Focus Energy Trust announces Q3 financial & operating results



    CALGARY, Nov. 8 /CNW/ - Focus Energy Trust ("Focus") (FET.UN - TSX)
announces its consolidated financial and operating results for the third
quarter ending September 30, 2007.

    
    Consolidated Highlights

    (thousands of                 Three Months           Nine Months
     dollars, except            Ended Sept. 30,       Ended Sept. 30,
     where indicated)          2007       2006       2007       2006  Change
    -------------------------------------------------------------------------
    FINANCIAL
    Production revenue
     and financial
     commodity contract
     settlements(1)          89,044     90,395    284,607    187,204     52%
    Funds flow from
     operations(2)           60,026     60,134    187,220    116,810     60%
      Per unit(3)(4)      $    0.76  $    0.77  $    2.37  $    2.25      5%
    Cash distributions
      Per unit            $    0.42  $    0.48  $    1.26  $    1.62   (22)%
      Payout ratio
       (per-unit basis)         55%        63%        53%        72%   (19)%
    Net income               19,138     12,670     48,676     51,321    (5)%
      Per unit            $    0.24  $    0.19  $    0.62  $    1.08   (43)%
    Capital
     expenditures(5)         25,624     36,459     84,129     63,420     33%
    Acquisitions(5)             278          -      4,251  1,091,294  (100)%
    Long-term debt less
     working capital(8)     301,486    313,390    301,486    313,390    (4)%
      Increase (decrease)
       for the period        (3,737)    15,939     (6,472)   220,872
    Total Trust Units
     - outstanding
     (000's)(4)              79,491     78,425     79,491     78,425      1%
    Weighted average
     Total Trust Units
     (000's)(6)              79,311     78,399     78,956     51,892     52%
    -------------------------------------------------------------------------
    OPERATIONS
    Average daily
     production
      Crude oil (bbls/d)      1,750      1,844      1,819      1,673      9%
      NGLs (bbls/d)             913        740        852        735     16%
      Natural gas (mcf/d)   109,728    115,612    113,588     69,425     64%
      Barrels of oil
       equivalent (at 6:1)   20,951     21,853     21,602     13,980     55%
    Average product
     prices realized(7)
      Crude oil
       (CDN$/bbl)         $   74.18  $   70.09  $   68.02  $   68.81    (1)%
      NGLs (CDN$/bbl)     $   61.25  $   66.56  $   59.43  $   64.00    (7)%
      Natural gas
       (CDN$/mcf)         $    6.83  $    6.75  $    7.32  $    7.14    (3)%
    Field netback per BOE
      Revenue(7)          $   44.68  $   43.92  $   46.60  $   47.12    (1)%
      Royalties           $   (6.87) $   (8.37) $   (8.28) $   (9.52)  (13)%
      Production expenses $   (3.84) $   (3.50) $   (4.02) $   (4.24)   (5)%
      Field netback       $   33.97  $   32.04  $   34.31  $   33.36      3%
    Wells drilled
      Gross                     143        154        349        171    104%
      Net                     119.0      128.6      275.0      144.0     90%
      Success rate             100%       100%       100%       100%
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    TRUST UNIT TRADING
     STATISTICS
    Unit prices
      High                $   17.83  $   25.09  $   20.41  $   25.89
      Low                 $   16.68  $   20.85  $   16.19  $   20.31
      Close               $   17.46  $   21.25  $   17.46  $   21.25   (18)%
    Daily average
     trading volume         162,056    282,942    191,202    199,258    (4)%
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    -------------------------------------------------------------------------

    (1) Production revenue includes settlements for financial commodity
        contracts. For 2007, it excludes any unrealized gains or losses
        recorded for financial commodity contracts and excludes the
        reclassification to earnings of gains on hedges held at January 1,
        2007.

    (2) Funds flow from operations ("funds flow" before changes in non-cash
        working capital and reclamation costs) is used by management to
        analyze operating performance and leverage. Funds flow 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 of other entities. Funds flow as presented is not
        intended to represent operating cash flow or operating profits for
        the period nor should it be viewed as an alternative to cash flow
        from operating activities, net earnings or other measures of
        financial performance calculated in accordance with Canadian GAAP.
        All references to funds flow throughout this report are based on
        funds flow from operations before changes in non-cash working capital
        and reclamation costs.

    (3) Based on the weighted average Total Trust Units outstanding for the
        period.

    (4) Total Trust Units being trust units, exchangeable partnership units,
        and exchangeable shares converted at the exchange ratio prevailing at
        the time. Total Trust Units 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 of other
        entities. The exchange ratio for exchangeable shares was 1.44137 at
        September 30, 2006. All outstanding exchangeable shares were redeemed
        for trust units on January 16, 2007. Each exchangeable partnership
        unit is exchangeable into one trust unit.

    (5) Cost of capital expenditures and acquisitions excluding any asset
        retirement obligation or future income tax.

    (6) Weighted average Total Trust Units including trust units,
        exchangeable partnership units and exchangeable shares converted at
        the average exchange ratio.

    (7) Includes settlements for financial commodity contracts and net of
        transportation charges. For 2007, it excludes any unrealized gains or
        losses recorded for financial commodity contracts and excludes the
        reclassification to earnings of gains on hedges held at January 1,
        2007.

    (8) Long-term debt less working capital excludes any derivative asset or
        derivative liability. At September 30, 2007, there was a
        $16.8 million derivative asset as compared to a derivative liability
        of $0.2 million at December 31, 2006.
    

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

    Forward-Looking Information - Certain information set forth in this
    document, including management's assessment of Focus' future plans and
    operations, contains forward-looking statements. By their nature,
    forward-looking statements are subject to numerous risks and
    uncertainties, some of which are beyond Focus' control, including the
    impact of general economic conditions, industry conditions, changes in
    legislation, volatility of commodity prices, currency fluctuations,
    imprecision of reserve estimates, environmental risks, competition from
    other industry participants, the lack of availability of qualified
    personnel or management, stock market volatility and ability to access
    sufficient capital from internal and external sources. Readers are
    cautioned that the assumptions used in the preparation of such
    information, although considered reasonable at the time of preparation,
    may prove to be imprecise and, as such, undue reliance should not be
    placed on forward-looking statements. Focus' actual results, performance
    or achievement could differ materially from those expressed in, or
    implied by, these forward-looking statements and, accordingly, no
    assurance can be given that any of the events anticipated by the
    forward-looking statements will transpire or occur, or if any of them do,
    what benefits Focus will derive therefrom. Focus disclaims any intention
    or obligation to update or revise any forward-looking statements, whether
    as a result of new information, future events or otherwise. Readers are
    cautioned that net present value of reserves does not represent fair
    market value of reserves.

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

    
    Highlights
    -------------------------------------------------------------------------
    -   During the third quarter Focus continued to execute on our
        sustainable business model. In spite of lower natural gas prices, we
        were able to realize strong netbacks, allowing us to deploy capital
        to replace production while at the same time maintaining
        distributions to unitholders. Funds flow from operations in the first
        three quarters of 2007 has essentially funded field capital
        expenditures of $84.1 million, distributions to unitholders of
        $99.8 million and $4.5 million of contributions to the reclamation
        fund.

    -   Third quarter netbacks of $33.97 per BOE were a result of strong
        realized natural gas prices and low operating, royalty and general
        and administrative costs.

    -   Natural gas hedging programs generated $17.8 million of incremental
        revenue in Q3 2007 ($32.1 million year-to-date), providing additional
        certainty to our distribution and capital programs.

    -   Field capital costs continue to drop and are being complemented by
        increased service efficiency.

    -   We have continued our successful program of selective acquisitions
        around our core areas, increasing our working interest in 48 (20 net)
        sections of land at our new Trutch Halfway gas pool adjacent to Tommy
        Lakes.

    -   Third quarter funds flow from operations of $0.76/unit was down
        five percent from $0.80/unit in Q2 2007, in a quarter where the
        average AECO daily reference price for natural gas decreased by
        27 percent.
    

    Message to Unitholders
    -------------------------------------------------------------------------
    In Q3 the majority of our capital program was focused on the Shackleton
field with the drilling of 143 (119 net) Milk River gas wells with 100 percent
success. We were active expanding the pool boundaries on the west side of the
Shackleton field at Sceptre and on the east side at Tyner. Activity in the
developed parts of the pool focused on increasing the drilling density from
four to eight wells per section, with the drilling of approximately 80 wells
from our 1000+ well inventory. We are pleased with the success of these
programs from both a cost and production perspective. These programs have
improved our understanding of the pool and its ultimate reserve potential, as
well as providing additions to our drilling inventory.
    Funds flow from operations remained strong in the third quarter of 2007
at $60.0 million, reflecting continued support from natural gas price
protection activities, low production expenses and low general and
administrative costs. Our realized natural gas price of $6.83 per mcf in Q3
2007 was 32 percent higher than the average AECO daily reference price of
$5.18 per mcf, demonstrating the positive contribution of our natural gas
hedging program.
    Operating costs in the third quarter were $3.84 per BOE, up slightly from
the $3.71 per BOE in Q2 2007. Our operating costs continue to be among the
lowest in the trust sector. We continue to see field capital cost reductions
and improvements in service efficiency, largely driven by reduced gas-directed
drilling activity levels in the Western Canadian Sedimentary Basin. We expect
to see these positive trends continue throughout the first half of 2008.

