are outstanding at March 9, 2007 and
convertible to a similar number of trust units.

    
    Outstanding Convertible Debentures

                                                                   Number of
                                                                       Units
                                                                      issued
                                           Number of                    upon
    As at March 9, 2007                        Units       $000s  conversion
    -------------------------------------------------------------------------
    8.75% Convertible Debenture               59,513      59,513       5,722
    8.0 % Convertible Debenture               41,035      41,035       6,727
    -------------------------------------------------------------------------
    Total                                    100,548     100,548      12,449
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Other Information on the Trust
    Additional information concerning the Trust including the Trust's Annual
Information Form, is available on SEDAR at www.sedar.com.

    Forward-Looking Statements - Certain statements contained within the MD&A
and in certain documents incorporated by reference into this document,
constitute forward-looking statements. These statements relate to future
events or our future performance. All statements other than statements of
historical fact may be forward-looking statements. Forward-looking statements
are often, but not always, identified by the use of words such as "seek",
"anticipate", "budget", "plan", "continue", "estimate", "expect", "forecast",
"may", "project", "predict", "potential", "targeting", "intend", "could",
"might", "should", "believe" and similar expressions. These statements involve
known and unknown risks, uncertainties and other factors that may cause actual
results or events to differ materially from those anticipated in such forward-
looking statements. We believe the expectations reflected in those forward-
looking statements are reasonable, but no assurance can be given that these
expectations will prove to be correct and such forward-looking statements
included in, or incorporated by reference into, this MD&A should not be unduly
relied upon. These statements speak only as of the date of this MD&A or as of
the date specified in the documents incorporated by reference into this MD&A,
as the case may be.
    In particular, this MD&A and the documents incorporated by reference into
it, contain forward-looking statements pertaining to the following:
    
    -   the performance characteristics of our oil and natural gas
        properties;
    -   oil and natural gas production levels;
    -   the size of the oil and natural gas reserves;
    -   projections of market prices and costs;
    -   supply and demand for oil and natural gas;
    -   expectations regarding the ability to raise capital and to
        continually add to reserves through acquisitions and development;
    -   treatment under governmental regulatory regimes and tax laws; and
    -   capital expenditures programs.

    The actual results could differ materially from those anticipated in these
forward-looking statements as a result of the risk factors set forth below and
elsewhere in this MD&A:

    -   volatility in market prices for oil and natural gas;
    -   liabilities inherent in oil and natural gas operations;
    -   uncertainties associated with estimating oil and natural gas
        reserves;
    -   competition for, among other things, capital, acquisitions of
        reserves, undeveloped lands and skilled personnel;
    -   incorrect assessments of the value of acquisitions;
    -   geological, technical, drilling and processing problems; and
    -   changes in income tax laws or changes in tax laws and incentive
        programs relating to the oil and gas industry and income trusts.
    

    Additional information on these and other factors that could affect
Sound's operations or financial results are included in Sound's reports on
file with Canadian securities regulating authorities and may be accessed
through the SEDAR website (www.sedar.com), Sound's website
(www.soundenergytrust.com) or by contacting Sound.
    Statements relating to "reserves" or "resources" are deemed to be 
forward-looking statements, as they involve the implied assessment, based on
certain estimates and assumptions, that the resources and reserves described
can be profitably produced in the future. Readers are cautioned that the
foregoing lists of factors are not exhaustive. The forward-looking statements
contained in this report and the documents incorporated by reference herein
are expressly qualified by this cautionary statement. Furthermore, the 
forward-looking statements contained in this report are made as of the date of
this report, and Sound 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 expressly required
by securities law. We do not undertake any obligation to publicly update or
revise any forward-looking statements.

    
    SOUND ENERGY TRUST
    Consolidated Balance Sheets

    Years ended December 31 ($000s)                         2006        2005
    -------------------------------------------------------------------------
    Assets
    Current
      Cash                                                 1,064           -
      Accounts receivable                                 29,074      18,069
      Fair value of derivative instruments (Note 17)         874           -
    -------------------------------------------------------------------------
                                                          31,012      18,069
    -------------------------------------------------------------------------
    Deferred charges (Note 7)                              4,167       1,911
    Future income tax asset (Note 13)                          -       2,166
    Property, plant and equipment (Note 4)               522,348     310,159
    Goodwill (Note 3)                                     91,295           -
    -------------------------------------------------------------------------
                                                         617,810     314,236
    -------------------------------------------------------------------------
                                                         648,822     332,305
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Liabilities
    Current
      Accounts payable and accrued liabilities            35,754      34,874
      Distributions payable (Note 15)                      5,685       2,835
      Current portion of deferred credits (Note 8)            94           -
      Current portion of capital lease
       obligation (Note 6)                                   212           -
      Bank debt (Note 5)                                       -      47,018
    -------------------------------------------------------------------------
                                                          41,745      84,727
    -------------------------------------------------------------------------
    Bank debt (Note 5)                                   102,300           -
    Deferred credits (Note 8)                                285           -
    Convertible debentures (Note 9)                      100,548      59,543
    Asset retirement obligation (Note 10)                 31,083      21,541
    Obligation under capital lease (Note 6)                  701           -
    Other long-term liabilities (Note 11)                      -       1,401
    Future income tax liability (Note 13)                  4,296           -
    -------------------------------------------------------------------------
                                                         239,213      82,485
    -------------------------------------------------------------------------

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

    Non-controlling interest (Note 12)                    12,116       3,100
    -------------------------------------------------------------------------
    Unitholders' Equity
    Unitholders' capital (Note 14)                       522,211     290,182
    Contributed surplus (Note 14)                          4,995       1,509
    Deficit (Note 15)                                   (171,458)   (129,698)
    -------------------------------------------------------------------------
                                                         355,748     161,993
    -------------------------------------------------------------------------
                                                         648,822     332,305
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See Notes to the Consolidated Financial Statements

    Approved on behalf of the Board of Directors:


    Thomas P. Stan                     Rodger Tourigny
    Director, President & CEO          Director




    SOUND ENERGY TRUST
    Consolidated Statements of Operations

    Years ended December 31
     ($000s, except per unit amounts)                       2006        2005
    -------------------------------------------------------------------------

    Revenue
      Petroleum and natural gas sales                    158,872     158,320
      Royalties, net of Alberta Royalty Tax Credits      (28,673)    (32,925)
    -------------------------------------------------------------------------
                                                         130,199     125,395
    -------------------------------------------------------------------------

    Expenses
      Production                                          38,897      30,010
      Transportation                                       5,627       4,979
      General and administrative (Notes 4, 11 and 14)     13,513       8,769
      Interest on convertible debentures (Note 9)          5,573       5,210
      Interest on bank debt                                5,209       2,153
      Payout settlement (Note 16)                              -       2,400
      Unrealized derivative gain (Note 17)                (1,522)          -
      Accretion of asset retirement obligation
       (Note 10)                                           2,171       1,440
      Depletion, depreciation and amortization            69,203      52,023
    -------------------------------------------------------------------------
                                                         138,671     106,984
    -------------------------------------------------------------------------

