Sound Energy Trust announces second quarter 2007 results



    TSX: SND.UN

    CALGARY, Aug. 14 /CNW/ - Sound Energy Trust ("Sound" or the "Trust")
today announced its financial and operating results for the quarter ended
June 30, 2007.

    
    Second Quarter Highlights

    -   Production volumes for the second quarter averaged 9,601 boe/d, in
        line with updated guidance provided in the Trust's first quarter
        report;

    -   Funds flow from operations totaled $18.1 million; with $9.5 million
        or $0.17 per Trust unit declared in distributions to Unitholders,
        representing a payout ratio of 52 percent;

    -   The Trust booked a net loss of $16.7 million mainly as a result of
        the allocation of $8.7 million for future income taxes, a consequence
        of the federal government's plan to begin taxing income trusts
        beginning in 2011;

    -   On July 9, 2007, Sound and Advantage Energy Income Fund ("Advantage")
        jointly announced their plans to combine into a new, larger entity
        that will continue to operate under Advantage's name. Closing of the
        transaction is expected to occur in early September.


    Key Performance Indicators

    Unaudited
    $000s, except
     per unit      Three months ended June 30      Six months ended June 30
     amounts          2007      2006  % Change      2007      2006  % Change
    -------------------------------------------------------------------------
    FINANCIAL
    -------------------------------------------------------------------------
    Petroleum and
     natural gas
     sales (5)      45,984    36,394        26    91,384    71,151        28
    Funds flow
     from
     operations(1)  18,061    15,206        19    37,363    29,508        27
      Per unit
        - basic       0.32      0.53       (40)     0.65      1.04       (38)
        - diluted     0.28      0.52       (46)     0.57      1.02       (44)
    Net income
     (loss)        (16,692)    3,000      (656) (110,551)    3,693    (3,094)
      Per unit
        - basic      (0.29)     0.11      (364)    (1.93)     0.13    (1,585)
        - diluted    (0.29)     0.10      (390)    (1.93)     0.13    (1,585)
    Distributions
     declared        9,467     8,535        11    21,438    17,057        26
      Per unit       0.165     0.300       (45)    0.375     0.600       (38)
      Payout
       ratio(2)        52%       56%                 57%       58%
    Capital
     expenditures -
     exploration
     and develop-
     ment           10,316     7,498        38    22,354    39,456       (43)
    As at June 30,
     2007
      Unitholders'
       capital                                   525,234   291,186        80
      Convertible
       debentures                                 97,773    59,543        64
      Bank debt                                  113,419    83,032        37
      Working
       capital
       deficiency(3)                               4,975    11,181       (56)
      Total net
       debt(4)                                   118,394    94,213        26
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    Trust units
     (000s)
      Weighted
       average
       - basic      57,318    28,443       102    57,144    28,416       101
      Weighted
       average -
       diluted(6)   57,318    29,029        97    57,144    28,905        98
      Total trust
       units
       outstanding  57,441    28,467       102    57,441    28,467       102
    Unit Trading
      High ($/unit)   4.42      9.05       (51)     5.15      9.82       (48)
      Low ($/unit)    3.80      7.30       (48)     3.40      7.30       (53)
      Close ($/unit)  4.04      7.51       (46)     4.04      7.51       (46)
      Average daily
       trading
       volume
       (000s)          152       134        13       269       117       130
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    OPERATING
    -------------------------------------------------------------------------
    Daily production
      Crude oil
       and NGLs
       (bbl/d)       3,982     3,813         4     4,152     3,882         7
      Natural gas
       (Mcf/d)      33,714    21,890        54    32,972    20,726        59
      Oil
       equivalent
       (boe/d 6:1)   9,601     7,461        29     9,647     7,336        32
    Average wellhead
     prices
      Crude oil
       and NGLs
       ($/bbl)       63.41     69.38        (9)    60.64     63.55        (5)
      Natural gas
       ($/Mcf)        7.50      6.09        23      7.67      7.03         9
      Oil equivalent
       ($/boe 6:1)   52.63     53.60        (2)    52.34     53.58        (2)
    Operating
     netback
     ($/boe)(1)
      Petroleum and
       natural gas
       sales         52.63     53.60        (2)    52.34     53.58        (2)
      Realized
       derivative
       gain           1.00         -       100      1.34         -       100
      Royalties      (9.95)   (10.52)       (5)   (10.11)   (10.70)       (6)
      Production    (13.38)   (11.90)       12    (13.24)   (12.44)        6
      Transport-
       ation         (2.34)    (1.88)       24     (2.10)    (1.89)       11
    -------------------------------------------------------------------------
      Net operating
       income        27.96     29.30        (5)    28.23     28.55        (1)
    -------------------------------------------------------------------------
    Number of wells
     drilled,
     gross (net)    12(3.9)    3(1.6)        -    22(8.5)  44(34.9)        -
    -------------------------------------------------------------------------
    Success rate (%)   100       100         -       100        95         -
    -------------------------------------------------------------------------

    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 cash flow from operations
        before changes in non-cash working capital and asset retirement
        obligations settled. Operating netback equals petroleum and natural
        gas sales less royalties, derivative gains and losses, production
        expenses and transportation expenses 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,
        which excludes bank debt.

    (4) Net debt equals bank debt plus working capital deficiency.

    (5) Includes other revenue.

    (6) Trust units weighted average diluted includes exchangeable shares in
        2006 and excludes exchangeable shares in 2007 because they are anti-
        dilutive.

    (7) The merger of NAV Energy Trust and Clear Energy Inc. was accounted
        for as a purchase by NAV Energy Trust. Accordingly, the comparative
        figures are those of NAV Energy Trust for the same period in 2006.

    (8) All currency references are to Canadian dollars unless otherwise
        indicated.

    (9) 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,

    In May of this year, we announced that our Board of Directors had decided
to pursue strategic alternatives for Sound, struck a special committee and
engaged FirstEnergy Capital Corp. to act as advisors in this process. I am
pleased to report to you that in the six-week period during which our data
room was open to potential partners, we saw great interest and ultimately
received several non-binding offers for a transaction with Sound.
    After careful review of all the bids received, the special committee
determined that the offer from Advantage Energy Income Fund ("Advantage")
represented the best value for our Unitholders in several respects, including
an 11.3% premium on the trading price of our units, an excellent property fit,
similar culture and better access to the capital markets. The proposed merger
with Advantage was announced on July 9 and was received well in the markets.
    Both parties are working diligently towards a successful completion of
the proposed transaction, which is subject to approval by two-thirds of
Sound's Unitholders as well as regulatory and legal authorities. The
information circular was mailed to Sound's Unitholders on August 10, and the
special meeting is scheduled to take place at 9:00 a.m. Mountain Time on
September 5 in the Grand Lecture Theatre of the Metropolitan Centre, 333 - 4th
Avenue SW, Calgary, Alberta. I encourage all Unitholders and Exchangeable
Shareholders to exercise their right to vote, with our Board of Directors and
management unanimously - with the exception of one Board member who abstained
as he also sits on Advantage's Board - recommending to vote in favor of the
transaction.
    The bigger Advantage will be led by its current management team under
Kelly Drader, Chief Executive Officer, and Andy Mah, President and Chief
Operating Officer, both possessing a proven track record of successfully
enhancing Unitholder value for their company.
    This is Sound's final quarterly report, and I would like to take this
opportunity to extend my gratitude to the members of our Board of Directors
for their engagement on behalf of our Unitholders and their astute guidance to
management over the past years. I would also like to give my heartfelt thanks
to all of our staff members who have worked very hard and often gone beyond
the call of duty in their efforts to make Sound a successful entity. I wish
everybody all the best in their future endeavors.

    Tom Stan
    President and Chief Executive Officer
    August 10, 2007


    Review of Operations

    Capital development expenditures for the Trust in the second quarter
totaled $10.3 million, reflecting a reduced program that was limited by spring
break-up and weather impeding access to all our producing areas. During the
period, the Trust drilled a total of 12 (3.9 net) wells with 100 percent
success on the programs. Production over the quarter totaled 9,601 boe/d,
which is in line with our previously provided annual average production
guidance of 9,600 boe/d.
    In Northern Alberta, the Trust spent $1.6 million at Sousa on the tie-in
of one (1.0 net) Bluesky gas well and completion and tie-in of one (1.0 net)
Keg River oil well, resulting in approximately 125 boe/d of production for the
Trust.
    In Central Alberta, capital investments totaled $4.1 million, applied to
both drilling and well tie-ins. In Nevis, four (2.6 net) gas wells were
drilled, and two (1.2 net) wells were tied in. In addition, two (1.1 net)
wells were initiated - one each in Youngstown and Nevis - for which drilling
was completed in July. We anticipate 190 boe/d of additional production from
these new wells. Further, the Trust continued to optimize the gathering system
at Nevis with the installation of field booster compressors.
    In the Peace River Arch, the Trust spent $3.3 million at Clear River on
the drilling and the tie-in of two (1.2 net) wells. As well, workovers were
performed on three (2.6 net) wells. One of the new drilled wells was a
successful follow-up on a prior well into a Baldonnel oil pool. The new well
is currently producing approximately 90 boe/d. The second new well was a
development natural gas well, which confirmed our 3D seismic model, and is
currently producing approximately 55 boe/d. Production and development of the
Trust's Glacier asset in the Peace River Arch region continues to be
constrained by access to transportation and processing capacity. To resolve
this, the Trust has completed the initial engineering studies to identify and
scope alternative pipeline and processing options. We are currently working
towards resolving these access impairments.
    A total of $1.3 million in capital was expended in Saskatchewan, the
majority of which focused on several oil-producing opportunities within our
portfolio. At Crystal Hills, the Trust completed one (1.0 net) horizontal oil
well into the Souris Valley formation; this well is currently producing
approximately 45 boe/d. The Trust has multiple follow-up locations on its
lands in this area and is currently proceeding with additional development
drilling and construction of infrastructure. The Trust also participated in
the drilling of six (0.1 net) shallow gas wells in the Liebenthal area, all of
which were successful. At Lashburn and West Hazel, the Trust conducted six
(3.4 net) well workovers and reactivations; the affected wells are presently
producing approximately 90 boe/d.