    Outlook
    -------------------------------------------------------------------------
    Throughout the third quarter we have seen continued deterioration in the
natural gas price as the North American gas supply adjusts to increased levels
of LNG being delivered to the east coast of the United States and growing U.S.
domestic supply. Focus was built not only to survive but to prosper during
these volatile natural gas markets. We have strong hedge positions with over
50 percent of gas hedged for Q4 2007 and Q1 2008 at $8.56 per mcf. Our
royalty, operating, general and administrative, and interest cost structures
are among the lowest in the sector and reflect our continued focus on the
aspects of our business that we can control. Combined, these factors result in
high netbacks supporting our significant capital and distribution programs.
Our inventory of drilling opportunities continues to expand and we have three
years of drilling inventory at our current pace. This inventory generates
economic rates of return at a flat $5.00 per mcf natural gas price. We have a
conservative debt position with debt-to-funds-flow of 1.2 times and our
sustainable business model ensures that we live within our funds flow and that
only the best projects get capitalized.
    On October 25, 2007, the Alberta government released details of a new
royalty framework for Alberta. This new framework is effective January 1, 2009
and will result in a significant increase in Crown royalties paid by Alberta
producers. Focus' exposure to Alberta is limited to approximately 13 percent
of our total production and we estimate that the impact to the Trust's funds
flow will be less than two percent.
    Our capital program in the first half of Q4 involves the completion and
tie-in of all wells remaining from the summer program. Later in the quarter we
will kick off our Shackleton winter drilling program, which is focused on
environmentally sensitive areas with winter-only access. The latter part of
the quarter will also see the start of our 15-well 2007/2008 Tommy Lakes
winter drilling program.
    The Trust is in excellent shape, largely unaffected by the Alberta
royalty decision and with our capex and distribution programs well supported
by a strong hedging position. We believe natural gas prices have bottomed and
we expect to see a sustained recovery in prices throughout 2008. The
combination of improving gas prices and better cost efficiencies from the
service sector should positively impact our profitability and funds flow as we
move into 2008.
    I would like to thank all of our unitholders for their ongoing support
and confidence in Focus.

    On behalf of the Board of Directors,

    (signed)

    Derek W. Evans
    President and Chief Executive Officer


    Management's Discussion and Analysis
    -------------------------------------------------------------------------
    The following is Management's Discussion and Analysis (MD&A) of the
operating and financial results of Focus for the three months and nine months
ended September 30, 2007 compared with the prior year, as well as information
and opinions concerning the Trust's future outlook based on currently
available information. This discussion is dated November 6, 2007 and should be
read in conjunction with the annual MD&A and the audited consolidated
financial statements for the years ended December 31, 2006 and 2005, together
with accompanying notes.
    Throughout the MD&A, we use the term funds flow from operations ("funds
flow" before changes in non-cash working capital and reclamation costs). Funds
flow is used by management to analyze operating performance and leverage.
Funds flow 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 of other entities. Funds flow as presented is not intended to
represent operating cash flow or operating profits for the period nor should
it be viewed as an alternative to cash flow from operating activities, net
earnings or other measures of financial performance calculated in accordance
with Canadian GAAP. All references to funds flow throughout this report are
based on funds flow from operations before changes in non-cash working capital
and reclamation costs.

    
                                          Three Months           Nine Months
                                        Ended Sept. 30,       Ended Sept. 30,
    OPERATIONS SUMMARY                 2007       2006       2007       2006
    -------------------------------------------------------------------------
    Average daily production
      Barrels of oil equivalent
       (at 6:1)                      20,951     21,853     21,602     13,980
      % of Natural gas                  87%        88%        88%        83%
    Average product prices
     realized
      Crude oil sales (CDN$/bbl)  $   76.15  $   74.16  $   68.54  $   72.28
        Financial commodity
         contract settlements
         (CDN$/bbl)               $   (1.98) $   (4.07) $   (0.52) $   (3.47)
    -------------------------------------------------------------------------
        Realized price (CDN$/bbl) $   74.18  $   70.09  $   68.02  $   68.81
    -------------------------------------------------------------------------
      NGLs (CDN$/bbl)             $   61.25  $   66.56  $   59.43  $   64.00
      NGL price/crude oil price         80%        90%        87%        89%
      Natural gas sales
       (CDN$/mcf)                 $    5.87  $    6.11  $    6.89  $    6.77
        Transportation system
         charges (CDN$/mcf)       $   (0.29) $   (0.32) $   (0.31) $   (0.46)
        Financial commodity
         contract settlements
         (CDN$/mcf)               $    1.25  $    0.96  $    0.75  $    0.82
    -------------------------------------------------------------------------
        Realized price (CDN$/mcf) $    6.83  $    6.75  $    7.32  $    7.14
    -------------------------------------------------------------------------
    Reference prices &
     differential to Focus sales
     price, after transportation
     and before price protection
      Crude oil (Edm. Light Price
       CDN$/bbl)                  $   79.83  $   81.63  $   72.93  $   76.43
        Differential (CDN$/bbl)   $   (3.67) $   (7.47) $   (4.39) $   (4.14)
      Natural gas (AECO daily
       CDN$/mcf)                  $    5.18  $    5.66  $    6.55  $    6.40
        Differential (CDN$/mcf)   $   (0.11) $   (0.27) $   (0.27) $   (0.51)
    -------------------------------------------------------------------------
    Funds flow from operations
     per BOE
      Production revenue          $   39.82  $   40.86  $   44.37  $   45.71
        Financial commodity
         contract settlements          6.38       4.75       3.89       3.68
        Transportation system
         charges                      (1.52)     (1.69)     (1.65)     (2.27)
    -------------------------------------------------------------------------
      Realized price                  44.68      43.92      46.60      47.12
      Royalties                       (6.87)     (8.37)     (8.28)     (9.52)
      Production expenses             (3.84)     (3.50)     (4.02)     (4.24)
    -------------------------------------------------------------------------
      Field netback                   33.97      32.04      34.31      33.36
      Facility income                  0.29       0.35       0.32       0.62
      General and administrative,
       cash portion                   (0.60)     (0.63)     (0.67)     (0.97)
      Elimination of the
       Executive Bonus Plan               -          -          -      (0.75)
      Interest and financing
       and other                      (2.22)     (1.85)     (2.11)     (1.60)
      Current and large
       corporations tax               (0.30)         -      (0.10)     (0.06)
    -------------------------------------------------------------------------
      Funds flow from operations
       per BOE                    $   31.14  $   29.91  $   31.75  $   30.61
    -------------------------------------------------------------------------
    Funds flow from operations/
     field netback                      92%        93%        93%        92%
    -------------------------------------------------------------------------
    Royalty rate (before financial
     commodity contract settlements)    18%        21%        19%        22%
      Effective royalty rate
       (after financial commodity
       contract settlements)            15%        19%        18%        20%
    -------------------------------------------------------------------------
    Production revenue and financial
     commodity contract settlements
     ($ thousands)
      Crude oil                      12,296     12,618     34,129     33,156
        Financial commodity
         contract settlements          (318)      (691)      (257)    (1,585)
      NGLs                            5,147      4,534     13,823     12,850
      Natural gas, before
       transportation system
       charges                       59,306     64,996    213,690    128,453
        Financial commodity
         contract settlements        12,613     10,239     23,222     15,632
        Non-cash amortization
         of hedging contracts             -     (1,301)         -     (1,301)
    -------------------------------------------------------------------------
        Production revenue and
         financial commodity
         contract settlements        89,044     90,395    284,607    187,204
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Funds flow from operations
     ($ thousands)
      Cash flow from operating
       activities                    56,023     35,682    199,255     88,861
        Reclamation costs               413          -      1,234        285
        Net change in non-cash
         working capital items        3,590     24,452    (13,269)    27,664
    -------------------------------------------------------------------------
        Funds flow from operations   60,026     60,134    187,220    116,810
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Overall Performance
    -------------------------------------------------------------------------
    Results for the third quarter of 2007 continue to reflect the benefits of
our price protection activities at a time of declining reference prices of
natural gas and the emphasis on reinvestment in our core natural gas area of
Shackleton, Saskatchewan.
    The main activity for Focus during the third quarter of 2007 was the
continuation of the development drilling program in the Shackleton field, with
the successful drilling of 143 natural gas wells.
    Funds flow from operations remained relatively strong for the quarter due
to crucial support from natural gas protection activities, despite the
significant decline in the reference price of natural gas. Natural gas
reference prices decreased 27 percent during the quarter, however, price
protection activities added $1.77 per mcf to the realized natural gas price,
resulting in additional revenue of approximately $17.8 million. Production
volumes in the third quarter of 2007 were four percent lower compared with the
second quarter of 2007 and the third quarter of 2006.
    Funds flow from operations for the third quarter of 2007 was
$60.0 million or $0.76 per unit. This compares with $62.8 million or $0.80 per
unit in the second quarter of 2007 and $60.1 million or $0.77 per unit in the
third quarter of 2006. Funds flow from operations per unit for the nine months
ended September 30, 2007 increased five percent compared with the prior year,
driven by a one-and-one-half percent increase in production per unit, a
two-and-one-half percent higher average realized natural gas price and lower
general and administrative expenses on a BOE basis.
    During the quarter, funds flow from operations of $60.0 million plus
$0.7 million of debt financing, funded field capital expenditures of
$25.6 million, distributions of $33.6 million and contributions to the
reclamation fund and reclamation costs of $1.5 million. Long-term debt less
working capital (excluding derivative assets and liabilities) decreased by
$3.7 million during the quarter. This was the net result of receiving
$4.4 million in proceeds from the Distribution Reinvestment and Optional Trust
Unit Purchase Plan ("DRIP Plan") and $0.4 million from the exercise of trust
unit rights, and paying out $0.3 million for acquisitions and $0.7 million for
operations.
    On a year-to-date basis, funds flow from operations of $187.2 million
plus $1.2 million of debt, have funded field capital expenditures of
$84.1 million, distributions of $99.8 million and contributions to the
reclamation fund and reclamation costs of $4.5 million. Long-term debt less
working capital (excluding derivative assets and liabilities) decreased by
$6.5 million. This was a result of receiving $10.6 million in proceeds from
the DRIP Plan and $1.3 million from the exercise of trust unit rights, more
than offsetting the $1.0 million debt funding for operations and $4.3 million
in acquisitions. Focus remains committed to a strong balance sheet and
sustainability whereby capital expenditures and distributions are funded by
funds flow from operations. On a year-to-date basis, Focus has essentially
funded all of its field capital expenditures, distributions to unitholders and
reclamation fund contributions out of funds flow from operations. The ratio of
debt to annualized funds flow from operations is approximately 1.2 times.
    Capital expenditures for the nine months ended September 30, 2007 were
$84.1 million with 96 percent directed towards natural gas. Of the
$80.7 million investment in natural gas properties, 71 percent has been
reinvested at Shackleton with the drilling of 340 gas wells and expansion of
gas processing facilities. A further 29 percent has been reinvested at Tommy
Lakes in British Columbia with the drilling of six wells, a 50-kilometer
seismic program south of the main Halfway pool, tie in of the new Trutch pool
to the northwest of the main Halfway pool and initial costs associated with
the upcoming winter drilling program. Results of our capital programs for the
first nine months remain in line with expectations.
    Net income for the three months ended September 30, 2007 of
$19.1 million, or $0.24 per unit, compared with net income of $12.7 million,
or $0.19 per unit, in the third quarter of 2006. On a year-to-date basis, net
income for the nine months ended September 30, 2007 was $48.7 million, or
$0.62 per unit, compared with net income of $51.3 million, or $1.08 per unit,
in 2006. The significant change from the prior year is primarily due to higher
depletion and depreciation charges resulting from the major acquisition in
June 2006 and the change in accounting policy January 1, 2007 to record the
unrealized gains on commodity contracts.