    Income (loss)  before taxes                           (8,472)     18,411
    -------------------------------------------------------------------------

    Taxes
      Capital taxes                                        1,129       1,409
      Future income tax recovery (Note 13)               (16,238)     (1,483)
    -------------------------------------------------------------------------
                                                         (15,109)        (74)
    -------------------------------------------------------------------------

    Income before non-controlling interest                 6,637      18,485
      Non-controlling interest (Note 12)                    (116)       (278)
    -------------------------------------------------------------------------
    Net income                                             6,521      18,207

    Net income per trust unit
      Basic                                                 0.17        0.65
      Diluted                                               0.16        0.63

    Weighted average number of trust units
     outstanding (Note 14)
      Basic                                               39,439      28,156
      Diluted                                             41,071      28,704
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See Notes to the Consolidated Financial Statements



    SOUND ENERGY TRUST
    Consolidated Statements of Deficit

    Years ended December 31 ($000s)                         2006        2005
    -------------------------------------------------------------------------
    Deficit, beginning of year                          (129,698)   (108,481)
    Distributions declared (Note 15)                     (48,281)    (39,424)
    Net income                                             6,521      18,207
    -------------------------------------------------------------------------
    Deficit, end of year                                (171,458)   (129,698)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See Notes to the Consolidated Financial Statements



    SOUND ENERGY TRUST
    Consolidated Statements of Cash Flows

    Years ended December 31 ($000s)                         2006        2005
    -------------------------------------------------------------------------
    Cash flows related to the following activities:

    Operating
      Net income                                           6,521      18,207
      Items not affecting cash:
        Accretion of asset retirement obligations          2,171       1,440
        Depletion, depreciation and amortization          69,203      52,023
        Unit-based compensation                            3,750       1,782
        Non-cash general and administrative expense            -         552
        Non-controlling interest                             116         278
        Future income tax recovery                       (16,238)     (1,483)
        Unrealized derivative gains                       (1,522)          -
      Asset retirement obligations settled                (1,519)       (840)
      Change in non-cash operating working capital        (3,445)      1,263
    -------------------------------------------------------------------------
                                                          59,037      73,222
    -------------------------------------------------------------------------
    Financing
      Increase in bank debt                                9,127      16,958
      Financing costs                                     (1,385)          -
      Convertible debentures issued, net of expenses      39,319           -
      Trust units issued for cash, net of expenses         1,617       1,338
      Proceeds on exercise of rights                       3,639         611
      Distributions                                      (45,431)    (40,666)
    -------------------------------------------------------------------------
                                                           6,886     (21,759)
    -------------------------------------------------------------------------
    Investing
      Property and equipment expenditures                (55,675)    (51,993)
      Property acquisitions                               (1,517)       (467)
      Property dispositions                                    -          67
      Transaction costs on acquisition of Clear Energy    (4,950)          -
      Change in non-cash working capital                  (2,717)        930
    -------------------------------------------------------------------------
                                                         (64,859)    (51,463)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net increase in cash                                   1,064           -

    Cash, beginning of year                                    -           -
    -------------------------------------------------------------------------
    Cash, end of year                                      1,064           -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    SOUND ENERGY TRUST
    Notes to Consolidated Financial Statements

    Years ended December 31, 2006 and 2005
    (all tabular amounts are in $000s except unit and per unit amounts)
    -------------------------------------------------------------------------

    1.  Structure of the Trust

        Sound Energy Trust ("Sound" or the "Trust") is an open-end
        unincorporated investment trust created under the laws of Alberta
        pursuant to a trust indenture (under NAV Energy Trust, "NAV") dated
        November 12, 2003, amended from time to time. The trust indenture was
        amended to change the name to Sound Energy Trust pursuant to the Plan
        of Arrangement effective August 14, 2006, resulting in the merger of
        Navigo Energy Inc. ("Navigo") and Clear Energy Inc. ("Clear Energy").
        The merger with Clear Energy has been accounted for as an acquisition
        with prior periods reflecting the financial position and results of
        operations of NAV. As a result of the Plan of Arrangement, a new
        series of exchangeable shares ("Series D") was created along with a
        new junior oil and gas exploration company known as Sure Energy Inc.
        ("Sure Energy"). The Trust disposed of certain oil and gas properties
        to Sure Energy as part of the Plan of Arrangement. Sound has no
        interest in Sure Energy.

        The beneficiaries of the Trust are the holders of trust units
        ("Unitholders"). The Trust was established to hold, directly and
        indirectly, interests in petroleum and natural gas properties. Cash
        flow is provided to the Trust from the properties owned and operated
        by its subsidiaries, SET Resources Inc. (the "Company") and Mamba
        Production Partnership (the "Partnership"). Cash flow is paid from
        the Company and the Partnership to the Trust by way of royalty
        payments, interest payments and principal repayments. The Trust makes
        monthly distributions to its Unitholders.

    2.  Significant Accounting Policies

        Basis of presentation

        The consolidated financial statements include the accounts of the
        Trust and its directly or indirectly wholly-owned subsidiaries, Sound
        1 Trust and the Partnership. All intercompany transactions have been
        eliminated.

        Measurement uncertainty

        The preparation of consolidated financial statements in conformity
        with Canadian generally accepted accounting principles requires
        management of the Trust to make estimates and assumptions that affect
        the amounts reported in the consolidated financial statements and
        accompanying notes. Actual results could differ from those estimated.
        The consolidated financial statements have, in management's opinion,
        been properly prepared using careful judgment and within the
        framework of the following significant accounting principles.

        The amounts recorded for depletion, depreciation and amortization,
        the impairment test and asset retirement obligations are based on
        future costs as well as estimates of reserves and production in the
        case of depletion. By their nature, these estimates and those related
        to the assessment of future cash flows used to assess impairment, are
        subject to measurement uncertainty and the impact on the financial
        statements of future periods could be material.

        Full cost accounting

        The Trust follows CICA Accounting Guideline 16 "Oil and gas
        accounting - full cost" ("AcG-16"). The Trust follows the full-cost
        method of accounting whereby all costs relating to the exploration
        for and development of petroleum and natural gas reserves are
        capitalized as part of Property, Plant and Equipment ("PP&E") in one
        Canadian cost centre and charged against income, as set out below.
        Such costs include land acquisition, drilling, geological and
        geophysical expenditures, production facilities and overhead expenses
        related to exploration and development activities. These costs are
        depleted and depreciated using a unit-of-production method using
        estimated gross proved petroleum and natural gas reserves as
        determined by independent engineers. For purposes of this
        calculation, petroleum and natural gas reserves are converted to a
        common unit of measurement on the basis of six thousand cubic feet of
        natural gas equating one barrel of oil. Costs of acquiring and
        evaluating unproved properties are excluded from costs subject to
        depletion and depreciation until it is determined whether proved
        reserves are attributable to the properties or impairment occurs.
        Costs of production facilities are depreciated on a
        unit-of-production basis. Gains or losses on sales of properties are
        recognized only when crediting the proceeds to costs would result in
        a change of 20 percent or more in the depletion rate.