    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, contains 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 Web site (www.sedar.com), Sound's Web site
(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 August 10, 2007 and should be read in conjunction with
the unaudited interim consolidated financial statements of Sound Energy Trust
("Sound" or the "Trust") for the three and six months ended June 30, 2007. 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 June 30, 2007 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 Energy 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. Operating 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

    As a result of the federal government's plans to begin taxing income
trusts such as Sound in 2011, the Trust incurred a future income tax
obligation of $8.7 million in the second quarter of 2007. This measure is
purely an accounting function and does not reflect an immediate corresponding
drop in cash flows. Essentially all Canadian income trusts have or will have
to make similar accommodations for the change in ruling that will become
effective in approximately 3.5 years.
    The Trust continues to distribute a portion of its cash flows to
Unitholders and in the reporting period saw a moderate payout ratio of 52
percent, well below the peer average. The balance of funds available was
applied to a reduced capital program, which nonetheless resulted in daily
average production of 9,601 boe/d, in line with guidance for 2007 provided
earlier in the year.
    During the second quarter, a Special Committee of the Board of Directors,
which was struck in March with the task of seeking strategic alternatives for
the Trust, conducted an active process that ultimately resulted in a number of
bids received from parties interested in carrying out a business transaction
with Sound. A careful review of all offers resulted in the joint announcement
on July 9, 2007 by Sound and Advantage Energy Income Fund ("Advantage")
proclaiming their intent on merging into a larger Advantage. The proposed
merger will provide Sound Unitholders with a number of benefits, including
participation in a larger, more sustainable entity that is listed both on the
Toronto and the New York Stock Exchanges. An information circular outlining
the details of the transaction, which requires approval by a minimum of 66 2/3
of Sound Unitholders and the customary regulatory and court approvals, was
mailed on August 10. It is anticipated that a Special Meeting of Sound
Unitholders to seek their approval will be held on September 5, 2007, with
closing expected to occur shortly thereafter, provided Unitholder approval is
granted at that meeting.

    
    Production

                   Three months ended June 30      Six months ended June 30
                      2007      2006  % Change      2007      2006  % Change
    -------------------------------------------------------------------------
    Crude oil &
     NGLs (bbl/d)    3,982     3,813         4     4,152     3,882         7
    Natural gas
     (Mcf/d)        33,714    21,890        54    32,972    20,726        59
    -------------------------------------------------------------------------
    Oil equivalent
     (boe/d)         9,601     7,461        29     9,647     7,336        32
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Combined average production volumes increased 29 percent to 9,601 boe/d
for the three months ended June 30, 2007 from 7,461 boe/d for the same period
in 2006. For the six months ended June 30, 2007, combined average production
volumes increased 32 percent to 9,647 boe/d from 7,336 boe/d for the same
period in 2006. The increase is mainly due to the inclusion of the acquisition
of Clear Energy Inc. that closed on August 14, 2006 (the "Clear Acquisition").

    
    Selected Financial Information

    Three months ended June 30               2007                2006

    -------------------------------------------------------------------------
                                         $000s     $/boe     $000s     $/boe
    -------------------------------------------------------------------------
    Petroleum and natural gas sales     45,984     52.63    36,394     53.60
    Realized derivative gain               872      1.00         -         -
    -------------------------------------------------------------------------
                                        46,856     53.63    36,394     53.60
    Royalties, net of ARTC              (8,691)    (9.95)   (7,144)   (10.52)
    Production                         (11,692)   (13.38)   (8,079)   (11.90)
    Transportation                      (2,043)    (2.34)   (1,281)    (1.88)
    -------------------------------------------------------------------------
    Net operating income                24,430     27.96    19,890     29.30
    Cash G&A(1)                         (2,170)    (2.48)   (2,033)    (2.99)
    Interest on convertible
     debentures(2)                      (2,143)    (2.45)   (1,320)    (1.94)
    Interest on bank debt               (1,764)    (2.02)   (1,017)    (1.50)
    Capital taxes                         (292)    (0.34)     (314)    (0.47)
    -------------------------------------------------------------------------
    Funds flow from operations          18,061     20.67    15,206     22.40
    Unit-based compensation(1)          (2,478)    (2.84)      343      0.50
    Non-cash interest on convertible
     debentures(2)                        (229)    (0.26)        -         -

    Unrealized derivative gain           3,937      4.51         -         -
    Accretion of asset retirement
     obligation                           (563)    (0.64)     (380)    (0.56)
    Depletion, depreciation and
     amortization                      (22,207)   (25.42)  (13,775)   (20.29)
    Future income tax recovery
     (expense)                         (13,425)   (15.37)    1,648      2.43
    -------------------------------------------------------------------------
                                       (16,904)   (19.35)    3,042      4.48
    Non-controlling interest               212      0.24       (42)    (0.06)
    -------------------------------------------------------------------------
    Net income (loss)                  (16,692)   (19.11)    3,000      4.42
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Cash flow from operations           19,069     21.83    12,593     18.55
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Included in G&A in the Statement of Operations.
    (2) Included in Interest on convertible debentures in the Statement of
        Operations.


    Six months ended June 30                 2007                2006

    -------------------------------------------------------------------------
                                         $000s     $/boe     $000s     $/boe
    -------------------------------------------------------------------------
    Petroleum and natural gas sales     91,384     52.34    71,151     53.58
    Realized derivative gain             2,346      1.34         -         -
    -------------------------------------------------------------------------
                                        93,730     53.68    71,151     53.58
    Royalties, net of ARTC             (17,649)   (10.11)  (14,207)   (10.70)
    Production                         (23,113)   (13.24)  (16,518)   (12.44)
    Transportation                      (3,684)    (2.10)   (2,513)    (1.89)
    -------------------------------------------------------------------------
    Net operating income                49,284     28.23    37,913     28.55
    Cash G&A(1)                         (3,804)    (2.18)   (3,443)    (2.59)
    Interest on convertible
     debentures(2)                      (4,237)    (2.43)   (2,605)    (1.96)
    Interest on bank debt               (3,272)    (1.87)   (1,706)    (1.28)
    Capital taxes                         (608)    (0.35)     (651)    (0.50)
    -------------------------------------------------------------------------
    Funds flow from operations          37,363     21.40    29,508     22.22
    Unit-based compensation(1)          (5,926)    (3.39)     (142)    (0.11)
    Non-cash interest on convertible
     debentures(2)                        (452)    (0.26)        -         -
    Impairment of goodwill             (91,295)   (52.28)        -         -
    Unrealized derivative gain           1,247      0.71         -         -
    Accretion of asset retirement
     obligation                         (1,121)    (0.65)     (768)    (0.58)
    Depletion, depreciation and
     amortization                      (42,836)   (24.53)  (26,879)   (20.24)
    Future income tax recovery
     (expense)                         (10,299)    (5.90)    2,025      1.53
    -------------------------------------------------------------------------
                                      (113,319)   (64.90)    3,744      2.82
    Non-controlling interest             2,768      1.59       (51)    (0.04)
    -------------------------------------------------------------------------
    Net income (loss)                 (110,551)   (63.31)    3,693      2.78
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Cash flow from operations           30,643     17.55    26,924     20.28
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Included in G&A in the Statement of Operations.
    (2) Included in Interest on convertible debentures in the Statement of
        Operations.


    Reconciliation of Funds Flow from Operations to Cash Flow from Operations

    Three months ended June 30               2007                2006

    -------------------------------------------------------------------------
                                         $000s     $/boe     $000s     $/boe
    -------------------------------------------------------------------------
    Cash flow from operations           19,069     21.83    12,593     18.55
    Asset retirement obligations
     settled                               397      0.45       211      0.31
    Change in non-cash operating
     working capital                    (1,405)    (1.61)    2,402      3.54
    -------------------------------------------------------------------------
    Funds flow from operations          18,061     20.67    15,206     22.40
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Six months ended June 30                 2007                2006

    -------------------------------------------------------------------------
                                         $000s     $/boe     $000s     $/boe
    -------------------------------------------------------------------------
    Cash flow from operations           30,643     17.55    26,924     20.28
    Asset retirement obligations
     settled                             2,202      1.26       495      0.37
    Change in non-cash operating
     working capital                     4,518      2.59     2,089      1.57
    -------------------------------------------------------------------------
    Funds flow from operations          37,363     21.40    29,508     22.22
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Petroleum and Natural Gas Sales ("P&NG sales")

    P&NG sales increased 26 percent to $46.0 million for the three months
ended June 30, 2007 compared with $36.4 million for the three months ended
June 30, 2006. Gains of $0.9 million were realized on derivative contracts in
the second quarter of 2007, compared with $Nil in the prior-year period.
    In the six months ended June 30, 2007 P&NG sales increased by 28 percent
to $91.4 million from $71.2 million in the comparative period. Gains of
$2.3 million were realized on derivative contracts in the first half of 2007
compared with $Nil in 2006.

    Crude Oil and Natural Gas Prices

                                    Three months            Six months
                                   ended June 30           ended June 30
                                                   %                       %
                                2007    2006  Change    2007    2006  Change
    -------------------------------------------------------------------------
    WTI average - US$/bbl      65.02   70.70      (8)  61.59   67.14      (8)
    US$/Cdn$ exchange rate
     average                   0.924   0.884       5   0.889   0.879       1
    Edmonton par price
     average - $/bbl           72.83   78.57      (7)  70.24   73.82      (5)
    AECO - C price - $/Mcf      7.37    6.03      22    7.42    6.76      10
    Trust crude oil and NGL
     price received - $/bbl    63.41   69.38      (9)  60.64   63.55      (5)
    Trust natural gas price
     received - $/Mcf           7.50    6.09      23    7.67    7.03       9
    Trust price received -
     $/boe                     52.63   53.60      (2)  52.34   53.58      (2)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    The pricing metrics in the three and six month periods ended June 30, 2007
are similar to those for their respective comparative periods in 2006. The
price received by the Trust on a barrel-of-oil-equivalent basis was marginally
lower than in the comparative period due to higher natural gas prices
mitigating lower received prices for crude oil and natural gas liquids
("NGLs").
    Crude oil and NGL prices were negatively impacted by lower market prices
and a stronger Canadian dollar. During the three-month period ended June 30,
2007, West Texas Intermediate ("WTI") crude prices decreased by eight percent
and the Canadian dollar strengthened by five percent. As a result, the Trust
received a price of $63.41 per barrel of crude oil and NGLs, nine percent less
than in the comparative period in 2006. In the six-month period ended June 30,
2007, the WTI price decreased by eight percent and the Canadian dollar
strengthened by one percent, which resulted in the Trust receiving a price of
$60.64 per barrel of crude oil and NGLs. This change represents a five-percent
drop compared with the prior-year period.
    The price received by the Trust for natural gas increased by 23 percent
and nine percent, respectively, for the three and six months ended June 30,
2007, compared with the same periods in 2006. This trend is consistent with
AECO pricing, which increased by 22 percent and 10 percent for the respective
periods stated.

    Royalties

    Royalties in the second quarter of 2007 were $8.7 million or 18.9 percent
of P&NG sales, compared with $7.1 million or 19.6 percent of P&NG sales in the
second quarter of 2006. Royalties in the first half of 2007 were $17.6 million
or 19.3 percent of P&NG sales, compared with $14.2 million or 20.0 percent of
P&NG sales in the first half of 2006.