    Seasonality of Operations
    -------------------------------------------------------------------------
    Prior to the major acquisition of Saskatchewan properties in June 2006,
the majority of Focus' natural gas production was in British Columbia and was
only accessible in the winter. This included Tommy Lakes and Kotcho-Cabin.
These areas represented approximately 70 percent of our production and the
majority of the Trust's capital program. Seasonality resulted in capital
expenditures, overhead recoveries and utilization of bank credit facilities
being highest in the first and fourth quarters of the year. In addition,
higher production volumes, revenue and royalties were reported in Q1 and
production expenses were higher in the first and fourth quarters when the
properties were accessible.
    Subsequent to the major acquisition in June 2006, only about 30 percent
of our natural gas production is from northeast British Columbia and
seasonality is less of a factor on our operations.

    Production
    -------------------------------------------------------------------------
    2007 Q3 compared with 2007 Q2:

    
    -   Average production during the third quarter was 20,951 BOE/d, a
        slight decline compared to 21,894 BOE/d in the second quarter of
        2007. Production was weighted 87 percent towards natural gas,
        four percent towards natural gas liquids and nine percent towards
        crude oil.

    -   Average natural gas production was 109.7 Mmcf per day, a five percent
        decline compared to 115.6 Mmcf per day in the second quarter of 2007.
        Natural gas production at Tommy Lakes was 33.2 Mmcf per day compared
        to 35.5 Mmcf per day in the second quarter of 2007 due to warm
        weather experienced in the summer, repairs and maintenance and new
        wells coming off flush production. Saskatchewan natural gas
        production averaged 68.9 Mmcf per day compared to 71.8 Mmcf per day
        in the second quarter of 2007. The natural decline has been partially
        offset by production from new wells, the majority of which came on
        stream in the last half of Q3.

    -   Oil production fell three percent reflecting natural production
        decline and limited capital investment on crude oil properties.

    2007 Q3 compared with 2006 Q3:

    -   Production in the third quarter of 2006 was 21,853 BOE/d compared to
        20,951 BOE/d in the third quarter of 2007.

    -   Natural gas production declined five percent from 115.6 Mmcf per day
        in the third quarter of 2006 to 109.7 Mmcf per day in the third
        quarter of 2007. Saskatchewan properties contributed 68.9 Mmcf per
        day to third quarter 2007 production and 75.4 Mmcf per day to third
        quarter 2006 production. Production at Tommy Lakes was 33.2 Mmcf per
        day in the third quarter of 2007 compared to 31.7 Mmcf per day in the
        third quarter of 2006.

    -   Oil production declined 94 BOE/d from 1,844 BOE/d in the third
        quarter of 2006 to 1,750 BOE/d in the third quarter of 2007. The
        Saskatchewan properties contributed 274 BOE/d of heavy oil to Q3 2007
        production compared with 292 BOE/d in Q3 2006.

    -   NGL production increased 173 BOE/d from 740 BOE/d in the third
        quarter of 2006 to 913 BOE/d in the third quarter of 2007 due to
        increased recovery of natural gas liquids at our Tommy Lakes and
        Sylvan Lake properties.

    Pricing and Price Risk Management
    -------------------------------------------------------------------------
    Natural Gas Pricing to June 30, 2006 (prior to the major Saskatchewan
acquisition)

    -   Focus had a differential between the realized price compared to the
        AECO average daily reference price resulting from:

        a) a higher than standard heat content of our natural gas at
           1.16 GJ's per mcf;

        b) approximately 83 percent of our natural gas being delivered to
           British Columbia markets which received a lower price;

        c) approximately 83 percent of our natural gas incurring
           transportation system charges in British Columbia which have a
           higher charge per mcf;

        d) the timing differences between how physical gas is sold during the
           period versus the AECO daily average.

    Natural Gas Pricing after June 30, 2006 (after the major Saskatchewan
acquisition)

    -   Focus has a differential between the realized price compared to the
        AECO average daily reference price resulting from:

        a) an average heat content of our natural gas of 1.06 GJ's per mcf;

        b) approximately 30 percent of natural gas being delivered to British
           Columbia markets which receives a lower price than the AECO
           reference price;

        c) approximately 30 percent of natural gas incurring transportation
           system charges in British Columbia which have a higher charge per
           mcf;

        d) the timing differences between how physical gas is sold during the
           period versus the AECO daily average.

    Realized natural gas price compared to AECO daily reference price to
September 30, 2007:

                                    Three Months Ended     Nine Months Ended
                                          September 30,         September 30,
    Realized Price Per Mcf             2007       2006       2007       2006
    -------------------------------------------------------------------------
    AECO daily average
     (CDN$/mcf)(1)                $    5.18  $    5.66  $    6.55  $    6.40
    Plus: heat content
     adjustment(1)(2)                  0.05       0.01       0.05       0.30
    Less: differential to B.C.
     markets(1)(2)                    (0.01)     (0.04)     (0.05)     (0.19)
    Less: transportation system
     charges(2)                       (0.29)     (0.32)     (0.31)     (0.46)
    Adjust: timing of actual
     gas sales(1)(2)                   0.13       0.08       0.05      (0.17)
    -------------------------------------------------------------------------
    Price before price protection
     (physical & financial)            5.07       5.39       6.29       5.89
    Impact of longer term physical
     sales contracts(1)                0.52       0.40       0.29       0.43
    Financial hedging settlements      1.25       0.96       0.75       0.82
    -------------------------------------------------------------------------
    Focus realized price per
     mcf(3)                       $    6.83  $    6.75  $    7.32  $    7.14
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Focus natural gas sales
        price per mcf (before
        transportation system
        charges and financial
        commodity contract
        settlements)              $    5.87  $    6.11  $    6.89  $    6.77
    -------------------------------------------------------------------------
    (2) Differential of Focus
        sales price to AECO
        daily reference price
        after transportation
        and before price
        protection per mcf        $   (0.11) $   (0.27) $   (0.27) $   (0.51)
    -------------------------------------------------------------------------
    (3) For 2007, excludes any unrealized gains or losses recorded for
        financial commodity contracts and excludes the reclassification to
        earnings of gains on hedges held at January 1, 2007


    Natural Gas Pricing

    -   Natural gas reference prices continued to decline in Q3 2007 due to
        the absence of storm-related supply disruptions in the Gulf of
        Mexico, increasing U.S. natural gas production and record levels of
        LNG imports into the U.S. resulting in high storage levels. Natural
        gas reference prices are currently improving slightly, however,
        combined with the strength of the Canadian dollar, Canadian natural
        gas prices have not seen as much improvement as US benchmark prices.
        The average AECO daily reference price per mcf for natural gas was
        $5.18 during the third quarter of 2007 compared with $7.07 for the
        second quarter of 2007 and $5.66 in the third quarter of 2006.

    -   Focus' realized natural gas price of $6.83 per mcf in the third
        quarter of 2007 was seven percent lower compared to the second
        quarter of 2007 price of $7.35 per mcf due to a 27 percent decrease
        in the reference price and a higher level of gains from the
        settlement of physical and financial commodity contracts.

    -   The realized price in the third quarter of 2007 was slightly higher
        than the third quarter of 2006 as the decrease in the reference price
        of natural gas was offset by higher financial and physical hedging
        settlements.

    -   During the third quarter of 2007, our price protection program
        reduced some of the volatility in natural gas prices and increased
        the realized price received by $1.77 per mcf. During the quarter,
        21 percent of natural gas was sold under forward physical sales
        contracts which resulted in natural gas sales being $5.2 million
        higher than if the natural gas had been sold based on the AECO daily
        reference price. Forty-nine percent of natural gas production was
        hedged with financial instruments. The impact of the financial
        instrument settlements was positive $12.6 million for the third
        quarter of 2007.