        Oil and gas assets are evaluated in each reporting period to assess
        whether the costs are recoverable and do not exceed the fair value of
        the properties. The costs are assessed to be recoverable if the sum
        of the undiscounted cash flows expected from the production of proved
        reserves and the lower of cost and market of unproved properties
        exceed the carrying value of the oil and gas assets. If the carrying
        value of the oil and gas assets is not assessed to be recoverable, an
        impairment loss is recognized to the extent that the carrying value
        exceeds the sum of the discounted cash flows expected from the
        production of proved and probable reserves and the lower of cost and
        market of unproved properties. The cash flows are calculated using
        estimated future product prices and costs and are discounted using
        the risk-free rate. Reserves are determined pursuant to National
        Instrument 51-101.

        Asset retirement obligations

        The Trust recognizes as a liability the estimated fair value of the
        future retirement obligations associated with PP&E. The fair value is
        capitalized and amortized over the same period as the underlying
        asset. The Trust estimates the liability based on the estimated costs
        to abandon and reclaim its net ownership interest in all wells and
        facilities and the estimated timing of the costs to be incurred in
        future periods. This estimate is evaluated on a periodic basis and
        any adjustment to the estimate is prospectively applied. As time
        passes, the change in net present value of the future retirement
        obligation is expensed through accretion. Retirement obligations
        settled during the period reduce the future retirement liability.

        Office furniture, equipment and leaseholds

        Office furniture and equipment is depreciated using the straight-line
        method at an annual rate of 20 percent. Leasehold improvements are
        amortized over the remaining lease term. These asset costs and
        related depreciation and amortization are included as part of PP&E.

        Foreign currency

        Monetary assets and liabilities denominated in foreign currencies are
        translated into Canadian dollars at year-end exchange rates. Non-
        monetary items are translated at the average exchange rate during the
        month they are recorded. Exchange gains or losses are included in
        income in the year incurred.

        Goodwill

        The Trust recognizes goodwill on corporate acquisitions when the
        total purchase price exceeds the fair value of net identifiable
        assets and liabilities of the acquired entity. Goodwill is tested
        annually at year-end for impairment or as events occur that could
        result in impairment. Impairment is recognized based on the fair
        value of the Trust compared with the book value of the Trust. If the
        fair value of the Trust is less than the book value, impairment is
        measured by allocating the fair value to the identifiable assets and
        liabilities as if the Trust had been acquired in a business
        combination for its fair value. The excess of the fair value over the
        amounts assigned to the identifiable assets and liabilities is the
        fair value of the goodwill. Any excess of the book value over this
        implied fair value of goodwill is the impairment amount. Impairment
        is charged to earnings in the period in which it occurs. Goodwill is
        stated at cost less impairment and is not amortized. Goodwill was
        tested at December 31, 2006 for impairment and no impairment was
        required.

        Joint interests

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

        Revenue recognition

        Revenue associated with sales of crude oil, natural gas and natural
        gas liquids is recognized when title passes to the purchaser,
        normally at the pipeline delivery point for natural gas and at the
        wellhead for crude oil.

        Hedging

        The Trust follows Accounting Guideline 13 - Hedging Relationships,
        which deals with the identification, designation, documentation and
        effectiveness of hedging relationships for the purpose of applying
        hedge accounting. The Trust periodically utilizes certain financial
        instruments to reduce exposures related to petroleum and natural gas
        prices and foreign exchange fluctuations on a portion of its crude
        oil and natural gas production. Gains and losses on these contracts,
        all of which must constitute effective hedges, are recognized in
        revenue concurrently with the hedged transaction. If hedge
        requirements are not met or if the Trust does not designate the
        contract as a hedge, the financial instruments are recorded at fair
        value; any gains or losses are included in income in the period.

        Future income taxes

        The Trust follows the liability method of accounting for income
        taxes. Under this method, future tax assets and liabilities are
        determined based on differences between the financial reporting and
        tax basis of assets and liabilities and measured using the
        substantively enacted tax rates and laws that are currently in effect
        when the differences are expected to reverse.

        The Trust is a taxable entity under the Income Tax Act (Canada) and
        is taxable only on income that is not distributed or distributable to
        the Unitholders. As the Trust allocates all of its taxable income to
        the Unitholders in accordance with the Trust Indenture and meets the
        requirements of the Income Tax Act (Canada) applicable to the Trust,
        no provision for income tax expense has been made in the Trust.

        In the Trust structure, payments are made between the Company, the
        Partnership and the Trust which result in the transferring of taxable
        income from the Company and the Partnership to individual
        Unitholders. These payments may reduce future income tax liabilities
        previously recorded by the Company which are recognized as a recovery
        of income tax in the period the payments are made.

        Unit-based compensation

        The Trust has a Unit Award Incentive Plan for directors, officers,
        employees and consultants of the Trust. Under the terms of the plan,
        a holder may elect, subject to consent of the Trust, to receive cash
        upon vesting in lieu of the rights held. These rights are issued in
        the form of Restricted Trust Units ("RTUs") and Performance Trust
        Units ("PTUs"). Compensation expense associated with rights granted
        under the plan is measured at the date of grant. The value is
        determined as the difference between the market price at the grant
        date and the exercise price of the rights ($Nil) and amortized over
        the vesting period of the rights.

        Trust unit rights related to the Trust Units Rights Incentive Plan
        are granted at the market price of the units at the time of grant,
        vest over three years and have a term of five years. The rights allow
        for the exercise price of rights to be reduced in future periods by a
        portion of the future distributions. Compensation expense is
        accounted for using the fair value method. See Note 14 for a
        description of the plans.

        Per-unit amounts

        Net income per trust unit is calculated using the weighted average
        number of units outstanding during the year. Diluted net income per
        trust unit includes the effect of dilutive Exchangeable Shares, RTUs,
        PTUs and convertible debentures. This is calculated using the
        treasury stock method and "if converted" method, as appropriate, to
        determine the dilutive effect of any unit-based compensation and
        convertible securities. The treasury method assumes that the proceeds
        received from the exercise of "in the money" unit rights are used to
        re-purchase and cancel units at the average trading price for the
        period. The "if converted" method assumes conversion of convertible
        securities at the beginning of the reporting period or at a time of
        issuance, if later.