                                                    % of                % of
                                          2007      P&NG      2006      P&NG
    Three months ended June 30          ($000s)    Sales    ($000s)    Sales
    -------------------------------------------------------------------------
    Crown royalties & mineral taxes      6,129      13.3     4,734      13.0
    ARTC                                     -         -      (117)     (0.3)
    -------------------------------------------------------------------------
    Net Crown royalties                  6,129      13.3     4,617      12.7
    Freehold & overriding royalties      1,948       4.2     2,009       5.5
    First Nations royalties                614       1.4       518       1.4
    -------------------------------------------------------------------------
    Total royalties                      8,691      18.9     7,144      19.6
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                                                    % of                % of
                                          2007      P&NG      2006      P&NG
    Six months ended June 30            ($000s)    Sales    ($000s)    Sales
    -------------------------------------------------------------------------
    Crown royalties & mineral taxes     12,450      13.6     9,501      13.3
    ARTC                                     -         -      (242)     (0.3)
    -------------------------------------------------------------------------
    Net Crown royalties                 12,450      13.6     9,259      13.0
    Freehold & overriding royalties      3,927       4.3     3,749       5.3
    First Nations royalties              1,272       1.4     1,199       1.7
    -------------------------------------------------------------------------
    Total royalties                     17,649      19.3    14,207      20.0
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Production Expenses

    Production expenses in the second quarter of 2007 increased to $11.7
million from $8.1 million in the second quarter of 2006, averaging $13.38/boe
and $11.90/boe, respectively. For the first half of 2007, production expenses
increased to $23.1 million over the $16.5 million reported in 2006 and
averaged $13.24/boe and $12.44/boe, respectively. The higher year-over-year
production costs are mainly due to higher prices of drilling and field
services.

    Operating Netbacks

    Three months ended June 30                          2007
    -------------------------------------------------------------------------
                                         Light    Medium     Heavy
                                           oil       oil       oil      NGLs
                                        ($/bbl)   ($/bbl)   ($/bbl)   ($/bbl)
    -------------------------------------------------------------------------
    Petroleum and natural gas sales      68.02     69.06     51.58     47.72
    Realized derivative gain              0.76         -         -         -
    -------------------------------------------------------------------------
                                         68.78     69.06     51.58     47.72

    Royalties                           (14.59)   (15.08)    (7.77)   (11.46)
    Production                          (19.19)   (16.54)   (17.13)        -
    Transportation                       (3.78)    (2.42)    (5.40)        -
    -------------------------------------------------------------------------
    Operating netback                    31.22     35.02     21.28     36.26
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Royalty as percent of petroleum
     and natural gas sales                  21        22        15        24
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Three months ended June 30                2007          2006
    ---------------------------------------------------------------
                                       Natural
                                           gas  Combined  Combined
                                        ($/Mcf)   ($/boe)   ($/boe)
    ---------------------------------------------------------------
    Petroleum and natural gas sales       7.50     52.63     53.60
    Realized derivative gain              0.20      1.00         -
    ---------------------------------------------------------------
                                          7.70     53.63     53.60

    Royalties                            (1.27)    (9.95)   (10.52)
    Production                           (1.90)   (13.38)   (11.90)
    Transportation                       (0.27)    (2.34)    (1.88)
    ---------------------------------------------------------------
    Operating netback                     4.26     27.96     29.30
    ---------------------------------------------------------------
    ---------------------------------------------------------------
    Royalty as percent of petroleum
     and natural gas sales                  17        19        20
    ---------------------------------------------------------------
    ---------------------------------------------------------------


    Six months ended June 30                           2007
    -------------------------------------------------------------------------
                                         Light    Medium     Heavy
                                           oil       oil       oil      NGLs
                                        ($/bbl)   ($/bbl)   ($/bbl)   ($/bbl)
    -------------------------------------------------------------------------
    Petroleum and natural gas sales      66.04     61.14     49.85     48.18
    Realized derivative gain              2.16         -         -         -
    -------------------------------------------------------------------------
                                         68.20     61.14     49.85     48.18

    Royalties                           (15.22)   (13.76)    (7.12)   (10.56)
    Production                          (17.69)   (14.30)   (16.32)        -
    Transportation                       (2.56)    (1.95)    (4.50)        -
    -------------------------------------------------------------------------
    Operating netback                    32.73     31.13     21.91     37.62
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Royalty as percent of petroleum
     and natural gas sales                  23        23        14        22
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Six months ended June 30                  2007          2006
    ---------------------------------------------------------------
                                       Natural
                                           gas  Combined  Combined
                                        ($/Mcf)   ($/boe)   ($/boe)
    ---------------------------------------------------------------
    Petroleum and natural gas sales       7.67     52.34     53.58
    Realized derivative gain              0.25      1.34         -
    ---------------------------------------------------------------
                                          7.92     53.68     53.58

    Royalties                            (1.31)   (10.11)   (10.70)
    Production                           (1.99)   (13.24)   (12.44)
    Transportation                       (0.31)    (2.10)    (1.89)
    ---------------------------------------------------------------
    Operating netback                     4.31     28.23     28.55
    ---------------------------------------------------------------
    ---------------------------------------------------------------
    Royalty as percent of petroleum
     and natural gas sales                  17        19        20
    ---------------------------------------------------------------
    ---------------------------------------------------------------


    General and Administrative ("G&A")

                                            Three months ended June 30
                                          2007   Per boe      2006   Per boe
    -------------------------------------------------------------------------
    Gross G&A                            6,547      7.49     3,172      4.67
    Overhead recoveries                   (735)    (0.84)     (703)    (1.03)
    Capitalized G&A                     (1,164)    (1.33)     (779)    (1.15)
    -------------------------------------------------------------------------
    Net G&A                              4,648      5.32     1,690      2.49
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                                              Six months ended June 30
                                          2007   Per boe      2006   Per boe
    -------------------------------------------------------------------------
    Gross G&A                           13,339      7.64     6,964      5.24
    Overhead recoveries                 (1,391)    (0.80)   (1,534)    (1.15)
    Capitalized G&A                     (2,218)    (1.27)   (1,845)    (1.39)
    -------------------------------------------------------------------------
    Net G&A                              9,730      5.57     3,585      2.70
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    


    G&A expense for the second quarter of 2007 was $4.6 million or $5.32/boe,
increasing from $1.7 million or $2.49/boe over the corresponding quarter of
2006. For the first six months of 2007, G&A expense was $9.7 million or
$5.57/boe, compared with $3.6 million or $2.70/boe in the 2006 reporting
period. This increase in gross G&A was mainly caused by the rise in unit-based
compensation related to the Unit Award Incentive Plan, which came into effect
upon the completion of the Clear Acquisition. Compensation expense related to
the Unit Award Incentive Plan recognized in the second quarter of 2007 was
$2.5 million, with $5.9 million being recognized in the first half of 2007.
    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 no longer records unit-based compensation
expense related to the Trust Units Rights Plan and Long-Term Incentive Plan as
these related costs were previously fully recognized.
    As of June 30, 2007, no performance trust units ("PTUs") have been
granted. Based upon the number of restricted trust units ("RTUs") outstanding
at June 30, 2007 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 June 30, 2007, the Trust, using the June 29, 2007 closing price of
$4.04/unit, would have recorded additional compensation expenses of
$2.4 million.

    Interest on Convertible Debentures

    Interest expense on the Convertible Debentures was $2.4 million and
$4.7 million for the three and six months ended June 30, 2007, respectively,
as compared to $1.3 million and $2.6 million, during the same respective
periods in 2006. The increase in interest expense is primarily due to the
issue of the $41.0 million 8.0% Convertible Debentures in November 2006 and,
to a lesser degree, to the inclusion of non-cash interest expense effective
January 1, 2007 upon the implementation of the new financial instruments
standards. The non-cash component of interest expense in the current year is
$0.2 million and $0.5 million, respectively.

    Interest on Bank Debt

    Interest expense for the second quarter of 2007 was $1.8 million, an
increase of 73 percent over the $1.0 million recorded in the second quarter of
2006. Interest expense in the first half of 2007 was $3.3 million, an increase
of 92 percent over the $1.7 million recorded in the first half of 2006. The
increase in interest expense in the current-year periods over the prior-year
periods is the result of higher debt balances in conjunction with a higher
interest rate environment.

    Goodwill

    At March 31, 2007, the Trust completed a valuation of goodwill, which was
established on the Clear Acquisition. As a result of the decline in market
valuation of the Trust during the first quarter of 2007, the Trust was
required to take a non-cash goodwill write-down of $91.3 million, representing
the entire amount of goodwill booked at the time of the Clear Acquisition.
This decline in market value of the Trust resulted in its fair value being
less than book value. The 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 Trust further reviewed its
petroleum and natural gas assets and determined no impairment of these assets
had been incurred at March 31, 2007 and June 30, 2007.

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

    DD&A was $22.2 million and $42.8 million for the three and six months
ended June 30, 2007, respectively, as compared to $13.8 million and $26.9
million, respectively, in 2006. This rise in DD&A in the current year is
mainly a result of a higher capital asset base in the reporting period due to
the Clear Acquisition that closed in the third quarter of 2006.

    Taxes

    Future income tax expense was $13.4 million and $10.3 million for the
three months and six months ended June 30, 2007, respectively, as compared
with future income tax recoveries of $1.6 million and $2.0 million,
respectively, during the same periods in 2006.
    On June 12, 2007, the legislation implementing the new tax on publicly
traded income trusts and limited partnerships (the "SIFT tax"), referred to as
"Specified investment flow-through" ("SIFT") entities (Bill C-52), received
third reading in the House of Commons and on June 22, 2007, the bill received
Royal Assent. As a result, the SIFT tax was considered to be enacted for
accounting purposes in June 2007. This change resulted in the recognition of a
future income tax liability and expense of $8.7 million. This is a non-cash
expense relating to temporary differences between the accounting and tax basis
of Sound's assets and liabilities and has no immediate impact on the Trust's
cash flows.