    -   Year-to-date price protection programs have increased realized
        natural gas prices by $1.04 per mcf and increased revenue by
        approximately $32.1 million. This compares with a benefit of
        $1.25 per mcf and $23.8 million for the comparable period in 2006.

    -   Accounting for financial contracts changed in 2007 to mark-to-market
        accounting from hedge accounting. This is further discussed in
        Notes 3 and 13 of the notes to consolidated financial statements.

    Crude Oil

    -   The price realized for crude oil, after settlement of financial
        hedges, was $74.18 per barrel for the third quarter of 2007 versus
        $70.09 for the comparable period in 2006 and $67.64 per barrel in the
        second quarter of 2007.

    -   The differential between the sales price of our crude oil and the
        Edmonton par reference price for light oil in the third quarter of
        2007 was $3.67 per barrel compared with $4.14 per barrel in the
        second quarter of 2007. Heavy oil production, representing 16 percent
        of oil production for the quarter, had a differential of $29.67 per
        barrel. Light oil production had a positive differential of $1.15 per
        barrel.

    -   We utilized price protection for a portion of our crude oil
        production. For Q3 2007, 800 barrels per day were hedged financially
        with a cost of $0.3 million, or $1.98 per barrel. This compares with
        a cost of $0.7 million in the third quarter of 2006 on 700 barrels
        per day hedged, or $4.07 per barrel. For the second quarter of 2007,
        800 barrels per day were hedged with financial commodity contracts
        which resulted in a cost of $15,000, or $0.09 per barrel.

    Price Protection
    -------------------------------------------------------------------------
    -   Focus uses price protection through longer term physical delivery
        contracts and financial contracts to reduce the volatility in
        commodity prices in an effort to help maintain sustainable
        distributions.

    -   A full description of the outstanding financial instruments and
        physical sales contracts and their estimated mark-to-market values is
        contained in Notes 12 and 14 of the notes to consolidated financial
        statements.

    -------------------------------------------------------------------------
    Price Protection (volume       2007                    2008
     and reference price)
                                      Q4       Q1       Q2       Q3       Q4
    -------------------------------------------------------------------------
     Natural gas  Mmcf/d            63.4     56.4     14.1     14.1      4.7
                  CDN$/mcf        $8.43-   $8.71-
                                   $8.55    $8.91    $6.76    $6.76    $6.76
     Crude oil    bbls/d             400      800      800      400      400
                  CDN$/bbl       $70.00-  $74.27-  $74.27-
                                  $79.00   $78.77   $78.77   $78.53   $78.53
    -------------------------------------------------------------------------

    These amounts assume a heat content of 1.06 GJ per mcf for our natural
gas.
    

    Changes in Accounting Policy
    -------------------------------------------------------------------------
    Effective January 1, 2007, the Trust adopted the new recommendations of
the Canadian Institute of Chartered Accountants (CICA) Handbook Section 1530,
"Comprehensive Income"; Section 3861, "Financial Instruments - Disclosure and
Presentation"; Section 3855, "Financial Instruments - Recognition and
Measurement"; and, Section 3865, "Hedges", prospectively and therefore the
comparative interim financial statements have not been restated. These new
handbook sections provide requirements for the recognition and measurement of
financial instruments and on the use of hedge accounting and apply to fiscal
years beginning on or after October 1, 2006.
    Upon adoption of these new standards, the Trust discontinued hedge
accounting on its financial commodity contracts. The unrealized gain on the
outstanding contracts at January 1, 2007 has been included in accumulated
other comprehensive income on adoption and will be deferred in accumulated
other comprehensive income until the original hedged transaction is recognized
in earnings which is over its original contract term. All financial commodity
contracts entered into subsequent to January 1, 2007 will be recorded at fair
value on the balance sheet. These contracts will be adjusted to fair value
each period with the change recognized in the determination of income. See
Notes 3 and 13 of the notes to consolidated financial statements for further
discussion.
    The following table summarizes the income statement impact of the
financial commodity contracts:

    
                                                  Three Months   Nine Months
                                                         Ended         Ended
                                                      Sept. 30,     Sept. 30,
    (thousands)                                           2007          2007
    -------------------------------------------------------------------------
    Fair value of financial contracts outstanding
     at end of period (asset)(1)                     $  16,757     $  16,757
    Fair value of financial contracts outstanding
     at beginning of period(2)                          17,191        25,786
    -------------------------------------------------------------------------
    Change in fair value - unrealized gain (loss)
     on financial commodity contracts                     (433)       (9,029)
    Cash settlement of financial contracts in
     the period                                         12,295        22,965
    Reclassification to earnings of gains on
     hedges(3)                                           6,243        23,069
    -------------------------------------------------------------------------
    Income statement impact before tax               $  18,105     $  37,005
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Represents the net derivative asset amount on the balance sheet.

    (2) The fair value of financial commodity contracts outstanding at
        December 31, 2006 was $25.8 million. This was recognized in
        accumulated other comprehensive income ("AOCI") and is amortized to
        income over the term of those contracts. AOCI and changes in other
        comprehensive income are presented in financial statements on a
        net-of-tax basis.

    (3) Transitional provisions of the new standards require the fair value
        of the outstanding financial contracts at December 31, 2006 be
        recognized in income over the term of the contracts. This amount
        represents the third quarter and nine month amortization of the
        December 31, 2006 fair value amount.

    The following table summarizes the financial statement effects of the
recognition of accumulated other comprehensive income:

    (thousands)
    -------------------------------------------------------------------------
    On adoption, net of tax ($25.9 million less
     related tax of $8.0 million)(1)                               $  17,947
    Amortized to income, net of tax ($23.1 million
     less related tax of $7.1 million)                                15,955
    -------------------------------------------------------------------------
    Balance as at September 30, 2007                               $   1,992
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Adoption amount includes $0.2 million related to the amortization of
        other commodity contracts.

    Physical commodity contracts will continue to be accounted for on an
accrual basis.

    Production Revenue
    -------------------------------------------------------------------------
    -   Production revenue, including financial contract hedging settlements,
        was $89.0 million for the three months ended September 30, 2007
        compared to $90.4 million in Q3 2006. Approximately 81 percent of
        production revenue was from natural gas. The small reduction in
        production revenue is mostly due to lower natural gas production
        volumes. This is partially offset by higher price realizations for
        crude oil and natural gas and higher NGL production volume.

    -   Production revenue for Q3 2007 decreased by $7.3 million from Q2
        2007, mainly due to lower natural gas price realizations and
        production volumes which were partially offset by higher crude oil
        price realizations.
    

    Royalties
    -------------------------------------------------------------------------
    Royalties, as a percentage of revenue before financial commodity contract
settlements and net of transportation charges, were 18 percent in the third
quarter of 2007 compared to 21 percent in the third quarter of 2006. Crown
royalties on the Saskatchewan properties are generally lower than on the
properties in Alberta and British Columbia. The effective royalty rate for the
third quarter of 2007 was 15 percent compared to 19 percent in the third
quarter of 2006 mainly due to the increase in financial hedging settlements in
Q3 2007. Financial commodity contract settlements are not subject to
royalties.
    On October 25, 2007, the Alberta government released details of a new
royalty framework for Alberta. The new royalty framework is effective
January 1, 2009 and will result in a significant increase in Crown royalties
paid by Alberta producers. It is a sliding scale structure, sensitive to both
price and well productivity. The government's report, titled "The New Royalty
Framework", is available on the Province of Alberta's website. We estimate
that the impact to the Trust's funds flow will be less than two percent.
Alberta production for the nine months ended September 30, 2007 is 13 percent
of total production. Alberta production represents six percent of natural gas
production and 62 percent of crude oil and NGL production.

    
    Production Expenses
    -------------------------------------------------------------------------
                               2007                    2006             2005
                         Q3     Q2     Q1     Q4     Q3     Q2     Q1     Q4
    -------------------------------------------------------------------------
    Production
     expenses
     per BOE          $3.84  $3.71  $4.50  $4.04  $3.50  $4.62  $5.50  $4.61
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -   Production expenses for the third quarter of 2007 were $3.84 per BOE
        compared with $3.71 per BOE for the second quarter of 2007 and $3.50
        for the third quarter of 2006. Our yearly production expenses remain
        on target to our guidance of $3.75 to $4.25 per BOE.

    -   Production expenses declined from the second quarter of 2006 largely
        due to the addition of the Saskatchewan properties which have lower
        production expenses.

    General and Administrative Expenses
    -------------------------------------------------------------------------
                                    Three Months Ended     Nine Months Ended
                                              Sept. 30,             Sept. 30,
    (thousands)                        2007       2006       2007       2006
    -------------------------------------------------------------------------
    Cash G&A expenses             $   3,135  $   3,054  $  10,448  $   6,976
    Overhead recoveries              (1,983)    (1,795)    (6,495)    (3,290)
    -------------------------------------------------------------------------
    Total cash G&A expenses           1,152      1,259      3,953      3,686
    Non-cash G&A expense(1)               -          -          -        804
    Rights Plan expense(2)              766        647      2,373      1,312
    Unit Award Plan expense(2)        1,163          -      1,163          -
    -------------------------------------------------------------------------
    Net G&A reported              $   3,081  $   1,906  $   7,489  $   5,802
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Cash-based G&A per BOE        $    0.60  $    0.63  $    0.67  $    0.97
    Net reported G&A per BOE      $    1.60  $    0.95  $    1.27  $    1.52

    (1) Gross general and administrative expenses for the nine months ended
        September 30, 2006 included $0.8 million related to the Executive
        Bonus Plan. Half of this amount was non-cash and settled through the
        issuance of units from treasury at a price equal to the average of
        the last five trading days of the month for which the bonus relates.
        The Executive Bonus Plan was terminated June 30, 2006.