    3.  Acquisitions

        On August 14, 2006, the Trust completed the acquisition of Clear
        Energy, a public oil and gas company, by acquiring 100 percent of
        Clear Energy's outstanding common shares. The results of Clear Energy
        have been included in the consolidated financial statements since
        August 14, 2006. The acquisition was accounted for using the purchase
        method of accounting. The allocation of the consideration paid to the
        fair value of the assets acquired and liabilities assumed is as
        follows, but is subject to change upon the final determination of
        fair values:

        Allocation of purchase price                                   $000s
        ---------------------------------------------------------------------
        Accounts receivable                                           13,756
        Property and equipment                                       220,662
        Goodwill                                                      91,295
        Accounts payable                                             (10,034)
        Fair value of derivative instruments                            (648)
        Bank debt                                                    (46,155)
        Deferred credits                                                (414)
        Asset retirement obligation                                   (6,129)
        Future income tax liability                                  (22,700)
        ---------------------------------------------------------------------
                                                                     239,633
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Consideration given                                            $000s
        ---------------------------------------------------------------------
        Issue of 27,550,058 trust units(1)                           224,822
        Issue of 1,208,323 Series D exchangeable shares(1)             9,861
        Acquisition costs                                              4,950
        ---------------------------------------------------------------------
                                                                     239,633
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) For purposes of the purchase price determination, the Trust
            used a price of $8.59 per trust unit and exchangeable share,
            being the average market price of NAV Energy Trust units on the
            days surrounding the announcement of the transaction, which was
            then discounted by 5 percent to reflect underwriting fees that
            would have occurred for a comparable market transaction.


        The amount allocated to goodwill is not deductible for tax purposes.
        As part of the Plan of Arrangement, NAV conveyed $409,000 of assets
        to Sure Energy in exchange for common shares, which were subsequently
        distributed to Unitholders.

    4.  Property, Plant and Equipment

                                                       Accumulated
                                                         depletion,
                                                      depreciation
                                                               and  Net book
        $000s                                   Cost  amortization     value
        ---------------------------------------------------------------------
        December 31, 2006
        Property, plant and equipment      1,033,688     511,340     522,348
        ---------------------------------------------------------------------
        December 31, 2005
        Property, plant and equipment        655,021     344,862     310,159
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        At December 31, 2006, $56.7 million (2005 - $27.7 million) of costs
        relating to unproved properties were excluded from costs subject to
        depletion. During 2006, $5.3 million (2005 - $3.9 million) of general
        and administrative expenses relating to exploration and development
        activities were capitalized. At December 31, 2006, $0.9 million (2005
        - $Nil) of assets under capital lease have been included as part of
        PP&E (see Note 7).

        The ceiling test as at December 31, 2006 was calculated using prices
        from the reserve report effective on that date. The price for a
        barrel of oil used for the first five years 2007 to 2011 was $58.97,
        $58.24, $56.30, $55.25 and $55.46, respectively, and benchmarked to
        WTI; thereafter increasing by 1.07 percent through to 2018. The price
        used for a thousand cubic feet of natural gas for the first five
        years 2007 to 2011 was $7.21, $7.49, $7.81, $7.86 and $7.93,
        respectively, and benchmarked to AECO; thereafter increasing by
        2.8 percent through to 2018. No impairment was required for 2006 and
        2005.

    5.  Bank Debt

        At December 31, 2006, the Trust had a credit facility with a
        syndicate of chartered banks consisting of a $126.5 million
        extendible revolving term credit facility and a $20.0 million
        extendible operating credit facility. At December 31, 2006,
        $102.3 million was drawn on the facilities (December 31, 2005 -
        $47.0 million). The Trust's $20.0 million short-term facility,
        initially included as part of the credit facility, matured on
        December 31, 2006 and was not renewed. The revolving term facility
        and the operating facility are available on a revolving basis until
        August 2007 (364-day facility) and are subject to extension annually
        with the agreement of the lenders. Should the lenders not extend the
        revolving facility, the facility will automatically convert to a
        one-year non-revolving term loan with no repayments until the end of
        such year. The credit facility is secured by a $300.0 million demand
        debenture conveying a first floating charge over all the assets of
        the Trust and is subject to a semi-annual review of the borrowing
        base. The facility bears interest based on the prime rate and/or
        money market rates plus a margin which fluctuates based on the debt-
        to-cash flow ratio of the Trust. Under the terms of the credit
        facility, the Trust is restricted from making distributions in
        circumstances: (i) where there is an event of default under the
        credit facility; and (ii) where outstanding borrowings exceed the
        borrowing base agreed to by the lenders. In March of 2007, the
        Trust's credit facilities, which are subject to interim borrowing
        base reviews, were reduced to $135.0 million with the existing
        syndicate of lenders (see Note 23). As a result of this review, an
        additional restriction was placed on making distributions where the
        distribution is in excess of 100 percent of distributable cash as
        defined by the credit facilty. The approximate effective rate on bank
        debt was 5.9 percent for the year ended December 31, 2006
        (December 31, 2005 - 4.8 percent).

    6.  Obligation under Capital Lease and Commitments

        In December 2006, the Trust entered into a three-year capital lease
        for a compressor. The lease has payment commitments over the next
        three years as follows:

                                                                       $000s
        ---------------------------------------------------------------------
        2007                                                             220
        2008                                                             203
        2009                                                             643
        ---------------------------------------------------------------------
                                                                       1,066
        Less imputed interest at 7.3 percent                            (153)
        ---------------------------------------------------------------------
        Present value of the minimum lease payments                      913
        Less current portion                                            (212)
        ---------------------------------------------------------------------
                                                                         701
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


        The Trust has assumed the following commitments, as detailed in the
        table below:

                             Total   2007   2008   2009   2010   2011  After
        ---------------------------------------------------------------------
        Transportation
         agreements          3,165  1,895    970    300      -      -      -
        Operating leases     7,351  1,527  1,417  1,325  1,330    701  1,051
        ---------------------------------------------------------------------
                            10,516  3,422  2,387  1,625  1,330    701  1,051
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    7.  Deferred Charges

                                                                       $000s
        ---------------------------------------------------------------------
        Balance - December 31, 2004                                    2,460
        ---------------------------------------------------------------------
        Amortization of deferred charges                                (549)
        Additions                                                          -
        ---------------------------------------------------------------------
        Balance - December 31,  2005                                   1,911
        Amortization of deferred charges                                (845)
        Additions                                                      3,101
        ---------------------------------------------------------------------
        Balance - December 31,  2006                                   4,167
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The additions to deferred charges from the beginning of the year
        include commitment fees incurred on the credit facility as part
        of the Plan of Arrangement paid to the lenders of $1,385,000 and fees
        incurred on the issuance of $41.0 million in convertible debentures
        on November 13, 2006 of $1,716,000. Deferred charges are amortized
        over the term of the respective borrowing arrangement.

    8.  Deferred Credits

        The deferred credits relate to reimbursements from the landlord for
        leasehold improvements on office space. On the acquisition of Clear
        Energy, the value attributed to these inducements was $414,000 and is
        being amortized against office lease expense over the five-year term
        of the lease remaining (see Note 3). Total amortization for the
        period ended December 31, 2006 is $35,000.

    9.  Convertible Debentures

        On November 13, 2006, the Trust issued $41.0 million, 5-year,
        8 percent convertible unsecured subordinated debentures (the "8.0%
        Convertible Debentures"). The interest is payable semi-annually on
        June 30 and December 31 in each year commencing June 30, 2007. After
        December 31, 2009 and prior to maturity, the 8.0% Convertible
        Debentures may be redeemed in whole or in part from time to time at
        the option of the Trust on not more than 60 days and not less than
        30 days' prior notice, at a redemption price of $1,050 per 8.0%
        Convertible Debenture after December 31, 2009 and on or before
        December 31, 2010, and at a redemption price of $1,025 per 8.0%
        Convertible Debenture after December 31, 2010 and before maturity, in
        each case, plus accrued and unpaid interest thereon, if any. The
        Trust has the option to settle principal and interest in trust units.
        Each 8.0% Convertible Debenture is convertible into trust units at
        the option of the holder at any time at a conversion price of
        $6.10 per trust unit.