    
    Quarterly Information

                                              2007                2006
    -------------------------------------------------------------------------
    Three months ended ($000s)         Jun. 30   Mar. 31   Dec. 31  Sept. 30
    -------------------------------------------------------------------------
    Petroleum and natural gas sales     45,984    45,400    44,779    41,093
    Funds flow from operations          18,061    19,302    18,952    15,541
      Per unit - basic                    0.32      0.34      0.33      0.35
      Per unit - diluted                  0.28      0.30      0.30      0.34
    Net income (loss)                  (16,692)  (93,859)    3,403      (575)
      Per unit - basic                   (0.29)    (1.65)     0.06     (0.01)
      Per unit - diluted                 (0.29)    (1.65)     0.06     (0.01)
    Total assets                       536,903   544,655   648,822   663,502
    Exploration and development
     capital expenditures               10,316    12,038    11,040     5,179
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Production
      Crude oil (bbl/d)                  2,919     3,232     2,857     3,083
      Heavy oil (bbl/d)                    624       673     1,118       667
      Natural gas (Mcf/d)               33,714    32,222    37,446    30,326
      NGLs (bbl/d)                         439       419       320       206
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
      Combined (boe/d)                   9,601     9,694    10,536     9,010
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Average selling price
      Crude oil ($/bbl)                  68.31     61.33     52.03     72.37
      Heavy oil ($/bbl)                  51.58     48.23     51.11     55.57
      Natural gas ($/Mcf)                 7.50      7.85      7.13      5.70
      NGLs ($/bbl)                       47.72     48.73     46.87     65.63
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
      Combined ($/boe)                   52.63     52.04     46.20     49.57
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                                              2006                2005
    -------------------------------------------------------------------------
    Three months ended ($000s)         Jun. 30   Mar. 31   Dec. 31  Sept. 30
    -------------------------------------------------------------------------
    Petroleum and natural gas sales     36,394    34,757    45,937    45,865
    Funds flow from operations          15,206    14,302    21,280    20,501
      Per unit - basic                    0.53      0.50      0.75      0.73
      Per unit - diluted                  0.52      0.49      0.74      0.71
    Net income (loss)                    3,000       693     7,284     6,585
      Per unit - basic                    0.11      0.02      0.26      0.23
      Per unit - diluted                  0.10      0.02      0.25      0.23
    Total assets                       347,930   352,639   332,305   327,177
    Exploration and development
     capital expenditures                7,498    31,958    18,414     9,989
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Production
      Crude oil (bbl/d)                  3,124     3,261     3,356     3,507
      Heavy oil (bbl/d)                    504       504       508       497
      Natural gas (Mcf/d)               21,890    19,549    21,835    22,252
      NGLs (bbl/d)                         185       187       254       284
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
      Combined (boe/d)                   7,461     7,210     7,757     7,996
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Average selling price
      Crude oil ($/bbl)                  71.25     61.00     62.10     71.67
      Heavy oil ($/bbl)                  59.31     37.93     40.46     52.95
      Natural gas ($/Mcf)                 6.09      8.07     11.48      9.21
      NGLs ($/bbl)                       65.26     56.90     58.10     56.07
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
      Combined ($/boe)                   53.61     53.56     64.39     62.36
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    


    Funds Flow from Operations and Net Income (Loss)

    For the second quarter of 2007, the Trust recorded funds flow from
operations of $18.1 million or $0.32 per unit as compared to $15.2 million or
$0.53 per unit in the second quarter of 2006. The $9.6 million increase in
petroleum and natural gas sales, combined with $0.9 million in realized
derivative gains, was offset by a $3.6 million increase in production
expenses, a $1.6 million increase in cash interest, a $1.5 million increase in
royalties and a $0.8 million increase in transportation expense. On a
unit-of-production basis, funds flow from operations decreased by eight
percent to $20.67/boe compared with $22.40/boe, primarily as a result of
increased operating costs and cash interest. A $16.7 million net loss in the
second quarter of 2007 compares with $3.0 million in net income for the same
period in 2006. The primary drivers for the net loss in the reporting period
are increased DD&A ($8.4 million) and future income taxes ($15.1 million).
    For the first half of 2007, the Trust recorded funds flow from operations
of $37.4 million or $0.65 per unit as compared to funds flow from operations
of $29.5 million or $1.04 per unit in the first half of 2006. The $20.2
million increase in petroleum and natural gas sales, combined with $2.3
million in realized derivative gains, was offset by a $6.6 million increase in
production expenses, a $3.4 million increase in royalties, a $3.2 million
increase in cash interest and a $1.2 million increase in transportation
expense. On a unit-of-production basis, funds flow from operations decreased
by four percent to $21.40/boe compared with $22.22/boe in the prior year. A
$110.6 million net loss in the first half of 2007 compares with $3.7 million
in net income for the same period in 2006. The net loss was primarily caused
by the impairment of goodwill recorded in Q1 2007 associated with the Clear
Acquisition.

    
    Capital Expenditures

                                            Three months        Six months
                                           ended June 30       ended June 30
    ($000s)                               2007      2006      2007      2006
    -------------------------------------------------------------------------
    Land and lease                         715       423     1,369     1,097
    Geological and geophysical              92        71       611        69
    Drilling and completions             4,415     2,332    10,992    20,068
    Equipment and facilities             3,902     3,450     6,755    16,104
    Overhead and office equipment        1,192     1,222     2,627     2,118
    -------------------------------------------------------------------------
    Total exploration and development   10,316     7,498    22,354    39,456

    Property acquisitions                 (123)    1,028         -     1,028
    Property dispositions                    -         -       (59)        -
    -------------------------------------------------------------------------
    Total capital expenditures          10,193     8,526    22,295    40,484
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Exploration and development expenditures, excluding acquisitions, grew by
38 percent from $7.5 million in the second quarter of 2006 to $10.3 million in
the second quarter of 2007. The capital program for the second quarter of 2007
saw activities in all of Sound's core regions, with a particular focus on
providing a balanced portfolio of investment across the Trust's properties. In
Central Alberta, capital expenditures of $4.1 million included drilling,
equipping and tie-in costs. In Nevis, the coalbed methane program resulted in
the drilling of four gross (2.6 net) wells and the tie-in of two (1.2 net)
wells. All of the new wells were successfully completed and are expected to
commence production by the third quarter. In the Peace River Arch (the "PRA"),
the Trust spent $3.3 million for the drilling and tie-in of two (1.2 net)
wells. Additional costs in the PRA relate to workovers on several wells that
resulted in further development of crude oil and natural gas pools at Clear
River. In Saskatchewan, the Trust spent $1.3 million on several crude oil
projects. The program included the completion of one gross (1.0 net)
successful horizontal well at Crystal Hills and six gross (3.4 net) workovers
in the Lashburn and West Hazel areas. As well, the Trust participated in six
(0.1 net) successful shallow gas wells at Liebenthal. These activities have
resulted in identifying a number of follow-up drilling locations. In Northern
Alberta, $1.6 million was spent in the second quarter, with activities related
to the winter program.

    Liquidity and Capital Resources

    In the second quarter of 2007, the Trust's capital expenditures of
$10.2 million; distributions totaling $9.5 million; working capital
requirements of $4.7 million; and settlement of asset retirement obligations
of $0.4 million were primarily funded by a combination of $18.1 million in
funds flow from operations; bank financing of $6.0 million; and $0.7 million
in proceeds from the issuance of Trust units and rights.
    In the first half of 2007, the Trust's capital expenditures of $22.3
million; distributions totaling $24.0 million; working capital requirements of
$2.4 million; and settlement of asset retirement obligations of $2.2 million
were primarily funded by a combination of $37.4 million in funds flow from
operations; Bank financing of $11.2 million; $1.5 million in proceeds from the
issuance of trust units and rights; and cash on hand of $1.1 million.

    
    Distributable cash

                                            Three months        Six months
                                           ended June 30       ended June 30
    ($000s)                               2007      2006      2007      2006
    -------------------------------------------------------------------------
    Funds flow from operations          18,061    15,206    37,363    29,508
    Asset retirement obligations
     settled                              (397)     (211)   (2,202)     (495)
    Change in non-cash operating
     working capital                     1,405    (2,402)   (4,518)   (2,089)
    -------------------------------------------------------------------------
    Cash flow from operations           19,069    12,593    30,643    26,924
    -------------------------------------------------------------------------
    Cash distributions                   9,452     8,530    23,964    17,045
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    At June 30, 2007, the Trust had a credit facility with a syndicate of
chartered banks consisting of a $115.0 million extendible revolving term
credit facility and a $20.0 million extendible operating credit facility. At
June 30, 2007, $113.4 million was drawn on the combined facilities
(December 31, 2006 - $102.3 million). The revolving term facility and the
operating facility are available on a revolving basis until August 2007
(364-day facility) and are extendible annually subject to the lenders'
agreement. Should the revolving facility not be extended, the facility would
automatically convert to a one-year non-revolving term loan with no repayments
until the end of such year. As a result of the transaction contemplated with
Advantage, the Trust has decided to not request an extension of the revolving
facility. The lenders and the Trust have agreed to extend the term of the
credit facility to October 15, 2007, which is anticipated to be after the
closing of the transaction with Advantage announced on July 9, 2007.
    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; (ii) where outstanding borrowings exceed the borrowing
base agreed to by the lenders; and (iii) a restriction was placed on making
distributions where the distribution is in excess of 100 percent of
distributable cash as defined by the credit facility.
    For 2007, capital expenditures were anticipated to be $35.0 million,
which would have been funded from cash flow from operations. Upon closing of
the merger with Advantage, the decisions for capital spending for the
remainder of 2007 will remain with the management of Advantage.
    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.

    Financial Instruments and Hedging

    The Trust has established a well-defined risk management strategy that
focuses on protection of the cash distributions and maintenance capital
program through the use of financial instruments. The Trust expects the
commodity price exposure on approximately 50 percent of its production will be
mitigated through the use of financial instruments, with target prices to be
determined according to the Trust's budgets and forecasts. The Trust has
elected not to designate any financial instruments as hedges as defined in the
Canadian Institute of Chartered Accountants ("CICA") Handbook, section 3865.

    At June 30, 2007, the Trust had the following financial instruments
outstanding:

    
                          Period           Volume      Strike Prices   Index
    -------------------------------------------------------------------------
    Oil price collar  January 1, 2007 to   500 bbl/d   US$70.00/bbl to   WTI
                       December 31, 2007                US$74.30/bbl

    Oil price collar  March 1, 2007 to   1,000 bbl/d   US$57.00/bbl to   WTI
                       December 31, 2007                US$70.00/bbl

    Oil price collar  April 1, 2007 to     500 bbl/d   US$60.00/bbl to   WTI
                       December 31, 2007                US$71.50/bbl

    Gas price collar  March 1, 2007 to   10,000 GJ/d(1)  $7.50/GJ to    AECO
                       December 31, 2007                  $9.00/GJ(1)

    Gas price collar  May 1, 2007 to                     $7.50/GJ to    AECO
                       December 31, 2007  5,000 GJ/d(1)   $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 June 30,
2007, the Trust has estimated the total undiscounted asset retirement
obligation to be $64.7 million, which will be funded from general Trust
resources at the time of settlement.