    (2) Rights Plan and Unit Award Plan compensation expense are calculated
        using the fair value method and represent a non-cash charge. Further
        details are contained in Notes 9 and 10 of the notes to consolidated
        financial statements.
    

    Cash-based general and administrative expenses were $0.60 per BOE for the
third quarter of 2007 and $0.67 per BOE for the nine months ended
September 30, 2007. This compares to $0.63 per BOE for the third quarter of
2006 and $0.97 per BOE for the nine months ended September 30, 2006. The major
acquisition in late June 2006 necessitated the addition of personnel in all
areas of the Trust to handle the expanded production base, larger capital
programs and additional corporate requirements. This growth increased general
and administrative costs associated with personnel, rent and corporate
activities. Even though we have grown in size, general and administrative
expenses per BOE have gone down because of increased production and additional
overhead recoveries from the acquired operated properties.
    Cash-based general and administrative expenses remained constant at
approximately $0.60 per BOE in the second and third quarters of 2007 and our
annual guidance remains at $0.90 to $1.10 per BOE.
    Focus reviewed and updated its long-term compensation plans to be more
comparable with the standard industry compensation framework. At the Annual
General and Special Meeting on May 17, 2007, unitholders approved a new Unit
Award Incentive Plan ("Unit Award Plan") which will grant awards of restricted
trust units ("RTUs") and performance trust units ("PTUs"). In addition, the
Trust Unit Rights Incentive Plan ("Rights Plan") was amended so that no
further rights would be granted under that plan. Additional information on
these plans is contained in Notes 9 and 10 of the notes to consolidated
financial statements. This review process took several months and resulted in
Focus being without an effective long-term incentive plan. Consequently, as a
bridge to a new long-term incentive plan, a bonus was paid to employees in
July 2007. This $1.2 million payment was approved by the Board of Directors
during the first quarter of 2007 and was recorded in the March 31, 2007
financial statements.
    In July 2007, the Board of Directors approved the initial grant of RTUs
and PTUs. At September 30, 2007 there are 320,811 RTU and 606,999 PTU grants
outstanding. The Unit Award Plan will pay out in trust units which may be
issued from treasury or purchased on the Toronto Stock Exchange. We anticipate
that the trust units will be issued from treasury. Additional trust units will
be issued for the value of accrued distributions. RTUs and PTUs will vest over
a period of two years and nine months. The number of RTUs issued is fixed,
whereas the number of PTUs issued is calculated by using a payout multiplier
which is tied directly to the performance of the Trust. The payout multiplier,
which will vary between zero and two, is determined annually and is based on
value measurements as defined by the Board of Directors. The Unit Award Plan
provides that the maximum number of trust units reserved for issuance shall
not exceed five percent: (i) of our outstanding trust units (including trust
units issuable upon exchange of exchangeable shares and any other fully paid
exchangeable securities of any other entity controlled by us) less (ii) the
aggregate number of trust units reserved under the Rights Plan.
    The RTUs and PTUs are accounted for on a fair value basis. This
compensation expense is a non-cash charge and is based on the fair value of
the trust units on the date of grant. The fair value of a Focus trust unit at
the date of initial grant was $17.55. Compensation expense is recognized in
income over the two year and nine month vesting period with a corresponding
increase in contributed surplus. The first vesting and settlement of the RTUs
and PTUs will occur in July 2008. This compensation expense of $1.2 million in
the third quarter consists of $0.4 million related to the RTUs and
$0.8 million related to the PTUs.
    Compensation expense associated with the PTUs has been estimated by
assuming a payout multiplier of one. The payout multiplier is based on annual
performance indicators which cannot be determined with certainty currently. We
anticipate that the payout multiplier will be determined in the first quarter
of 2008 prior to the release of the 2007 annual and fourth quarter results.
    The additional trust units that will be issued for accrued distributions
are accounted for in equity with a corresponding payable. This is also
accounted for over the two year and nine month vesting period.

    Interest and Financing Expenses
    -------------------------------------------------------------------------
    Interest and financing expenses were $4.3 million in the third quarter of
2007 compared to $4.2 million in the second quarter of 2007. Average debt
declined during the third quarter and average interest rates increased. The
Trust's debt is subject to floating short-term market interest rates.
Outstanding long-term debt decreased $4.5 million from $286 million at
June 30, 2007 to $281.5 million at September 30, 2007.
    Interest and financing expenses increased from $3.7 million in the third
quarter of 2006 to $4.3 million in the third quarter of 2007 commensurate with
higher interest rates. Outstanding long-term debt at September 30, 2007 was
$281.5 million compared to $293.2 million at September 30, 2006.

    Depletion, Depreciation and Accretion
    -------------------------------------------------------------------------
    Depletion, depreciation and accretion expense consists of the following:

    
                                    Three Months Ended     Nine Months Ended
                                              Sept. 30,             Sept. 30,
    (thousands)                        2007       2006       2007       2006
    -------------------------------------------------------------------------
    Depletion and depreciation
     of oil and gas assets        $  44,153  $  48,271  $ 134,708  $  70,139
    Depletion of asset retirement
     obligation(1)                      901        797      2,635      1,362
    Depletion related to the
     conversion of exchangeable
     shares(2)                        3,519      3,616     10,767     10,001
    Accretion of the asset
     retirement obligation              800        523      2,236      1,307
    -------------------------------------------------------------------------
                                  $  49,373  $  53,207  $ 150,346  $  82,809
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                                    Three Months Ended     Nine Months Ended
                                              Sept. 30,             Sept. 30,
    (per BOE)                          2007       2006       2007       2006
    -------------------------------------------------------------------------
    Depletion and depreciation
     of oil and gas assets        $   22.92  $   24.01  $   22.84  $   18.38
    Depletion of asset retirement
     obligation(1)                     0.47       0.40       0.45       0.36
    Depletion related to the
     conversion of exchangeable
     shares(2)                         1.83       1.80       1.83       2.62
    Accretion of the asset
     retirement obligation             0.42       0.26       0.38       0.34
    -------------------------------------------------------------------------
                                  $   25.62  $   26.47  $   25.50  $   21.70
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Depletion related to the capitalized portion of the asset retirement
        obligation that is depleted over the estimated net proved reserves.

    (2) The conversion of exchangeable shares results in an increase in
        petroleum and natural gas properties and equipment without an
        increase in reserves and is depleted over the estimated net proved
        reserves. Exchangeable shares have all been converted to trust units
        at January 16, 2007.
    

    Depletion, depreciation and accretion for the three months ended
September 30, 2007 increased slightly to $25.62 per BOE compared to $25.50 per
BOE in the second quarter of 2007. The second quarter 2006 amount includes
$0.39 per BOE related to accretion.
    The depletion, depreciation and accretion rate incorporates the results
of independent reserve reports dated December 31, 2006 and actual capital
expenditures.

    Asset Retirement Obligation
    -------------------------------------------------------------------------
    The asset retirement obligation increased $2.3 million to $41.6 million
at September 30, 2007 from $39.3 million at June 30, 2007 largely due to
drilling activity and accretion expense. The asset retirement obligation
recorded represents the net present value of cash flows required to settle
asset retirement obligations. Asset retirement costs are capitalized as part
of petroleum and natural gas properties and equipment and are depleted over
the estimated net proved reserves. A full description is contained in Note 4
of the notes to consolidated financial statements.
    A reclamation fund has been established to fund environmental and site
reclamation costs. Contributions to the reclamation fund are made each quarter
such that the currently estimated future environmental and site restoration
costs will be funded after 20 years. At September 30, 2007, the reclamation
fund had a balance of $8.9 million. The contribution level is reviewed
annually commensurate with the annual reserve reports based on a detailed
assessment of future estimated environmental and site restoration costs.
    We anticipate that all expenditures will be financed by the reclamation
fund. Reclamation costs in the nine months ended September 30, 2007 were
66 percent funded by the reclamation fund. The remaining 34 percent was funded
temporarily through working capital.

    Income and Other Taxes
    -------------------------------------------------------------------------
    On June 22, 2007, Bill C-52, the Federal Government's legislation
containing provisions to impose a tax on publicly traded income trusts and
partnerships, received Royal Assent. The legislation includes a 31.5 percent
tax for taxation years beginning in 2011 on income of the Trust before
distributions. Distributions will effectively be taxed as a dividend to the
taxable Canadian investor.
    Certain of the Trust's assets are held by entities which transfer taxable
income to unitholders. Prior to the legislation becoming enacted, future
income taxes were not required to be recorded on temporary differences related
to the carrying value of these assets over their tax value. As a result of the
legislation becoming enacted, the Trusts' tax status has changed for purposes
of Canadian accounting guidelines. A non-cash, future income tax expense of
$13.8 million has been recorded on these temporary differences in the second
quarter of 2007 because of this change in tax status.
    Income and other taxes include a future income tax recovery of
$4.6 million in the third quarter of 2007 compared to a recovery of
$7.8 million in the third quarter of 2006. The future income tax recovery in
the third quarter resulting from the transfer of taxable income from the Trust
to individual unitholders and from the depletion associated with the
accounting for exchangeable shares, is offset by the expense from previously
recorded temporary differences.
    As noted above, the legislation is effective January 1, 2011 provided the
Trust continues to comply with the "normal growth" guidelines in the
transitional period until 2011.
    Current guidelines effectively measure "normal growth" with reference to
the Trust's market capitalization on October 31, 2006, the date the government
first announced the proposal for the tax. The "normal growth" will permit new
equity of 40 percent to the end of December 31, 2007 with an additional
20 percent per year 2008 to 2010, for a total of 100 percent. In addition, the
Trust will be permitted to repay existing outstanding debt on October 31, 2006
without impacting the normal growth limits.
    We are currently assessing various structural alternatives in light of
the legislation however, in spite of the structural implications, our core
business remains the same.
    Current tax provision of $0.6 million in the third quarter of 2007
relates to estimated income tax for two subsidiary corporations of the Trust.