        On June 10, 2004, the Trust issued $60.0 million, 5-year,
        8.75 percent convertible unsecured subordinated debentures (the
        "8.75% Convertible Debentures"). The interest is payable semi-
        annually on June 30 and December 31 in each year commencing
        December 31, 2004. The 8.75% Convertible Debentures are redeemable at
        a price of $1,025 per 8.75% Convertible Debenture after June 30, 2008
        and before maturity on June 30, 2009. Each 8.75% Convertible
        Debenture is convertible into trust units at the option of the holder
        at any time at a conversion price of $10.40/trust unit. The Trust has
        the option to settle principal and interest in trust units. The
        conversion price of the 8.75% Convertible Debentures was adjusted
        from $11.00/trust unit to $10.40/trust unit to recognize the value of
        the distribution of Sure Energy shares to debenture holders as part
        of the Plan of Arrangement with Clear Energy.

                                                          Number
        Outstanding Convertible Debentures (000s)       of units       $000s
        ---------------------------------------------------------------------
        Balance - December 31,  2004                      59,552      59,552
        Exchanged for trust units                             (9)         (9)
        Issued                                                 -           -
        ---------------------------------------------------------------------
        Balance - December 31,  2005                      59,543      59,543
        Exchanged for trust units                            (30)        (30)
        Issued                                            41,035      41,035
        ---------------------------------------------------------------------
        Balance - December 31, 2006                      100,548     100,548
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    10. Asset Retirement Obligation

        The following table presents the reconciliation of the beginning and
        ending aggregate carrying amount of the obligation associated with
        the retirement of oil and gas properties:


        $000s                                               2006        2005
        ---------------------------------------------------------------------
        Asset retirement obligation, December 31, 2005    21,541      19,784
        Liabilities incurred on acquisition from
         Clear Energy (Note 3)                             6,129           -
        Liabilities incurred                               2,761       1,157
        Liabilities settled                               (1,519)       (840)
        Accretion of asset retirement obligation           2,171       1,440
        ---------------------------------------------------------------------
        Asset retirement obligation, December 31, 2006    31,083      21,541
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        At December 31, 2006, the total undiscounted asset retirement
        obligation is estimated to be $62.5 million (December 31, 2005 -
        $45.8 million). A 1.5 percent inflation rate and a seven percent
        discount rate assumption have been used to estimate the obligations.
        Most of the obligations related to oil and gas wells are expected to
        be settled from 2007 to 2026 and those related to the facilities
        settled up to 2040, all being funded from general Trust resources at
        the time of settlement.

    11. Other Long-Term Liabilities

        In May 2005, the Trust initiated a long-term incentive plan to retain
        and attract qualified employees, to promote a proprietary interest in
        the Trust by such employees, to encourage such employees to remain in
        the employ of the Trust, to put forth maximum efforts for the success
        of the Trust, and to reward positive performance. The plan award to a
        specific participant is expressed as a number of notional units. The
        number of notional units is referred to as the "Plan Unit Number".
        The Plan bonus was payable on the anniversary award date to each
        employee in the next three years after the grant date in the amount
        of 33 1/3 percent per year and to each officer and director in the
        amounts of 25 percent in the first year, 35 percent in the second
        year, and 40 percent in the third year. On each payment date the cash
        value of that portion of the Plan bonus to be paid to the specific
        participant was the percentage of the Plan Unit Number at the then
        unit price together with all distributions in respect of that
        percentage of the Plan Unit Number since the award date.

        The acquisition of Clear Energy Inc. on August 14, 2006 triggered a
        change of control provision under the long-term incentive plan. This
        resulted in the immediate vesting and payment of the next anniversary
        award granted to each employee. All other award grants were canceled
        and the plan terminated. As at December 31, 2006, there were no Plan
        Units outstanding (December 31, 2005 - 826,374 Plan Units). For the
        year ended December 31, 2006, compensation expense of $1.3 million
        has been included in general and administrative expenses (2005 -
        $1.7 million) and $0.9 million has been included as capitalized
        general and administrative (2005 - $1.1 million) outlays. The accrued
        long-term portion of the Trust's $2.8 million liability for the long-
        term incentive plan included in other long-term liabilities was
        $1.4 million at December 31, 2005.

    12. Non-Controlling Interest

        The exchangeable shares of the Trust are convertible at any time into
        trust units (at the option of the holder) based on the exchange
        ratio. The exchange ratio is increased monthly based on the cash
        distributions paid on the trust units divided by the five-day
        weighted average unit price preceding the record date. Cash
        distributions are not paid on the exchangeable shares. On the tenth
        anniversary of the issuance of the exchangeable shares, subject to
        extension of such date by the Board of Directors of the Company, the
        exchangeable shares will be redeemed for trust units at a price equal
        to the value of that number of trust units based on the exchange
        ratio as at the last business day prior to the redemption date.

        At December 31, 2006, the exchange ratio of the Series A exchangeable
        shares was 1.57996, for the Series B exchangeable shares was 1.55644,
        and for the Series D exchangeable shares was 1.06129. The total
        number of trust units that the exchangeable shares would be converted
        into at December 31, 2006 using these exchange ratios would be
        1,583,521. The Series D exchangeable shares were issued pursuant to
        the Plan or Arrangement effective August 14, 2006 (see Note 3).

        The exchangeable shares of the Trust are presented as a non-
        controlling interest on the consolidated balance sheet because they
        fail to meet the non-transferability criteria necessary in order for
        them to be classified as equity. Net income has been reduced by an
        amount equivalent to the non-controlling interest's proportionate
        share of the Trust's consolidated net income with a corresponding
        increase to the non-controlling interest on the balance sheet.