    The Trust has assumed the following commitments:
    
                                             Less
                                             than      1-3      4-5    After
    $000s                          Total   1 year    years    years  5 years
    -------------------------------------------------------------------------
    Transportation agreements      3,062    1,968    1,094        -        -
    Operating leases               6,793    1,532    2,687    1,873      701
    -------------------------------------------------------------------------
                                   9,855    3,500    3,781    1,873      701
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    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

    Sure Energy is a related party of Sound as three directors of Sure Energy
are members of the Board of Directors of SET Resources Inc., the operating
company of the Trust, 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 received and to be received from Sure Energy by
the Trust totaled $286,000 and $509,000 for the three months and six months
ended June 30, 2007, respectively, of which $187,000 is receivable at the end
of the period. Amounts paid and to be paid from the Trust to Sure Energy
totaled $250,000 and $509,000 for the three months and six months ended June
30, 2007, respectively, of which $14,000 is payable at the end of the period.
Also, Sure Energy was charged by Sound $85,000 and $168,000, respectively, for
the three and six months ended June 30, 2007 for rent, business taxes and
parking. 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

    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 March 31, 2007 for impairment and
impairment of $91.3 million was recorded.
    Certain of our accounting policies require that we make appropriate
decisions with respect to the formulation of estimates and assumptions that
affect the reported amounts of assets, liabilities, revenues and expenses. For
a discussion about those accounting policies, please refer to our Management's
Discussion and Analysis for the year ended December 31, 2006 available at
www.sedar.com.

    Changes in Accounting Policies

    Comprehensive Income, Financial Instruments and Hedges

    Effective January 1, 2007, the Trust adopted the CICA (Canadian Institute
of Chartered Accountants) Handbook section 3855, "Financial Instruments -
Recognition and Measurement"; section 3865, "Hedges"; section 1530,
"Comprehensive Income"; and section 3861, "Financial Instruments - Disclosure
and Presentation." These standards have been adopted prospectively. See Note
3a) to the Consolidated Financial Statements.

    Accounting Changes

    In July 2006, the AcSB issued a revised CICA Handbook section 1506,
"Accounting Changes." These amendments were made to harmonize section 1506
with current international financial reporting standards. The changes covered
by this section include changes in accounting policy, changes in accounting
estimates, and correction of errors. Under CICA Handbook section 1506,
voluntary changes in accounting policy are only permitted if they result in
financial statements that provide more reliable and relevant information. When
a change in accounting policy is made, this change is applied retrospectively
unless impractical. Changes in accounting estimates are generally applied
prospectively and material prior-period errors are corrected retrospectively.
This section also outlines additional disclosure requirements when accounting
changes are applied, including justification for voluntary changes, complete
description of the policy, primary source of GAAP, and detailed effect on
financial statement line items. CICA Handbook section 1506 is effective for
fiscal years beginning on or after January 1, 2007.

    Recent Events and Outlook

    On May 14, 2007 the Board of SET Resources Inc., the operator of the
Trust, determined that it would be in the best interest of the Trust and its
stakeholders to commence a formal process to examine the strategic
alternatives available to maximize Unitholder value. The Board, in conjunction
with the management of the Trust and the Trust's financial advisor,
FirstEnergy Capital Corp., considered a full range of possible transactions
and respective restructuring options available to the Trust. These
alternatives included, but were not limited to, a merger with another issuer,
the disposition of the Trust, the acquisition or disposition of select assets,
the reversion of the Trust to a corporate structure, the spin-out or creation
of one or more issuers, or the continuation of the Trust with a new strategic
direction.
    On July 9, 2007, Advantage and Sound announced that their respective
boards of directors had approved a business combination. The transaction is
expected to be accomplished through a Plan of Arrangement by the exchange of
each Sound Trust unit ("Sound Unit") for 0.30 of an Advantage Trust unit
("Advantage Unit") or, at the election of the holder of Sound Units, $0.66 in
cash and 0.2557 of an Advantage Unit. Successful completion of the Arrangement
is subject to stock exchange, court and regulatory approvals and the approval
by at least two-thirds of Sound's Unitholders and Sound Exchangeable
Shareholders. It is anticipated that the Sound Unitholder meeting required to
approve the Arrangement will be held on September 5, 2007, with the
Arrangement expected to close shortly thereafter.

    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 may use
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 with the purpose of
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 a competitive employer.
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 blow-outs,
environmental 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 3-D 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
February 16, 2007, the Alberta Government announced that a review of the
province's royalty and tax regime (including income tax and freehold mineral
rights tax) pertaining to oil and gas resources, including oil sands,
conventional oil and gas and coalbed methane, will be conducted by a panel of
experts, with the assistance of individual Albertans and key stakeholders. The
review panel is to produce a final report that will be presented to the
Minister of Finance by August 31, 2007.
    All phases of the oil and natural gas business present environmental
risks and hazards and are subject to environmental regulation pursuant to a
variety of federal, provincial and local laws and regulations. Compliance with
such legislation can require significant expenditures and a breach may result
in the imposition of fines and penalties, some of which may be material.
Environmental legislation is evolving in a manner expected to result in
stricter standards and enforcement, larger fines and liability and potentially
increased capital expenditures and operating costs. In 2002, the Government of
Canada ratified the Kyoto Protocol, which calls for Canada to reduce its
greenhouse gas emissions to specified levels. There has been much public
debate with respect to Canada's ability to meet these targets and the
Government's strategy or alternative strategies with respect to climate change
and the control of greenhouse gases. Implementation of strategies for reducing
greenhouse gases, whether to meet the limits required by the Protocol or as
otherwise determined, could have a material impact on the nature of oil and
natural gas operations, including those of the Trust.
    The Federal Government released on April 26, 2007, its Action Plan to
Reduce Greenhouse Gases and Air Pollution (the "Action Plan"), also known as
ecoACTION and which includes the Regulatory Framework for Air Emissions. This
Action Plan covers not only large industry, but regulates the fuel efficiency
of vehicles and the strengthening of energy standards for a number of
energy-using products. Regarding large industry and industry-related projects,
the Government's Action Plan intends to achieve the following: (i) an absolute
reduction of 150 megatonnes in greenhouse gas emissions by 2020 by imposing
mandatory targets; and (ii) air pollution from industry is to be cut in half
by 2015 by setting certain targets. New facilities using cleaner fuels and
technologies will have a grace period of three years. In order to facilitate
the companies' compliance of the Action Plan's requirements, while at the same
time allowing them to be cost-effective, innovative and adopt cleaner
technologies, certain options are provided. These are: (i) in-house
reductions; (ii) contributions to technology funds; (iii) trading of emissions
with below-target emission companies; (iv) offsets; and (v) access to Kyoto's
Clean Development Mechanism.
    On March 8, 2007, the Alberta Government introduced Bill 3, the Climate
Change and Emissions Management Amendment Act, which intends to reduce
greenhouse gas emission intensity from large industries. Bill 3 states that
facilities emitting more than 100,000 tonnes of greenhouse gases a year must
reduce their emissions intensity by 12 percent starting July 1, 2007; if such
reduction is not initially possible the companies owning the large emitting
facilities will be required to pay $15 per tonne for every tonne above the
12-percent target. These payments will be deposited into an Alberta-based
technology fund that will be used to develop infrastructure to reduce
emissions or to support research into innovative climate change solutions. As
an alternate option, large emitters can invest in projects outside of their
operations that reduce or offset emissions on their behalf, provided that
these projects are based in Alberta. Prior to investing, the offset
reductions, offered by a prospective operation, must be verified by a third
party to ensure that the emission reductions are real.
    Given the evolving nature of the debate related to climate change and the
control of greenhouse gases and resulting requirements, it is not possible to
predict the impact of those requirements on the Trust and its operations and
financial condition.
    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 filed on SEDAR
(www.sedar.com).

    Outstanding Unit Information

    At August 10, 2007, there were 57.5 million units, 0.3 million Series A
exchangeable shares, 3,145 Series B exchangeable shares and 0.9 million
Series D exchangeable shares outstanding. The exchange ratio at August 14,
2007 for the Series A exchangeable shares was 1.75785 Trust units per
exchangeable share, the exchange ratio for the Series B exchangeable shares
was 1.73169, and the exchange ratio for the Series D exchangeable shares was
1.18079. RTUs of 2,248,405 and Trust rights of 103,917 were outstanding at
August 10, 2007 and convertible to a like number of Trust units.

    
    Outstanding Convertible Debentures
                                                                      Number
                                                                    of Units
                                            Number               issued upon
    As at August 10, 2007                 of Units        $000s   conversion
    -------------------------------------------------------------------------
    8.75% Convertible Debenture             59,513       59,513        5,722
    8.00% 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 Web site (www.sedar.com), Sound's Web site
(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.

    
    Consolidated Balance Sheets
                                                        June 30  December 31
    Unaudited ($000s)                                      2007         2006
    -------------------------------------------------------------------------
    Assets
    Current
      Cash                                                    -        1,064
      Accounts receivable (Note 3)                       27,704       29,074
      Derivative financial instruments (Notes 3 and 17)   4,024          874
    -------------------------------------------------------------------------
                                                         31,728       31,012
    -------------------------------------------------------------------------
    Deferred charges (Notes 3 and 10)                         -        4,167
    Property, plant and equipment (Note 5)              505,175      522,348
    Goodwill (Note 6)                                         -       91,295
    -------------------------------------------------------------------------
                                                        505,175      617,810
    -------------------------------------------------------------------------
                                                        536,903      648,822
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Liabilities
    Current
      Accounts payable and accrued liabilities           32,121       35,754
      Distributions payable (Note 16)                     3,159        5,685
      Current portion of deferred credits (Note 9)           94           94
      Current portion of capital lease obligation
       (Note 8)                                             324          212
      Derivative financial instruments (Notes 3 and 17)   1,005            -
    -------------------------------------------------------------------------
                                                         36,703       41,745
    -------------------------------------------------------------------------
    Bank debt (Notes 3,7 and 22)                        113,419      102,300
    Deferred credits (Note 9)                               238          285
    Convertible debentures (Notes 3 and 10)              97,773      100,548
    Asset retirement obligation (Note 11)                32,605       31,083
    Obligation under capital lease (Note 8)               1,263          701
    Future income tax liability (Notes 3 and 13)         14,528        4,296
    -------------------------------------------------------------------------
                                                        259,826      239,213
    -------------------------------------------------------------------------

    Non-controlling interest (Note 14)                    7,797       12,116
    -------------------------------------------------------------------------
    Unitholders' Equity
    Unitholders' capital (Note 15)                      525,234      522,211
    Contributed surplus (Note 15)                        10,921        4,995
    Accumulated other comprehensive income (Note 3)         542            -
    Deficit (Notes 3 and 16)                           (304,120)    (171,458)
    -------------------------------------------------------------------------
                                                        232,577      355,748
    -------------------------------------------------------------------------
                                                        536,903      648,822
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See Notes to the Consolidated Financial Statements