    Capital Expenditures
    -------------------------------------------------------------------------
    Capital expenditures for field operations in the third quarter of 2007
were $25.6 million. Expenditures were almost entirely in our core area of
Shackleton. We drilled 113 (110 net) wells and participated in another 30
(9 net) with another operator for a total of 143 (119 net) Milk River gas
wells with a 100 percent success rate.
    Although rain delays slowed down the start of our Shackleton summer
drilling program in the second quarter, the addition of a third drilling rig
in the third quarter helped make up some lost time. The Shackleton summer
program is coming in on time, on budget and as per expectations in terms of
well results.
    During the third quarter we acquired further lands and working interest
positions at our new Trutch Halfway gas pool, adding 48 (20 net) sections of
land. This $2.2 million transaction is effective September 1 and closed
October 16, 2007.
    We will continue to have an active program in Shackleton throughout the
fourth quarter. In the first half of Q4 we will be finishing the completions
and tie-ins from the summer programs and the second half of Q4 will see us
start drilling in our environmentally sensitive winter access areas. Also, in
Q4 we will be starting our 2007/2008 Tommy Lakes winter drilling program.

    Liquidity and Capital Resources
    -------------------------------------------------------------------------
    As at September 30, 2007 Focus had a working capital deficit of
$20.0 million (excluding any derivative asset or liability) compared with
working capital deficit of $11.0 million (excluding any derivative asset or
liability) at December 31, 2006 and working capital deficit of $20.2 million
(excluding any derivative asset or liability) at September 30, 2006. The
working capital deficiency has increased from year end partly due to a
decrease in revenue receivables from a lower natural gas price at September
30, 2007 compared to December 31, 2006 and an increase in the drawings under
the bank operating facility at September 30, 2007. On a monthly basis there
are fluctuations in accounts receivable and accounts payable reflecting the
extent of capital programs, distributions to unitholders after month end,
commodity price volatility and seasonal fluctuations.
    Long-term debt at September 30, 2007 was $281.5 million compared with
$297 million at December 31, 2006 and $293.2 million at September 30, 2006.
The decrease in long-term debt from year end results partly from the timing of
capital expenditures, we are more active in the winter than in the third
quarter with our winter drilling programs. In addition, current bank debt at
September 30, 2007 was $14.3 million compared to $5.0 million at December 31,
2006 due to timing of cheques cashed.
    Focus had a $350 million revolving syndicated credit facility among four
Canadian financial institutions and a $15 million operating facility with one
Canadian chartered bank at September 30, 2007. The credit facility revolves
until June 24, 2008, whereupon it may be renewed for a further 364-day term
subject to a review by the lenders. If not extended, principal payments will
commence after expiry of the revolving period and will consist of three
quarterly payments of eight and one-third percent commencing 15 months after
the term date and the remaining 75 percent at the end of the term. The credit
facilities are secured by a floating charge debenture covering all of the
assets of the Trust and a general security agreement. At September 30, 2007,
the Trust was in compliance with its covenants under its syndicated facility.

    
    Capitalization Table
                                                      Sept. 30,  December 31,
    (thousands except per-unit amounts)                   2007          2006
    -------------------------------------------------------------------------
    Long-term debt                                  $  281,500    $  297,000
    Plus: working capital deficiency
     (excluding derivative asset & liability)           19,986        10,958
    -------------------------------------------------------------------------
    Total debt (excluding derivative asset
     & liability)                                   $  301,486    $  307,958
    Units outstanding and exchangeable
     partnership units                                  79,491        78,504
    Market price                                    $    17.46    $    18.18
    Market capitalization                           $1,387,913    $1,427,203
    Total capitalization                            $1,689,399    $1,735,161
    -------------------------------------------------------------------------
    Total debt as a percentage of total
     capitalization                                      17.8%         17.7%
    Annualized funds flow from operations(1)        $  250,312    $  247,062
    Total debt to funds flow                              1.2x          1.2x
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) September 30, 2007 is based on the funds flow of the Trust for the
        273-day period. The calculation of debt to annualized funds flow at
        December 31, 2006 is based on the $124.5 million of funds flow from
        operations of the Trust for the period of July 1 to December 31, 2006
        to more appropriately match the asset base after the acquisition with
        the debt level after the acquisition late in June 2006.

    In October 2006 Focus approved the DRIP Plan which provides eligible
unitholders of Focus trust units the advantage of accumulating additional
trust units by reinvesting their cash distributions and/or by making optional
payment for additional trust units. Under the distribution reinvestment
portion of the DRIP Plan, participants can potentially buy additional units
from treasury at 95 percent of the average market price. This DRIP Plan
provides a service to unitholders and increases our financial flexibility.
Focus wants to maintain financial flexibility at a time of shifting commodity
prices. We will use funds generated by this plan to reduce debt and invest in
additional capital projects, including land purchases and expanded development
operations.
    Trust units issued under the DRIP program in 2007 are summarized as
follows:

    -------------------------------------------------------------------------
    Month     Value (thousands)   Number of Units Issued     DRIP Unit Price
    -------------------------------------------------------------------------
    January            $   874                    52,247              $16.73
    February             1,002                    57,431              $17.45
    March                1,073                    67,862              $15.82
    April                1,096                    64,372              $17.03
    May                  1,096                    61,028              $17.95
    June                 1,122                    60,646              $18.50
    July                 1,094                    65,348              $16.74
    August               1,740                   106,915              $16.27
    September            1,534                    94,325              $16.26
    -------------------------------------------------------------------------
                       $10,631                   630,174
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Cash Distributions
    -------------------------------------------------------------------------
    In determining the level of cash distributions and capital expenditures,
Focus looks at cash flow from operating activities, adjusted for changes in
non-cash working capital and reclamation costs. Focus refers to this subtotal
as funds flow from operations. Funds flow from operations as presented does
not have any standardized meaning as prescribed by Canadian GAAP and therefore
it may not be comparable with the calculation of similar measures of other
entities. Please see page 5 for further disclosure.
    Focus uses the funds flow from operations measure to analyze operating
performance and leverage and in setting levels for distributions and field
capital expenditures. The change in non-cash working capital varies and can be
significant through the year due to the seasonality of a significant part of
our operations. Tommy Lakes and a portion of our Shackleton property are
accessible only in the winter. We do not expect the seasonality or other
timing factors to influence the level of distributions.

                                                          Nine Months Ended
                                                               September 30,
    (thousands)                                           2007         2006
    -------------------------------------------------------------------------
    Cash flow from operating activities             $  199,255    $   88,861
      Reclamation costs(1)                               1,234           285
      Net change in non-cash working capital items     (13,269)       27,664
    -------------------------------------------------------------------------
    Funds flow from operations                      $  187,220    $  116,810
    Less:
      Capital expenditures(2)                          (84,129)      (63,420)
      Reclamation fund contributions(1)                 (4,494)       (2,388)
      Distributions                                    (99,806)      (86,928)
    -------------------------------------------------------------------------
    Financing surplus (requirement) from funds
     flow from operations                               (1,209)      (35,926)
    Proceeds from issue of trust units (net of costs)    1,300           737
    Proceeds from DRIP program(3)                       10,631             -
    Acquisitions(2)(4)                                  (4,251)     (184,100)
    Other                                                    -        (1,206)
    -------------------------------------------------------------------------
    Decrease (increase) in long-term debt
     and working capital                            $    6,471    $ (220,495)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Distributions per unit(5)                       $     1.26    $     1.62
    Accumulated distributions per unit,
     beginning of period(6)                               8.03          5.93
    -------------------------------------------------------------------------
    Accumulated distributions per unit,
     end of period(6)                               $     9.29    $     7.55
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Contributions are made each quarter to the Reclamation Fund ("the
        Fund"). The Fund is held on deposit at a Canadian financial
        institution. The contribution level is reviewed annually commensurate
        with the annual reserve reports based on a detailed assessment of
        future estimated environmental and site restoration costs. Future
        expenditures for environmental and site restoration costs will be
        financed from the Fund.

    (2) Due to the nature of reserve reporting, natural production declines
        and the risks involved with capital expenditures, it is not possible
        to distinguish between capital expenditures for maintenance of
        productive capacity and growth of productive capacity. Asset
        acquisitions are excluded from productive capacity maintenance
        expenditures.

    (3) DRIP proceeds are generally used to reduce debt, fund acquisitions
        and to fund expanded development opportunities.

    (4) In connection with the major acquisition in June 2006, Focus paid
        cash of $199.8 million and obtained net working capital of
        $15.7 million for a net change in debt and working capital deficiency
        of $184.1 million.

    (5) Distributions per unit is the sum of the per-unit amounts declared
        monthly to unitholders to date in 2007.

    (6) Accumulated distributions per unit is the sum of the per-unit amounts
        declared monthly to unitholders since the inception of the Trust in
        August 2002.

    Central to Focus' business strategy is the concept of sustainability where
the sum of field capital expenditures to maintain production and distributions
is equal to funds flow from operations. Focus plans to finance its program for
production replacement primarily through investing approximately 35 to 45
percent of funds flow from operations. Capital expenditures, including
acquisitions and significant purchases of undeveloped land, above this level
will be financed through a combination of funds flow, debt and equity.