        Non-controlling interest

                                             Number   Convertible
                                           of shares  to units(1)      $000s
        ---------------------------------------------------------------------
        Series A
        Balance - December 31, 2004          319,119     372,176       3,344
        Exchanged for trust units            (51,232)    (62,223)       (540)
        Non-controlling interest in
         net income                                -           -         268
        Adjustment to exchange ratio               -      53,888           -
        ---------------------------------------------------------------------
        Balance - December 31, 2005          267,887     363,841       3,072
        Exchanged for trust units             (2,844)     (4,039)        (33)
        Non-controlling interest in
         net income                                -           -          77
        Adjustment to exchange ratio               -      58,955           -
        ---------------------------------------------------------------------
        Balance - December 31, 2006          265,043     418,757       3,116
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Series B
        Balance - December 31, 2004          187,172     215,115       1,487
        Exchanged for trust units           (184,027)   (219,301)     (1,469)
        Non-controlling interest in
         net income                                -           -          10
        Adjustment to exchange ratio               -       8,395           -
        ---------------------------------------------------------------------
        Balance - December 31, 2005            3,145       4,209          28
        Exchanged for trust units                  -           -           -
        Non-controlling interest in
         net income                                -           -           1
        Adjustment to exchange ratio               -         686           -
        ---------------------------------------------------------------------
        Balance - December 31, 2006            3,145       4,895          29
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Series C
        Balance - December 31, 2004          563,174     603,120       5,609
        Exchanged for trust units           (563,174)   (603,120)     (5,609)
        Non-controlling interest in
         net income                                -           -           -
        Adjustment to exchange ratio               -           -           -
        ---------------------------------------------------------------------
        Balance - December 31, 2005 and 2006       -           -           -
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Series D
        Balance - December 31, 2005                -           -           -
        Issued on acquisition of
         Clear Energy (Note 3)             1,208,323   1,208,323       9,861
        Exchanged for trust units           (115,437)   (117,355)       (928)
        Non-controlling interest in
         net income                                -           -          38
        Adjustment to exchange ratio               -      68,901           -
        ---------------------------------------------------------------------
        Balance - December 31, 2006        1,092,886   1,159,869       8,971
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Total outstanding                  1,361,074   1,583,521      12,116
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) The conversion ratios used at December 31, 2006, December 31,
            2005 and for exchanges that occurred during the years are
            specific to the dates represented or when the transaction
            occurred.

    13. Income Taxes

        The components of the future income tax liability at December 31,
        2006 and 2005 are as follows:

        $000s                                               2006        2005
        ---------------------------------------------------------------------
        Future income tax assets (liabilities)
          Property and equipment                         (12,605)     (4,269)
        Future income tax benefits
          Asset retirement obligations                     7,685       6,387
          Share issue costs                                  624          48
        ---------------------------------------------------------------------
        Future income tax asset (liability)               (4,296)      2,166
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The provision for income taxes differs from the result that would be
        obtained by applying the combined Canadian Federal and Provincial
        statutory income tax rates to income (loss) before taxes. This
        difference results from the following:


        $000s                                               2006        2005
        ---------------------------------------------------------------------

        Consolidated income (loss) before future taxes    (9,601)     17,002
          Income attributed to the Trust                  32,949      21,138
        ---------------------------------------------------------------------
          Loss before future taxes attributable to
           the Company                                   (42,550)     (4,136)
          Expected income taxes at the statutory rate
           of 35.8% (2005 - 37.6%)                       (15,233)     (1,555)
          Increase (decrease) in taxes resulting from:
            Crown royalties, (net of ARTC)                 1,868       3,621
            Resource allowance                            (2,882)     (3,897)
            Capital tax                                       88         469
            General and administrative not deductible      1,455         587
            Other                                             46          72
        ---------------------------------------------------------------------
        Utilized (not recognized) for tax on income
         earned (loss incurred) in period                (14,658)       (703)
          Adjustment of tax basis and reduction of
           future income tax rates                        (1,580)       (780)
        ---------------------------------------------------------------------
        Future income tax recovery                       (16,238)     (1,483)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


        The Trust had no taxable income in 2006 or 2005. The Trust has
        recorded a future tax liability of $4.3 million at December 31, 2006
        (2005 an asset of $2.2 million). The Trust's group of affiliated
        companies includes entities not subject to income tax as income is
        taxed directly to their ultimate owners. Total temporary differences
        associated with these entities not subject to tax is $11.5 million
        for 2006 (2005 - $19.9 million).

        $000s                                               2006        2005
        ---------------------------------------------------------------------
        Canadian exploration expenditures                 30,285      11,297
        Canadian development expenditures                 78,776      29,183
        Canadian oil and gas property expense            154,451      82,621
        Undepreciated capital cost                       136,823      67,577
        Non-capital losses                                19,990      37,805
        Other                                             11,300       7,581
        ---------------------------------------------------------------------
                                                         431,625     236,064
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


        On October 31, 2006, the federal government announced its intention
        to change the way that royalty trusts and income funds are taxed. The
        proposed changes are not yet enacted and accordingly, there was no
        impact on the Trust's December 31, 2006 consolidated financial
        statements. If the proposals are enacted as currently written, they
        will result in taxation of distributions at the Trust level at a rate
        of 31.5 percent effective January 1, 2011. As Sound is an existing
        trust, there will be no impact on cash flow in the four-year
        transition period. The Trust is currently assessing the proposals and
        their potential implications to Sound.

    14. Unitholders' Capital

        (a) Authorized

        The Trust is authorized to issue an unlimited number of Trust units.

        (b) Issued and outstanding

                                                          Number      Value
        Unit capital                                    of units     ($000s)
        ---------------------------------------------------------------------
        Balance - December 31, 2004                   27,180,218     280,221
        Trust Unit Rights exercised                       78,832         721
        Issued on conversion of Series A
         exchangeable shares                              62,223         540
        Difference between the fair value and book
         value on the conversion of Series A
         exchangeable shares                                   -        (277)
        Issued on conversion of Series B
         exchangeable shares                             219,301       1,469
        Issued on conversion of Series C
         exchangeable shares                             603,120       5,609
        Issued on conversion of convertible debentures       817           9
        Issued pursuant to the distribution
         reinvestment plan                               145,270       1,338
        Issued on settlement of retention
         bonus (Note 20)                                  61,583         552
        ---------------------------------------------------------------------
        Balance - December 31, 2005                   28,351,364     290,182
        Trust Unit Rights exercised                      558,500       4,731
        Issued on conversion of Series A
         exchangeable shares                               4,039          33
        Difference between the fair value and book
         value on the conversion of Series A
         exchangeable shares                                   -           1
        Issued on conversion of Series D
         exchangeable shares                             117,355         928
        Issued on conversion of convertible debentures     2,727          30
        Issued pursuant to the distribution
         reinvestment plan                               236,158       1,617
        Issued on acquisition of Clear
         Energy (Note 3)                              27,550,058     224,822
        Distribution of common shares of Sure
         Energy (Note 3)                                       -        (409)
        Issued on settlement of retention
         bonus (Note 20)                                  29,212         276
        ---------------------------------------------------------------------
        Balance - December 31, 2006                   56,849,413     522,211
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Redemption right

        Unitholders may redeem their trust units at any time by delivering
        their unit certificates to the Trustee, together with a properly
        completed notice requesting redemption. The redemption amount per
        trust unit will be the lesser of 90 percent of weighted average
        trading price of the trust units on the principal market on which
        they are traded for the 10-day period after the trust units have been
        validly tendered for redemption and the "closing market price" of the
        trust units. The redemption amount will be payable on the last day of
        the following calendar month. The "closing market price" will be the
        closing price of the trust units on the principal market on which
        they are traded on the date on which they were validly tendered for
        redemption, or, if there was no trade of the trust units on that
        date, the average of the last bid and ask prices of the trust units
        on that date.