    Consolidated Statements of Operations and
    Comprehensive Income (Loss)
    -------------------------------------------------------------------------
                                      Three months ended    Six months ended
                                                 June 30             June 30
    -------------------------------------------------------------------------
    Unaudited
     ($000s, except per unit amounts)     2007      2006      2007      2006
    -------------------------------------------------------------------------
    Revenue
      Petroleum and natural gas sales   45,984    36,394    91,384    71,151
      Royalties, net of Alberta
       Royalty Tax Credits              (8,691)   (7,144)  (17,649)  (14,207)
    -------------------------------------------------------------------------
                                        37,293    29,250    73,735    56,944
    Expenses
      Production (Note 15)              11,692     8,079    23,113    16,518
      Transportation                     2,043     1,281     3,684     2,513
      General and administrative
       (Notes 5, 12 and 15)              4,648     1,690     9,730     3,585
      Interest on convertible
       debentures (Notes 3 and 10)       2,372     1,320     4,689     2,605
      Interest on bank debt              1,764     1,017     3,272     1,706
      Impairment of goodwill                 -         -    91,295         -
      Derivative gain (Notes 3 and 17)  (4,809)        -    (3,593)        -
      Accretion of asset retirement
       obligation (Note 11)                563       380     1,121       768
      Depletion, depreciation and
       amortization                     22,207    13,775    42,836    26,879
    -------------------------------------------------------------------------
                                        40,480    27,542   176,147    54,574
    -------------------------------------------------------------------------
    Income (loss) before taxes          (3,187)    1,708  (102,412)    2,370
    -------------------------------------------------------------------------
    Taxes
      Capital taxes                        292       314       608       651
      Future income tax expense
       (recovery)                       13,425    (1,648)   10,299    (2,025)
    -------------------------------------------------------------------------
                                        13,717    (1,334)   10,907    (1,374)
    -------------------------------------------------------------------------
    Income (loss) before
     non-controlling interest          (16,904)    3,042  (113,319)    3,744
      Non-controlling interest
       (Note 13)                           212       (42)    2,768       (51)
    -------------------------------------------------------------------------
    Net income (loss)                  (16,692)    3,000  (110,551)    3,693
    Other comprehensive income (loss)
      Loss on cash flow hedges
       de-designated on January 1, 2007
       (net of tax of $112 and $440)      (270)        -    (1,053)        -
    -------------------------------------------------------------------------
    Comprehensive income (loss)        (16,962)    3,000  (111,604)    3,693
    -------------------------------------------------------------------------
    Net income (loss) per Trust unit
      Basic                              (0.29)     0.11     (1.93)     0.13
      Diluted                            (0.29)     0.10     (1.93)     0.13

    Weighted average number of Trust
     units outstanding (Note 15)
      Basic                             57,318    28,443    57,144    28,416
      Diluted                           57,318    29,029    57,144    28,905
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See Notes to the Consolidated Financial Statements



    Consolidated Statement of Retained Earnings

                                      Three months ended    Six months ended
                                                 June 30             June 30
    Unaudited ($000s)                     2007      2006      2007      2006
    -------------------------------------------------------------------------
    Deficit, beginning of period      (277,961) (137,527) (171,458) (129,698)
    Net income (loss)                  (16,692)    3,000  (110,551)    3,693
    Distributions (Note 16)             (9,467)   (8,535)  (21,438)  (17,057)
    Adoption of financial instruments
     (Note 3)                                -         -      (673)        -
    -------------------------------------------------------------------------
    Deficit, end of period            (304,120) (143,062) (304,120) (143,062)
    -------------------------------------------------------------------------



    Consolidated Statement of
    Accumulated Other Comprehensive Income

    Accumulated other comprehensive
     income, beginning of period           812         -         -         -
    Adoption of financial instruments
     (Note 3)                                -         -     1,595         -
    Other comprehensive loss
      Loss on cash flow hedges
       de-designated on January 1,
       2007 (net of tax of $112
       and $440)                          (270)        -    (1,053)        -
    -------------------------------------------------------------------------
    Accumulated other comprehensive
     income, end of period                 542         -       542         -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See Notes to the Consolidated Financial Statements



    Consolidated Statements of Cash Flows
    -------------------------------------------------------------------------
                                      Three months ended    Six months ended
                                                 June 30             June 30
    -------------------------------------------------------------------------
    Unaudited ($000s)                     2007      2006      2007      2006
    -------------------------------------------------------------------------

    Cash flows related to the following
     activities:

    Operating
      Net income (loss)                (16,692)    3,000  (110,551)    3,693
      Items not affecting cash:
        Accretion of asset retirement
         obligations                       563       380     1,121       768
        Depletion, depreciation and
         amortization                   22,207    13,775    42,836    26,879
        Unit-based compensation          2,478      (343)    5,926       142
        Non-cash interest expense          229         -       452         -
        Non-controlling interest          (212)       42    (2,768)       51
        Future income tax expense
         (recovery)                     13,425    (1,648)   10,299    (2,025)
        Impairment of goodwill               -         -    91,295         -
        Unrealized derivative gain      (3,937)        -    (1,247)        -
      Asset retirement obligations
       settled                            (397)     (211)   (2,202)     (495)
      Change in non-cash operating
       working capital                   1,405    (2,402)   (4,518)   (2,089)
    -------------------------------------------------------------------------
                                        19,069    12,593    30,643    26,924
    -------------------------------------------------------------------------

    Financing
      Increase in bank debt              5,976    18,786    11,245    36,014
      Convertible debentures issued,
       net of expenses                      (4)      359      (156)      692
      Trust units issued for cash,
       net of expenses                     732         -     1,472         -
      Proceeds on exercise of rights         -         -         -         5
      Settlement of lease obligation       (44)        -       (91)        -
      Distributions                     (9,452)   (8,530)  (23,964)  (17,045)
    -------------------------------------------------------------------------
                                        (2,792)   10,615   (11,494)   19,666
    -------------------------------------------------------------------------

    Investing
      Property, plant and equipment
       expenditures                    (10,316)   (7,498)  (22,354)  (39,456)
      Property acquisitions                123    (1,028)        -    (1,028)
      Property dispositions                  -         -        59         -
      Change in non-cash working
       capital                          (6,084)  (14,682)    2,082    (6,106)
    -------------------------------------------------------------------------
                                       (16,277)  (23,208)  (20,213)  (46,590)
    -------------------------------------------------------------------------

    Net decrease in cash                     -         -    (1,064)        -
    Cash, beginning of period                -         -     1,064         -
    -------------------------------------------------------------------------
    Cash, end of period                      -         -         -         -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See Notes to the Consolidated Financial Statements



    SOUND ENERGY TRUST
    Notes to Consolidated Financial Statements

    Three months and six months ended June 30, 2007 (Unaudited)
    (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

        The interim consolidated financial statements of the Trust have been
        prepared by management in accordance with accounting principles
        generally accepted in Canada. The interim consolidated financial
        statements have been prepared following the same accounting policies
        and methods of computation as the consolidated financial statements
        for the fiscal year ended December 31, 2006, except as noted below.
        The interim consolidated financial statements should be read in
        conjunction with the consolidated financial statements and the notes
        thereto for the year ended December 31, 2006.

    3.  Changes in Accounting Policy

        a) Financial Instruments and Hedging Activities

        Effective January 1, 2007, the Trust adopted the CICA Handbook
        section 3855, "Financial Instruments - Recognition and Measurement";
        section 3865, "Hedges"; section 1530, "Comprehensive Income"; and
        section 3861, "Financial Instruments - Disclosure and Presentation."
        The Trust has adopted these standards prospectively and the
        comparative interim consolidated financial statements have not been
        restated. Transition amounts have been recorded in deficit or
        accumulated other comprehensive income.


        i) Financial Instruments
        All financial instruments must initially be recognized at fair value
        on the balance sheet. The Trust has classified each financial
        instrument into the following categories: held-for-trading financial
        assets and financial liabilities, loans or receivables, held to
        maturity investments, available for sale financial assets, and other
        financial liabilities. Subsequent measurement of the financial
        instruments is based on their classification. Unrealized gains and
        losses on held-for-trading financial instruments are recognized in
        earnings. Gains and losses on available for sale financial assets are
        recognized in other comprehensive income and are transferred to
        earnings when the asset is derecognized. The other categories of
        financial instruments are recognized at amortized cost using the
        effective interest rate method.

        Upon adoption and with any new financial instrument, an irrevocable
        election is available that allows entities to classify any financial
        asset or financial liability as held for trading, even if the
        financial instrument does not meet the criteria to designate it as
        held for trading.

        For financial assets and financial liabilities that are not
        classified as held for trading, the transaction costs that are
        directly attributable to the acquisition or issue of a financial
        asset or financial liability are added to the fair value initially
        recognized for that financial instrument. These costs are expensed to
        earnings using the effective interest rate method.

        The following is a summary of the accounting classification the Trust
        has elected to apply to each of its significant categories of
        financial instruments outstanding as of January 1, 2007 and June 30,
        2007:
        -  Cash designated as held for trading;
        -  Accounts receivable designated as loans and receivables;
        -  Accounts payable and accrued liabilities and distributions payable
           designated as other liabilities;
        -  Bank debt designated as held for trading; and
        -  Convertible debentures designated as other liabilities.

        The Trust currently does not have any financial assets classified as
        available for sale or held to maturity.

        ii) Derivative Instruments and Hedging Activities
        Derivative instruments are utilized by the Trust to manage market
        risk against the volatility in commodity prices. The Trust's policy
        is not to utilize derivative instruments for speculative purposes.
        The Trust may choose to designate derivative instruments as hedges.
        Hedge accounting continues to be optional.

        Section 3865 of the CICA Handbook specifies the criteria that must be
        satisfied in order for hedge accounting to be applied and the
        accounting for each of the permitted hedging strategies: fair value
        hedges and cash flow hedges. Hedge accounting is discontinued
        prospectively when the derivative no longer qualifies as an effective
        hedge, or the derivative is terminated or sold, or upon the sale or
        early termination of the hedged item.

        As a result of the adoption of CICA Handbook section 3855, the Trust
        chose to de-designate hedges outstanding at December 31, 2006. The
        fair value of these de-designated hedges is reflected on the balance
        sheet in accumulated other comprehensive income and recognized though
        income over the remaining term of the hedge item. In addition, as
        with any other derivative in which hedge accounting is not used, any
        changes in fair value from the adoption date to the reporting date
        are immediately recognized through income.