    Cash distributions related to 2007 are as follows:

    -------------------------------------------------------------------------
    Ex-Distribution                         Distribution        Distribution
    Date                Record Date         Payment Date        per Unit
    -------------------------------------------------------------------------
    January 29, 2007    January 31, 2007    February 15, 2007   $0.14
    February 26, 2007   February 28, 2007   March 15, 2007      $0.14
    March 28, 2007      March 31, 2007      April 16, 2007      $0.14
    April 26, 2007      April 30, 2007      May 15, 2007        $0.14
    May 29, 2007        May 31, 2007        June 15, 2007       $0.14
    June 27, 2007       June 30, 2007       July 16, 2007       $0.14
    July 27,2007        July 31, 2007       August 15, 2007     $0.14
    August 29, 2007     August 31, 2007     September 17, 2007  $0.14
    September 26, 2007  September 30, 2007  October 15, 2007    $0.14
    October 29, 2007    October 31, 2007    November 15, 2007   $0.14
    November 28, 2007   November 30, 2007   December 17, 2007   $0.14((*))
    December 27, 2007   December 31, 2007   January 15, 2008    $0.14((*))
    -------------------------------------------------------------------------
    ((*)) estimated
    

    Focus declared distributions of $1.26 per unit in respect of January to
September 2007 production. Cash distributions of the Trust are essentially
taxed to the unitholders as ordinary income.
    The distribution rate reflects Focus' commitment to a business strategy
of sustainability where the sum of field capital expenditures and
distributions is approximately equal to cash flow. The Trust continually
monitors the forward strip for natural gas and takes action in a prudent and
proactive manner to ensure sustainability through price protection activities
and by adjusting capital programs and distribution levels.
    Exchangeable partnership units receive a cash distribution equal to the
cash distribution declared for each Focus unit.

    Sustainability of Cash Distributions
    -------------------------------------------------------------------------
    The objective of Focus Energy Trust is to provide sustainable long-term
returns to our unitholders. To succeed with this objective, a strong
operational focus that utilizes the drill bit to create value and a focus on a
sustainable business plan is required. As production and reserves of oil and
natural gas assets naturally deplete, we must continually develop and/or
acquire new reserves in an economically efficient manner to remain
sustainable. The four elements that we believe define sustainability are 1)
production per unit, 2) reserves per unit, 3) capital reinvestment versus
funds flow, and 4) drilling inventory. Production per unit is a proxy for
funds flow. Stable funds flow is important in that it allows for stable
capital and distribution programs.
    The following table is a summary of the historical quarterly per-unit
calculation for production, funds flow from operations, cash flow from
operations and payout ratios:

    
    Per-trust unit ratios        Q3 2007  Q2 2007  Q1 2007     2006     2005
    -------------------------------------------------------------------------
    Production per unit
     - unadjusted(1)                0.26     0.28     0.28     0.27     0.27
    Production per unit
     - debt adjusted(2)             0.22     0.23     0.23     0.23     0.24
    Funds flow from operations
     per unit(3)                   $0.76    $0.80    $0.82    $3.09    $3.12
    Cash flow from operating
     activities per unit           $0.71    $0.89    $0.93    $2.57    $3.07
    Distributions per unit         $0.42    $0.42    $0.42    $2.10    $2.02
    Payout ratio - distributions/
     funds flow from operations      55%      53%      51%      68%      65%
    Payout ratio - distributions/
     cash flow from operations       59%      47%      45%      82%      66%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Average daily BOE per thousand units divided by weighted average
        Total Trust Units.

    (2) Debt adjusted assumes quarter-end debt is eliminated by adding units
        equal to the average net debt for the period divided by the average
        monthly closing unit prices for the period.

    (3) Funds flow 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 of other entities. Please
        see additional disclosures at beginning of the MD&A on page 5.

    Reserves are determined annually based on evaluations done by independent
engineering consultants. Please refer to the Trust's 2006 Annual Report for a
summary of reserves as at December 31, 2006 and the calculation of reserves
per unit.
    We believe we have in excess of three years of drill-ready inventory at
Shackleton and Tommy Lakes currently identified. In addition, we expect our
ongoing drilling program will expand that inventory as pool boundaries are
extended.

    Financial Sustainability

    ($ millions)      2007 YTD   2006   2005   2004   2003   2002  Cumulative
    -------------------------------------------------------------------------
    Field capital
     expenditures         84.1   90.4   43.0   25.2   16.8    4.1      263.6
    Distributions         99.8  124.2   73.7   61.4   41.0   11.1      411.2
    Reclamation fund
     & expenditures        4.5    3.2    1.4    1.0    1.3      -       11.4
    -------------------------------------------------------------------------
    Total                188.4  217.8  118.1   87.6   59.1   15.2      686.2
    Available funds flow
     from operations     187.2  181.2  116.4   89.6   65.8   19.0      659.2
    -------------------------------------------------------------------------
    Surplus (shortfall)   (1.2) (36.6)  (1.8)   2.0    6.7    3.8      (27.0)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    In 2006, there was a significant difference between funds flow from
operations and total expenditures of $36.6 million. This difference resulted
partly from the rapid decline of natural gas prices throughout 2006 resulting
in a shortfall of approximately $20 million. The other major components of the
$36.6 million were Focus' decision to invest $9.8 million at the Saskatchewan
land sale in August and $5.0 million related to acceleration of the Tommy
Lakes and Shackleton 2006/2007 winter drilling program into the fourth
quarter. Bank debt was used to fund the shortfall.
    Distributions, field capital expenditures and contributions to the
reclamation fund for the first nine months of 2007 have been funded 99 percent
by funds flow from operations and one percent by increased debt.
    The Trust continually monitors the forward strip for natural gas and takes
action in a prudent and proactive manner to protect sustainability through
price protection and by adjusting capital programs and distribution levels.

    Net Income and Distributions

    ($ millions
     except where
     noted)           2007 YTD   2006   2005   2004   2003   2002  Cumulative
    -------------------------------------------------------------------------
    Net income            48.7   73.0   63.5   59.6   41.4   10.2      296.4
    Distributions         99.8  124.2   73.7   61.4   41.0   11.1      411.2
    Excess (shortfall)
     of net income over
     distributions       (51.1) (51.2) (10.2)  (1.8)   0.4   (0.9)    (114.8)
    Excess (shortfall)
     as a percent of
     net income         (105)%  (70)%  (16)%   (3)%     1%   (9)%      (39)%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Another measure of sustainability is the comparison of net income to
distributions. Net income encompasses all costs including non-cash expenses
such as depletion and depreciation, unrealized gains and losses on commodity
contracts, future income tax expense and recoveries. Non-cash expenses will
not affect the Trust's current ability to pay a monthly distribution. Cash
flow from operations measures the cash generated for the period before the
cost of the capital assets. Depletion and depreciation is based on the
historical cost of the capital asset and does not reflect available funds flow
from operations for distributions and does not represent the value of the
assets at the current date. Focus made a significant acquisition in 2006
through a Plan of Arrangement for approximately $1.1 billion resulting in more
than a doubling of production. The acquisition significantly increased the
Trust's depletion provision. We expect reserve appreciation on the Shackleton
assets once they mature, as well as from identification of additional infill
and step-out locations, which could positively impact depletion.

    Contractual Obligations and Commitments
    -------------------------------------------------------------------------
    The Trust has contractual obligations in the normal course of operations
including purchase of assets and services, operating agreements,
transportation commitments and sales commitments. These obligations are of a
recurring and consistent nature and impact cash flow in an ongoing manner. See
Note 17 of the notes to consolidated financial statements for further details.

    Critical Accounting Estimates
    -------------------------------------------------------------------------
    Focus' financial and operating results incorporate certain estimates
including:

    
    -   estimated revenues, royalties and operating expenses on production as
        at a specific reporting date but for which actual revenues and
        expenses have not yet been received;

    -   estimated capital expenditures on projects that are in progress;

    -   estimated depletion, depreciation and accretion that are based on
        estimates of oil and gas reserves that we expect to recover in the
        future, estimated future salvage values, and estimated future capital
        costs;

    -   estimated fair values of derivative contracts and physical sales
        contracts that are subject to fluctuation depending upon the
        underlying commodity prices and foreign exchange rates;

    -   estimated value of asset retirement obligations that are dependent
        upon estimates of future costs and timing of expenditures.
    

    We have hired individuals and consultants who have the skill sets to make
such estimates and ensures that the individuals and departments with the most
knowledge of an activity are responsible for the estimates. Past estimates are
reviewed and compared to actual results in order to make more informed
decisions on future estimates. Our management team's mandate includes ongoing
development of procedures, standards and systems to allow us to make the best
estimates possible.

    Assessment of Business Risks
    -------------------------------------------------------------------------
    Refer to the Assessment of Business Risks section of the Trust's 2006
Annual Report MD&A for a detailed assessment.

    Environmental Regulation and Risk
    ---------------------------------
    All phases of the oil and natural gas business present environmental
risks and hazards and are subject to environmental regulation pursuant to a
variety of federal, provincial and local laws and regulations. Compliance with
such legislation can require significant expenditures and a breach may result
in the imposition of fines and penalties, some of which may be material.
Environmental legislation is evolving in a manner expected to result in
stricter standards and enforcement, larger fines and liability and potentially
increased capital expenditures and operating costs. In 2002, the Government of
Canada ratified the Kyoto Protocol (the "Protocol"), which calls for Canada to
reduce its greenhouse gas emissions to specified levels. There has been much
public debate with respect to Canada's ability to meet these targets and the
Government's strategy or alternative strategies with respect to climate change
and the control of greenhouse gases. Implementation of strategies for reducing
greenhouse gases whether to meet the limits required by the Protocol or as
otherwise determined, could have a material impact on the nature of oil and
natural gas operations, including those of Focus.
    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
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 Focus and its operations and
financial condition.