        (c) Trust Unit Rights Incentive Plan

        The Trust Unit Rights Incentive Plan (the "Rights Plan") was
        established as part of the Plan of Arrangement effective December 29,
        2003 regarding the reorganization of Navigo into NAV. The Rights Plan
        has been replaced by the Unit Award Incentive Plan as discussed in
        "Unit Award Incentive Plan" of these consolidated financial
        statements and is no longer active for future grants. Trust unit
        rights are granted at the market price of the trust units at the time
        of the grant, vest over three years and have a term of five years.
        The Rights Plan allows for the exercise price of the rights to be
        reduced in future periods by a portion of the future distributions.

        The Trust recorded compensation expense for the year ended
        December 31, 2006 of $0.6 million (December 31, 2005 - $1.0 million),
        which has been recorded as a general and administrative expense and
        included in contributed surplus as the cost associated with the
        rights. The compensation expense was based on the fair value of
        rights issued and is amortized over the remaining vesting period of
        such rights.

        The number of unit rights issued and exercise prices are detailed
        below:

                                                                    Weighted
                                                                     average
                                                       Number of    exercise
        Trust Unit Rights                                 rights       price
        ---------------------------------------------------------------------
        Balance - December 31, 2004                    1,074,250      $10.33
        Granted                                          146,500        9.84
        Exercised                                        (78,832)       7.75
        Cancelled                                       (222,001)       9.10
        ---------------------------------------------------------------------
        Balance - December 31, 2005                      919,917       10.20
        Granted                                                -           -
        Exercised                                       (558,500)       6.27
        Cancelled                                       (253,500)       7.65
        ---------------------------------------------------------------------
        Balance - December 31, 2006 before reduction
         of exercise price                               107,917       10.29
        Reduction in exercise price for cumulative
         distributions                                         -       (3.54)
        ---------------------------------------------------------------------
        Balance - December 31, 2006                      107,917        6.75
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Exercisable - December 31, 2006                  107,917       $6.75
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


        (d) Unit Award Incentive Plan

        As a result of the Plan of Arrangement, on August 14, 2006, the
        Unitholders of Sound approved a unit award incentive plan. The plan
        authorizes the Board of Directors to grant rights to acquire trust
        units consisting of Restricted Trust Units ("RTUs") and Performance
        Trust Units ("PTUs") to directors, officers, employees and
        consultants of the Trust and its affiliates. The number of PTUs
        granted is dependent on various factors including the performance of
        the individual and the performance of the Trust relative to a peer
        comparison group of petroleum and natural gas trusts and other
        companies or other criteria the Board of Directors may determine. The
        number of PTUs that potentially may be granted to each employee is
        discretionary and is based upon an estimate made by management. A
        holder of an RTU or PTU may elect, subject to consent of the Trust,
        to receive cash upon vesting in lieu of the units to be issued. It is
        management's intention to settle unit awards in the form of trust
        units versus settlement in cash and as a result has accounted for
        these unit awards as equity instruments. The value is determined as
        the difference between the market price at the grant date and the
        exercise price of the rights ($Nil) and amortized over the vesting
        period of the rights. The following table sets forth the Unit Award
        Incentive Plan activity for the year ended December 31, 2006:

                                        Restricted   Performance
                                       Trust Units   Trust Units       Total
        ---------------------------------------------------------------------
        Balance - December 31, 2005              -             -           -
        Granted                          2,074,200             -   2,074,200
        Cancelled                          (47,000)            -     (47,000)
        ---------------------------------------------------------------------
        Balance - December 31, 2006      2,027,200             -   2,027,200
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        RTUs vest annually over a three-year period and, upon vesting,
        entitle the holder to the number of trust units designated or
        approved by the Compensation Committee. Forfeitures are recognized
        on an actual basis.

        The weighted average grant date fair value of the RTUs granted in
        2006 was $8.22 per unit. The fair value of units granted is amortized
        through compensation expense over the vesting period with a
        corresponding increase in contributed surplus.

        The Trust recorded compensation expense for the year ended
        December 31, 2006 of $3.9 million (December 31, 2005 - $Nil), which
        has been recorded as unit-based compensation and included in
        contributed surplus as the cost associated with the rights.

        As of December 31, 2006, no PTUs have been granted. Based upon the
        number of RTUs outstanding at December 31, 2006 and limited by the
        Unit Award Incentive Plan, the maximum number of PTUs that may be
        granted at a future date is 600,000.

        (e) Per-unit amounts

        The per unit amounts for the years ended December 31, 2006 and 2005
        were calculated based on the following weighted average number of
        units outstanding:

        Years ended December 31                             2006        2005
        ---------------------------------------------------------------------
        Basic                                         39,439,325  28,155,958
        Trust rights incentive plan                       14,443     180,261
        Series A exchangeable shares (Note 12)           418,757     363,841
        Series B exchangeable shares (Note 12)             4,895       4,209
        Series D exchangeable shares (Note 12)           441,704           -
        Restricted trust units                           752,353           -
        ---------------------------------------------------------------------
        Diluted                                       41,071,477  28,704,269
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        For the year ended December 31, 2006, the following securities were
        excluded from the determination of diluted net income per unit as
        their inclusion would be anti-dilutive: convertible debentures -
        6,609,186 (December 31, 2005 - 5,413,000); exchangeable shares -
        718,165 (December 31, 2005 - Nil); RTUs - 1,274,847 (December 31,
        2005 - Nil); and the Rights Plan - 93,474 (December 31, 2005 -
        739,656).


        (f) Contributed surplus

                                                                       $000s
        ---------------------------------------------------------------------
        Balance - December 31, 2004                                      666
        Compensation expense                                             953
        Net benefit on rights exercised                                 (110)
        ---------------------------------------------------------------------
        Balance - December 31, 2005                                    1,509
        Compensation expense                                           4,578
        Net benefit on rights exercised                               (1,092)
        ---------------------------------------------------------------------
        Balance - December 31, 2006                                    4,995
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    15. Distributions

        Income of the Trust includes all interest income from the Company,
        and other income, which accrues to the Trust to the end of the year.
        Under the Trust Indenture, taxable income of the Trust for each year
        will be paid or payable by way of cash distributions to the
        Unitholders.

        The following table shows the distributions declared for each month
        in the years ended December 31, 2006 and 2005:

                                        2006                    2005

                                  $/Unit       $000s      $/Unit       $000s
        ---------------------------------------------------------------------
        January                     0.10       2,839        0.15       4,186
        February                    0.10       2,841        0.15       4,193
        March                       0.10       2,842        0.15       4,211
        April                       0.10       2,843        0.15       4,213
        May                         0.10       2,845        0.10       2,816
        June                        0.10       2,847        0.10       2,817
        July                        0.10       2,848        0.10       2,826
        August                      0.10       5,661        0.10       2,829
        September                   0.10       5,673        0.10       2,831
        October                     0.10       5,676        0.10       2,833
        November                    0.10       5,681        0.10       2,834
        December                    0.10       5,685        0.10       2,835
        ---------------------------------------------------------------------
        Total                       1.20      48,281        1.40      39,424
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        At December 31, 2006, distributions of $5,685,000 (2005 - $2,835,000)
        were payable to Unitholders for the month of December, 2006. The cash
        distributions paid in 2006 were $45.4 million (2005 - $40.7 million).
        Cash distributions declared in 2006 were $48.3 (2005 -
        $39.4 million).