        The fair value of a financial instrument is the amount of
        consideration that would be agreed upon in an arm's-length
        transaction between knowledgeable, willing parties who are under no
        compulsion to act. The fair value of a financial instrument on
        initial recognition is the transaction price, which is the fair value
        of the consideration given or received. Subsequent to initial
        recognition, the fair values of financial instruments that are quoted
        in active markets are based on bid prices for financial assets held
        and offer prices for financial liabilities. When independent prices
        are not available, fair values are determined by using valuation
        techniques which refer to observable market data.

        iii) Embedded Derivatives
        Embedded derivatives are derivatives embedded in a host contract.
        They are recorded separately from the host contract when their
        economic characteristics and risks are not clearly and closely
        related to those of the host contract, the terms of the embedded
        derivatives are the same as those of a freestanding derivative and
        the combined contract is not classified as held for trading or
        designated at fair value. The Trust has selected January 1, 2003 as
        its transition date for accounting for any potential embedded
        derivatives. As at June 30, 2007 and December 31, 2006, the value of
        the identified embedded derivatives is zero.

        iv) Comprehensive Income
        Comprehensive income consists of net earnings and other comprehensive
        income ("OCI"). OCI comprises the change in the fair value of the
        effective portion of the derivatives used as hedging items in a cash
        flow hedge and the change in fair value of any available for sale
        financial instruments. Amounts included in OCI are shown net of tax.
        Accumulated other comprehensive income is a new equity category
        comprised of the cumulative amounts of OCI.

        v) Transitional adjustment
        As required, these standards have been applied as an adjustment to
        opening deficit and AOCI. Prior-period balances have not been
        restated. The impact of adopting these standards as at January 1,
        2007 was as follows:

                                       December 31,                January 1,
                                              2006     Adoption         2007
                                      (As reported)  adjustment (As restated)
        ---------------------------------------------------------------------
        Assets
          Accounts receivable               29,074         (126)      28,948
          Fair value of derivative
           instruments                         874        2,391        3,265
          Deferred charges                   4,167       (4,167)           -
        Liabilities
          Bank debt                        102,300         (126)     102,174
          Convertible debentures           100,548       (3,071)      97,477
          Future income tax liability        4,296          373        4,669
        Unitholders' Equity
          Deficit                         (171,458)        (673)    (172,131)
          Accumulated other
           comprehensive income                  -        1,595        1,595
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        b) Accounting Changes

        Effective January 1, 2007, the Trust adopted the revised
        recommendations of CICA Handbook section 1506, "Accounting Changes."
        The new recommendations permit voluntary changes in accounting policy
        only if they result in financial statements which provide more
        reliable and relevant information. Accounting policy changes are
        applied retrospectively unless it is impractical to determine the
        period or cumulative impact of the change. Corrections of prior
        period errors are applied retrospectively and changes in accounting
        estimates are applied prospectively by including these changes in
        earnings. The guidance was effective for all changes in accounting
        policies, changes in accounting estimates and corrections of prior-
        period errors initiated in periods beginning on or after January 1,
        2007.

        c) Future Accounting Changes

        On December 1, 2006, the CICA issued three new accounting standards:
        Section 1535, Capital Disclosures; Section 3862, Financial
        Instruments - Disclosures; and Section 3863, Financial Instruments -
        Presentation. These new standards will be effective on January 1,
        2008.

        Section 1535 specifies the disclosure of an entity's objectives,
        policies and processes for managing capital, quantitative data about
        what the entity regards as capital, whether the entity has complied
        with any capital requirements, and if it has not complied, the
        consequences of such non-compliance. This Section is expected to have
        minimal impact on the Trust's financial statements.

        Sections 3862 and 3863 specify a revised and enhanced disclosure on
        financial instruments. These sections will require the Trust to
        increase disclosure on the nature and extent of the risks arising
        from financial instruments and how the entity manages those risks.

    4.  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:

        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
        ---------------------------------------------------------------------
        Issue of 27,550,058 Trust units                              224,822
        Issue of 1,208,323 Series D exchangeable shares                9,861
        Acquisition costs                                              4,950
        ---------------------------------------------------------------------
                                                                     239,633
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        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.

    5.  Property, Plant and Equipment ("PP&E")

                                                                    Net book
        $000s                                 Cost  Accumulated        value
        ---------------------------------------------------------------------
        June 30, 2007
        Property, plant and equipment    1,054,926      551,162      503,764
        Other                                4,425        3,014        1,411
        ---------------------------------------------------------------------
                                         1,059,351      554,176      505,175
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        December 31, 2006
        Property, plant and equipment    1,029,672      508,639      521,033
        Other                                4,016        2,701        1,315
        ---------------------------------------------------------------------
                                         1,033,688      511,340      522,348
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        At June 30, 2007, $54.7 million (December 31, 2006 - $56.7 million)
        of costs relating to unproved properties were excluded from costs
        subject to depletion. During the three months ended June 30, 2007,
        $2.2 million (year ended December 31, 2006 - $5.3 million) of general
        and administrative expenses relating to exploration and development
        activities were capitalized. At June 30, 2007, $1.7 million
        (December 31, 2006 - $0.9 million) of assets under capital lease have
        been included as part of PP&E (see Note 8).

    6.  Goodwill

        The Trust assessed goodwill for impairment at March 31, 2007 and
        determined that the fair value of the reporting unit had declined due
        to current declines in fair market value valuations given to similar
        energy trusts and due to the Trust seeking strategic alternatives
        (Note 22). The Trust recorded an impairment charge of $91.3 million
        (2006 - $Nil). The following table reconciles the goodwill balance:

                                                                       $000s
        ---------------------------------------------------------------------
        Balance - December 31, 2006                                   91,295
        Impairment of goodwill                                       (91,295)
        ---------------------------------------------------------------------
        Balance - March 31, 2007                                           -
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    7.  Bank Debt

        At June 30, 2007, the Trust had a credit facility with a syndicate of
        chartered banks consisting of a $115.0 million extendible revolving
        term credit facility and a $20.0 million extendible operating credit
        facility (see Note 22). 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. At
        June 30, 2007, $113.4 million was drawn on the facilities
        (December 31, 2006 - $102.3 million). 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; (ii) where outstanding borrowings exceed the
        borrowing base agreed to by the lenders; and (iii) a restriction was
        placed on making distributions where the distribution is in excess of
        100 percent of distributable cash as defined by the credit facility.
        The approximate effective rate on bank debt was 6.5 percent for the
        three months ended June 30, 2007 (June 30, 2006 - 5.6 percent). For
        the six months ended June 30, 2007, the approximate effective
        interest rate was 6.2 percent (June 30, 2006 - 5.4 percent).

    8.  Lease Obligations and Commitments

        In 2006, the Trust entered into two three-year capital leases for
        compressors with payment commitments over the next four years as
        follows:

                                                                      ($000s)
        ---------------------------------------------------------------------
        2007                                                             187
        2008                                                             376
        2009                                                             816
        2010                                                             427
        ---------------------------------------------------------------------
                                                                       1,806
        Less imputed interest at 7.3 percent and 6.3 percent            (219)
        ---------------------------------------------------------------------
        Present value of the minimum lease payments                    1,587
        Less current portion                                            (324)
        ---------------------------------------------------------------------
                                                                       1,263
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The Trust has assumed the following commitments, as detailed in the
        table below:
                                  Less than                            After
        $000s              Total     1 year  1-3 years  4-5 years    5 years
        ---------------------------------------------------------------------
        Transportation
         agreements        3,062      1,968      1,094          -          -
        Operating leases   6,793      1,532      2,687      1,873        701
        ---------------------------------------------------------------------
                           9,855      3,500      3,781      1,873        701
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    9.  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 4). Total amortization for the
        period ended June 30, 2007 is $47,000.

    10. Convertible Debentures

        Upon adoption of the financial instruments CICA Handbook section
        3855, "Financial Instruments - Recognition and Measurement" at
        January 1, 2007, deferred charges are now netted against the cost of
        the convertible debentures and amortization of deferred charges is
        calculated using the effective interest method rather than straight-
        line amortization.

        $000s,                                           Deferred
         except unit information      Units  Principal    Charges      Total
        ---------------------------------------------------------------------
        8.75% Convertible Debentures
        Balance - December 31, 2006  59,513     59,513     (1,366)    58,147
        Adoption of financial
         instruments (Note 3)             -          -        (17)       (17)
        Amortization                      -          -        274        274
        ---------------------------------------------------------------------
        Balance - June 30, 2007      59,513     59,513     (1,109)    58,404
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        8.0% Convertible Debentures
        Balance - December 31, 2006  41,035     41,035     (1,680)    39,355
        Adoption of financial
         instruments (Note 3)             -          -         (8)        (8)
        Additions                         -          -       (156)      (156)
        Amortization                      -          -        178        178
        ---------------------------------------------------------------------
        Balance -  June 30, 2007     41,035     41,035     (1,666)    39,369
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Total outstanding           100,548    100,548     (2,775)    97,773
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    11. 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
        ---------------------------------------------------------------------
        Asset retirement obligation, December 31, 2006                31,083
        Liabilities incurred                                           2,603
        Liabilities settled                                           (2,202)
        Accretion of asset retirement obligation                       1,121
        ---------------------------------------------------------------------
        Asset retirement obligation, June 30, 2007                    32,605
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        At June 30, 2007, the total undiscounted asset retirement obligation
        is estimated to be $64.7 million (December 31, 2006 - $62.5 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.

    12. 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 June 30, 2007, there were no Plan
        Units outstanding (June 30, 2006 - 708,001 Plan Units). For the six
        months ended June 30, 2006, compensation expense of $1.0 million was
        included in general and administrative expenses and $0.7 million was
        included as capitalized general and administrative outlays. The
        accrued long-term portion of the Trust's $2.7 million liability for
        the long-term incentive plan included in other long-term liabilities
        was $1.2 million at June 30, 2006.

    13. Income Taxes

        On June 12, 2007, the legislation implementing the new tax on
        publicly traded income trusts and limited partnerships (the "SIFT
        tax"), referred to as "Specified investment flow-through" ("SIFT")
        entities (Bill C-52), received third reading in the House of Commons
        and on June 22, 2007, the bill received Royal Assent. As a result,
        the SIFT tax was considered to be enacted for accounting purposes in
        June 2007. This change resulted in the recognition of a future income
        tax liability and expense of $8.7 million. This is a non-cash expense
        relating to temporary differences between the accounting and tax
        basis of Sound's assets and liabilities and has no immediate impact
        on the Trust's cash flows.

    14. 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 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 June 30, 2007, the exchange ratio of the Series A exchangeable
        shares was 1.73447, for the Series B exchangeable shares was 1.70866,
        and for the Series D exchangeable shares was 1.16508. The total
        number of Trust units that the exchangeable shares would be converted
        into at June 30, 2007 using these exchange ratios would be 1,496,046.
        The Series D exchangeable shares were issued pursuant to the Plan or
        Arrangement effective August 14, 2006 (see Note 4).

        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.