        The Trust has a Distribution Reinvestment Plan that provides eligible
        Unitholders of the Trust the advantage of accumulating additional
        trust units by reinvesting their cash distributions paid by the
        Trust. The cash distributions are reinvested at the discretion of the
        Company, either by the acquisition of trust units at prevailing
        market rates, or by the acquisition of trust units issued from
        treasury at 95 percent of the average market price (which is the
        weighted average trading price of trust units on the Toronto Stock
        Exchange for the period commencing on the second business day after
        the distribution record date and ending on the second business day
        immediately prior to the distribution payment date, such period not
        to exceed 20 trading days).

    16. Payout Settlement

        In 2005, the Trust expensed $2.4 million for settlement of two
        contractual arrangements with a third-party processor. For the first
        arrangement, a transportation contract, $1.4 million was paid on
        early termination in 2005. In 2006, $1.0 million was paid on early
        termination for the second agreement, a processing fee arrangement.

    17. Financial Instruments

        The carrying value of the Trust's accounts receivable, accounts
        payable and accrued liabilities and distributions payable
        approximates fair value due to the short term nature of these items.
        The Trust's bank debt bears interest at a floating market rate;
        accordingly, no significant difference exists between the fair value
        and the carrying value.

        Substantially all of the Trust's accounts receivable are due from
        customers in the oil and gas industry and are subject to the normal
        industry credit risks. The carrying value of accounts receivable
        reflects management's assessment of the associated credit risks.

        At December 31, 2006, the Trust had the following financial
        instruments outstanding where hedge accounting has not been applied,
        and the mark-to-market impact is reflected in the financial
        statements:

                                                          Hedged
                          Period           Volume         price        Index
        ---------------------------------------------------------------------
        Gas price collar  Nov. 1, 2006 to                 $8.00/GJ to
                           Mar. 31, 2007   5,000 GJ/d(1)  $9.17/GJ(1)   AECO
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) GJs convert to Mcf at a rate of 1.055056:1.


    18. Supplementary Cash Flow Information


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

        Interest paid on bank debt                         6,400       2,207
        Interest paid on convertible debentures(1)         7,814       2,605
        Taxes paid                                         1,342         967
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) Interest paid includes $2,605,000 accrued for as at December 31,
            2005.


    19. Hedging Contracts

        The nature of the Trust's operations results in exposure to
        fluctuations in commodity prices, foreign exchange rates and interest
        rates. The Trust monitors and, when appropriate, utilizes derivative
        financial instruments to hedge its exposure to these risks.

        The fair values of these derivative instruments are based on an
        estimate of the amounts that would have been received or paid to
        settle these instruments prior to maturity.

        The Trust is exposed to losses in the event of default by the
        counterparties to these derivative instruments.

        In 2006, petroleum and natural gas sales increased by $1.9 million
        (2005 - $2.7 million reduction) due to crude oil and natural gas
        hedging activities. At December 31, 2006, the Trust had the following
        financial instruments outstanding for which hedge accounting has been
        applied:

                                                         Hedged
                          Period          Volume         price         Index
        ---------------------------------------------------------------------
        Oil price collar  Jan. 1, 2007 to                US$70.00/bbl to
                           Dec. 31, 2007  500 bbls/d     US$74.30/bbl    WTI

        Gas price collar  Nov. 1, 2006 to                $8.00/GJ to
                           Mar. 31, 2007  5,000 GJ/d(1)  $11.40/GJ      AECO
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) GJs convert to Mcf at a rate of 1.055056:1.


        At December 31, 2006, settlement of the oil price collars would have
        resulted in gains of US$1.3 million (2005 - US$0.6 million) and
        settlement of the gas price collar would have resulted in a gain of
        $0.7 million (2005 - $Nil).

    20. Related-Party Transactions

        Pursuant to agreements dated December 31, 2003, three senior
        executives were entitled to receive a total of $1.5 million in
        retention bonuses payable in trust units based on the market price at
        the time of issue, payable in semi-annual payments over the
        following two years subject to certain conditions. During the first
        quarter of 2006, 29,212 trust units were issued in settlement of the
        last semi-annual payment for two senior executives. All of the third
        senior executive's retention bonus was settled during 2004.

        Sure Energy is a related party of Sound as three directors of Sure
        Energy sit on the Board of Directors of Sound and the same director
        serves as Chairman for both companies. The Trust is the operator of
        several properties in which Sure Energy is a joint venture partner.
        Amounts paid and to be paid by the Trust to Sure Energy totaled
        $397,000 for the year ended December 31, 2006. As at December 31,
        2006, $168,000 was included in accounts payable in respect of these
        amounts. Also, during 2006, Sure Energy was charged $129,000 for rent
        and parking by Sound, of which $57,000 was payable at December 31,
        2006. Amounts charged by or payable by the Trust to Sure Energy are
        on the same terms and conditions as charged to any other third party
        or third party joint venture partner.

    21. Contingencies

        The Trust is party to various outstanding claims arising from the
        normal course of business. In management's opinion, none of the
        claims, either individually or in total, is expected to have a
        material impact on the Trust's results of operations or financial
        position.

    22. Comparative Figures

        Certain comparative figures have been reclassified to conform to the
        current financial statement presentation. Certain pipeline tariffs
        previously netted against revenues have now been reclassified to
        transportation expense.

    23. Subsequent Events

        In March of 2007, the Trust's credit facilities, which are subject to
        interim borrowing base reviews, were reduced to $135.0 million with
        the existing syndicate of lenders. The primary reduction was the
        expiration of the $20.0 million short-term facility, and due to the
        issuance of subordinate debt in the fourth quarter of 2006, the
        remaining borrowing base was further reduced. As a result of this
        review, an additional restriction has been placed on making
        distributions where the distribution is in excess of 100 percent of
        distributable cash as defined by the credit facility.
    

    Sound is a Calgary-based, open-end oil and gas income trust whose trust
units trade on the Toronto Stock Exchange (the "TSX") under the symbol SND.UN.
Previously issued debentures of Sound trade on the TSX under the symbol SND.DB
and SND.DB.A.

    ADVISORY: Certain information regarding Sound Energy Trust including
management's assessment of future plans and operations, may constitute
forward- looking statements under applicable securities law and necessarily
involve risks associated with oil and gas exploration, production, marketing
and transportation such as loss of market, volatility of prices, currency
fluctuations, imprecision of reserve estimates, environmental risks,
competition from other producers and ability to access sufficient capital from
internal and external sources; as a consequence, actual results may differ
materially from those anticipated in the forward-looking statement





For further information:

For further information: Anne-Marie Buchmuller, Manager, Investor
Relations, Phone: (403) 218-3664, Toll-free: 1-888-414-4144,
www.soundenergytrust.com

Organization Profile

SOUND ENERGY TRUST

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