                                         Number of  Convertible
        Non-controlling interest            shares   to units(1)       $000s
        ---------------------------------------------------------------------
        Series A
        Balance - December 31, 2006        265,043      418,757        3,116
        Non-controlling interest in
         net loss                                -            -         (802)
        Adjustment to exchange ratio             -       40,952            -
        ---------------------------------------------------------------------
        Balance - June 30, 2007            265,043      459,709        2,314
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Series B
        Balance - December 31, 2006          3,145        4,895           29
        Non-controlling interest in
         net loss                                -            -           (9)
        Adjustment to exchange ratio             -          479            -
        ---------------------------------------------------------------------
        Balance - June 30, 2007              3,145        5,374           20
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Series D
        Balance - December 31, 2006      1,092,886    1,159,869        8,971
        Exchanged for trust units         (208,000)    (233,611)      (1,551)
        Non-controlling interest in
         net loss                                -            -       (1,957)
        Adjustment to exchange ratio             -      104,705            -
        ---------------------------------------------------------------------
        Balance - June 30, 2007            884,886    1,030,963        5,463
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Total outstanding                1,153,074    1,496,046        7,797
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (1)   The conversion ratios used at June 30, 2007, December 31, 2006
              and for exchanges that occurred during the period are specific
              to the dates represented or when the transaction occurred.


    15. Unitholders' Capital

        (a) Authorized

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

        (b) Issued and outstanding

        Unit capital                          Number of units   Value ($000s)
        ---------------------------------------------------------------------
        Balance - December 31, 2006                56,849,413        522,211
        Issued on conversion of Series D
         exchangeable shares                          233,611          1,551
        Issued pursuant to the distribution
         reinvestment plan                            358,290          1,472
        ---------------------------------------------------------------------
        Balance - June 30, 2007                    57,441,314        525,234
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        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 the 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

        No compensation expense was recorded by the Trust for the three
        months ended June 30, 2007 (June 30, 2006 - $0.3 million). The
        compensation expense is based on the fair value of rights issued and
        is amortized over the remaining vesting period of such rights as
        general and administrative expense and included in contributed
        surplus.

                                                                    Weighted
                                                                     average
                                                    Number of       exercise
        Trust Unit Rights                              rights       price ($)
        ---------------------------------------------------------------------
        Balance - December 31, 2006 before
         reduction of exercise price                  107,917          10.29
        Cancelled                                      (4,000)          6.31
        ---------------------------------------------------------------------
        Balance -June 30, 2007 before reduction of
         exercise price                               103,917          10.27
        Reduction in exercise price for cumulative
         distributions                                      -          (3.92)
        ---------------------------------------------------------------------
        Balance - June 30, 2007                       103,917           6.35
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Exercisable - June 30, 2007                   103,917           6.35
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (d) Unit Award Incentive Plan

        As a result of the Plan of Arrangement, on August 14, 2006, the
        Unitholders of Sound approved the Unit Award Incentive Plan. This
        plan authorizes the Board 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 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 six months ended June 30, 2007:

                                        Restricted  Performance
                                       Trust Units  Trust Units        Total
        ---------------------------------------------------------------------
        Balance - December 31, 2006      2,027,200            -    2,027,200
        Granted                            275,205            -      275,205
        Cancelled                          (54,000)           -      (54,000)
        ---------------------------------------------------------------------
        Balance - June 30, 2007          2,248,405            -    2,248,405
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        RTUs vest annually over one or three-year periods 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 2007 was $6.86 per unit.

        The Trust recorded compensation expense of $2.5 million and
        $5.9 million for the three months and six months ended June 30, 2007,
        respectively, as compared to $Nil and $Nil, respectively, during the
        same periods in 2006. Unit-based compensation is included in
        contributed surplus as the cost associated with the rights.

        As of June 30, 2007, no PTUs have been granted. Based upon the number
        of RTUs outstanding at June 30, 2007 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 June 30, 2007,
        the Trust, using the June 29, 2007 closing price of $4.04/unit, would
        have recorded additional compensation expenses of $2.4 million.

    (e) Per-unit amounts

        The per-unit amounts for the three months and six months ended
        June 30, 2007 and 2006 were calculated based on the following
        weighted average number of units outstanding:

                                  Three months ended        Six months ended
                                             June 30                 June 30
                                    2007        2006        2007        2006
        ---------------------------------------------------------------------
        Basic                 57,317,969  28,442,628  57,144,049  28,416,313
        Trust rights incentive
         plan                          -     196,552           -      98,801
        Series A exchangeable
         shares (Note 14)              -     385,006           -     385,006
        Series B exchangeable
         shares (Note 14)              -       4,497           -       4,497
        ---------------------------------------------------------------------
        Diluted               57,317,969  29,028,683  57,144,049  28,904,617
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        For the three months ended June 30, 2007, the following securities
        were excluded from the determination of diluted net income (loss) per
        unit as their inclusion would be anti-dilutive: convertible
        debentures - 12,446,600 (June 30, 2006 - 5,413,000); exchangeable
        shares - 1,496,046 (June 30, 2006 - Nil); RTUs - 2,248,405 (June 30,
        2006 - Nil); and the Rights Plan - 103,917 (June 30, 2006 - 721,199).

        For the six months ended June 30, 2007, the following securities were
        excluded from the determination of diluted net income per unit as
        their inclusion would be anti-dilutive: convertible debentures -
        12,446,600 (June 30, 2006 - 5,413,000); exchangeable shares -
        1,496,046 (June 30, 2006 - Nil); RTUs - 2,248,405 (June 30, 2006 -
        Nil); and the Rights Plan - 103,917 (June 30, 2006 - 820,950).

        (f) Contributed surplus

                                                                       $000s
        ---------------------------------------------------------------------
        Balance - December 31, 2006                                    4,995
        Compensation expense                                           5,926
        ---------------------------------------------------------------------
        Balance - June 30, 2007                                       10,921
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    16. 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 six months ended June 30, 2007:

                                                          $/Unit       $000s
        ---------------------------------------------------------------------
        January 31, 2007                                   0.100       5,692
        February 28, 2007                                  0.055       3,135
        March 31, 2007                                     0.055       3,144
        April 30, 2007                                     0.055       3,152
        May 31, 2007                                       0.055       3,156
        June 30, 2007                                      0.055       3,159
        ---------------------------------------------------------------------
        Total                                              0.375      21,438
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        At June 30, 2007, distributions of $3,159,000 were payable to
        Unitholders for the month of June 2007. The cash distributions paid
        in the period were $24.0 million for those declared in the December
        2006 to May 2007 period.

        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).

    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. The fair value of convertible debentures at
        June 30, 2007 using the last available closing price prior to that
        date is $100.4 million.

        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 June 30, 2007, 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:

                                                                        Fair
                                                                       Value
                       Period       Volume      Strike prices  Index  ($000s)
        ---------------------------------------------------------------------
        Oil price  Jan. 1, 2007    500 bbl/d    US$70.00/bbl    WTI       63
         collar     to Dec. 31,                 to US$74.30/bbl
                    2007
        Oil price  Mar. 1, 2007  1,000 bbl/d    US$57.00/bbl    WTI     (734)
         collar     to Dec. 31,                 to US$70.00/bbl
                    2007
        Oil price  Apr. 1, 2007    500 bbl/d    US$60.00/bbl    WTI     (271)
         collar     to Dec. 31,                 to US$71.50/bbl
                    2007
        Gas price  Mar. 1, 2007  10,000 GJ/d(1) $7.50/GJ        AECO   2,635
         collar     to Dec. 31,                 to $9.00/GJ(1)
                    2007
        Gas price  May 1, 2007    5,000 GJ/d(1) $7.50/GJ        AECO   1,326
         collar     to Dec. 31,                 to $9.00/GJ(1)
                    2007
        (1)   GJs convert to Mcf at a rate of 1.055056:1.


                                      Three months ended    Six months ended
        $000s                                    June 30             June 30
                                          2007      2006      2007      2006
        ---------------------------------------------------------------------
        Realized derivative gain           872         -     2,346         -
        Unrealized derivative gain       3,937         -     1,247         -
        ---------------------------------------------------------------------
        Total                            4,809         -     3,593         -
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


    18. Supplementary Cash Flow Information

                                      Three months ended    Six months ended
        $000s                                    June 30             June 30
                                          2007      2006      2007      2006
        ---------------------------------------------------------------------
        Interest paid on bank debt       1,478     1,121     3,623     1,878
        Interest paid on convertible
         debentures                      4,601     2,605     4,601     5,210
        Taxes paid                         413       247       783       602
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    19. Related-Party Transactions

        Sure Energy is a related party of Sound as three directors of Sure
        Energy sit on the Board of the Company 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 received and to be received from
        Sure Energy by the Trust totaled $286,000 and $509,000 for the three
        and six months ended June 30, 2007, respectively, of which $187,000
        is receivable at the end of the period. Amounts paid and to be paid
        from the Trust to Sure Energy totaled $250,000 and $509,000 for the
        three months and six months ended June 30, 2007 of which $14,000 is
        payable at the end of the period. Also, Sure Energy was charged by
        Sound $85,000 and $168,000 for the for the three and six months ended
        June 30, 2007, respectively, for rent, business taxes and parking.
        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.

    20. 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.

    21. 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.

    22. Subsequent Events

        On July 9, 2007, Advantage and Sound announced that their respective
        boards of directors had approved a business combination. The
        transaction would be accomplished through a Plan of Arrangement by
        the exchange of each Sound Trust unit for 0.30 of an Advantage Trust
        unit or, at the election of the Sound Unitholder, $0.66 in cash
        and 0.2557 of an Advantage Trust unit. Successful completion of the
        Arrangement is subject to stock exchange, court and regulatory
        approvals and the approval by at least two-thirds of Sound's
        Unitholders and Sound Exchangeable Shareholders. It is anticipated
        that the Sound Unitholder meeting required to approve the Arrangement
        will be held on September 5, 2007, with the Arrangement closing
        shortly thereafter.

        On July 18, 2007 the Trust closed a transaction to dispose of certain
        properties in the Maple Glen and Strathmore areas for approximately
        $13.0 million effective April 1, 2007 to a private oil and gas
        company. As a result, the borrowing base was reduced by $5.0 million
        to $130.0 million consisting of a $110.0 million extendible revolving
        term credit facility and a $20.0 million extendible operating credit
        facility (see Note 7).

        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. Debentures of Sound trade on the TSX under the symbols
        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 statements.
    


    %SEDAR: 00020262E




For further information:

For further information: Anne-Marie Buchmuller, Manager, Investor
Relations, Phone: (403) 218-3664, Toll-free: 1-888-414-4144, Cell: (403)
472-0053, Email: investorrelations@soundenergytrust.com,
www.soundenergytrust.com

Organization Profile

SOUND ENERGY TRUST

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