    Disclosure Controls and Controls Over Financial Reporting
    -------------------------------------------------------------------------
    The Trust maintains a Disclosure Committee (the "Committee") that is
responsible for ensuring that all public and regulatory disclosures are
sufficient, timely and appropriate, and that disclosure controls and
procedures are operating effectively. The Committee consists of the Chief
Executive Officer and each of the Vice Presidents. The Trust's disclosure
controls and procedures are in place to ensure that any material, or
potentially material, information is made known to the Committee and is
properly included in this report.
    Management has designed internal controls over financial reporting to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of the financial statements for external purposes in
accordance with GAAP. At December 31, 2006, we concluded that the design of
internal controls over financial reporting was effective.
    There were no changes that have materially affected or are reasonably
likely to materially affect the Trust's internal control over financial
reporting in the nine months ended September 30, 2007.
    The Trust's management, including the Chief Executive Officer and the
Chief Financial Officer, do not expect that our disclosure controls or our
internal control over financial reporting will prevent or detect all error or
fraud. A control system, no matter how well designed and operated, can provide
only reasonable, not absolute, assurance that the control system's objectives
will be met. The design of a control system must reflect the fact that there
are resource constraints, and the benefits of controls must be considered
relative to their costs. Further, because of the inherent limitations in all
control systems, no evaluation of controls can provide absolute assurance that
misstatements due to error or fraud will not occur or that all control issues
and instances of fraud, if any, within the Trust have been detected.

    Outlook - 2007
    -------------------------------------------------------------------------
    The Trust's operational results and financial condition will be dependent
on the prices received for oil and natural gas production. Oil and natural gas
prices have fluctuated significantly over recent years and are determined by
global demand and supply factors.
    The following chart summarizes our 2007 outlook. No major acquisitions
are assumed for the purpose of these forecasts.
    In 2007, we will continue our active drilling and development program on
our major natural gas properties. It is anticipated that these development
opportunities will maintain production by offsetting production declines.
    We do not attempt to forecast commodity prices, and as a result, we do
not forecast funds flow from operations or future cash distributions to
unitholders.

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

    Summary of 2007 Expectations
    -------------------------------------------------------------------------
    Average annual production                                   21,500 BOE/d
    Weighting to natural gas                                             89%
    Production expenses per BOE                                $3.75 - $4.25
    Cash G&A expenses per BOE                                  $0.90 - $1.10
    Capital expenditures - field                          $95 - $115 million
    Average annual payout ratio                                    55% - 65%
    Approximate taxable portion of distributions                        100%
    Funds from operations/net debt                               1.1x - 1.3x
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    We are committed to increasing the long-term value of the Trust to
unitholders. The following goals are the foundation of our commitment to value
creation:

    -   Maximize the value of existing assets;
    -   Attract and retain the best value creation team;
    -   Pursue quality acquisitions that are strategic and accretive;
    -   Protect margins and improve profitability;
    -   Create value through operational expertise and control; and
    -   Maintain financial flexibility and strength.

    Summary of Quarterly Results
    -------------------------------------------------------------------------
    The following table provides a summary of results for each of the last
eight quarters. Significant factors and trends which have impacted these
results include:

    -   Revenue and royalties are directly related to fluctuations in the
        underlying commodity prices and the extent to which price protection
        has been achieved through financial hedges and forward physical sales
        contracts.

    -   Focus completed a major acquisition in June 2006 for approximately
        $1.1 billion which more than doubled our production. The acquisition
        was financed with the issuance of 40.8 million trust units or
        exchangeable partnership units and an increase in long-term debt plus
        working capital deficiency of $179 million.

    -   Prior to the major acquisition in late June 2006, many of the natural
        gas areas of Focus were only accessible in the winter. This includes
        the Tommy Lakes area, which is significant from a production and
        development program perspective. Please refer to the Seasonality of
        Operations section for additional information.

    -   Effective January 1, 2007, the Trust discontinued hedge accounting on
        its financial commodity contracts. See Changes in Accounting Policy
        section for further discussion.

    -------------------------------------------------------------------------
                                                     2007               2006
    (thousands of dollars,
     except as indicated)                   Q3        Q2        Q1        Q4
    -------------------------------------------------------------------------
    FINANCIAL
    Production revenue and
     financial commodity
     contract settlements(1)            89,044    96,294    99,269    98,434
    Funds flow from
     operations                         60,026    62,780    64,414    64,412
      Per unit - basic                   $0.76     $0.80     $0.82     $0.81
    Cash distributions
     per trust unit                      $0.42     $0.42     $0.42     $0.48
    Payout ratio
     (per-unit basis)                      55%       53%       51%       59%
    Net income(2)                       19,138    23,790     5,748    21,646
      Per unit - basic                   $0.24     $0.30     $0.07     $0.28
    Capital expenditures                25,624     8,863    49,642    26,986
    Acquisition
     expenditures, net                     278     3,973         -        45
    Long-term debt plus
     working capital(3)                301,486   305,223   324,137   307,958
    Total Trust Units -
     outstanding (000's)                79,491    79,097    78,765    78,504
    -------------------------------------------------------------------------
    OPERATIONS
    Average daily production
      Crude oil (bbls/d)                 1,750     1,798     1,911     1,965
      NGLs (bbls/d)                        913       831       810       706
      Natural gas (mcf/d)              109,728   115,585   115,515   113,539
      BOE (at 6:1)                      20,951    21,894    21,974    21,594
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                                                     2006               2005

                                            Q3        Q2        Q1        Q4
    -------------------------------------------------------------------------
    FINANCIAL
    Production revenue and
     financial commodity
     contract settlements(1)            90,395    48,663    48,146    52,315
    Funds flow from
     operations                         60,134    27,988    28,688    32,350
      Per unit - basic                   $0.77     $0.70     $0.77     $0.86
    Cash distributions
     per trust unit                      $0.48     $0.57     $0.57     $0.54
    Payout ratio
     (per-unit basis)                      63%       82%       74%       63%
    Net income(2)                       12,671    21,873    16,780    17,858
      Per unit - basic                   $0.19     $0.57     $0.46     $0.49
    Capital expenditures                36,457     2,674    24,289    10,865
    Acquisition
     expenditures, net                       - 1,091,294         -       (33)
    Long-term debt plus
     working capital(3)                313,390   297,451   109,094    92,518
    Total Trust Units -
     outstanding (000's)                78,425    78,359    37,521    37,456
    -------------------------------------------------------------------------
    OPERATIONS
    Average daily production
      Crude oil (bbls/d)                 1,844     1,563     1,610     1,714
      NGLs (bbls/d)                        740       682       784       762
      Natural gas (mcf/d)              115,612    46,753    45,137    42,629
      BOE (at 6:1)                      21,853    10,038     9,917     9,582
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Production revenue includes settlements for financial commodity
        contracts. For 2007, it excludes any unrealized gains or losses
        recorded for financial commodity contracts and excludes the
        reclassification to earnings of gains on hedges held at January 1,
        2007.

    (2) Effective January 1, 2007, the Trust discontinued hedge accounting
        for its financial commodity contracts. See Changes in Accounting
        Policy for further discussion.

    (3) Long-term debt less working capital excludes any derivative asset or
        derivative liability.


    Consolidated Balance Sheets (unaudited)

                                                  September 30,  December 31,
    (thousands)                                           2007          2006
    -------------------------------------------------------------------------
    ASSETS
    Current assets
      Accounts receivable                           $   32,890    $   51,392
      Derivative assets                                 16,757             -
      Prepaid expenses and deposits                      9,675         5,467
      Commodity contracts                                    -         2,959
    -------------------------------------------------------------------------
                                                        59,322        59,818
    Petroleum and natural gas properties
     and equipment                                   1,258,092     1,301,056
    Goodwill                                           453,241       453,241
    Reclamation fund                                     8,910         5,649
    -------------------------------------------------------------------------
                                                    $1,779,565    $1,819,764
    -------------------------------------------------------------------------
    LIABILITIES
    Current
      Accounts payable and accrued liabilities      $   37,085    $   50,426
      Cash distributions payable                        11,128        12,443
      Current bank debt                                 14,338         4,948
      Commodity contracts                                    -         3,123
    -------------------------------------------------------------------------
                                                        62,551        70,940
    Long-term debt (note 5)                            281,500       297,000
    Asset retirement obligation (note 4)                41,587        36,131
    Future income taxes (note 16)                      322,188       318,800
    -------------------------------------------------------------------------
                                                       707,826       722,871
    -------------------------------------------------------------------------
    NON-CONTROLLING INTEREST
    Exchangeable shares (note 6)                             -         4,550
    UNITHOLDERS' EQUITY
      Unitholders' capital (note 7)                    965,520       922,426
      Exchangeable partnership units (note 8)          200,807       218,500
      Contributed surplus                                6,078         2,945
      Accumulated deficit (note 11)                   (102,658)      (51,528)
      Accumulated other comprehensive
       income (note 13)                                  1,992             -
    -------------------------------------------------------------------------
                                                     1,071,739     1,092,343
    -------------------------------------------------------------------------
    Commitments and contingencies (note 17)
    -------------------------------------------------------------------------
                                                    $1,779,565    $1,819,764
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See Notes to Consolidated Financial Statements

    Approval on behalf of the Board of Directors:

    "Signed"                    "Signed"
    STUART G. CLARK             JAMES H. MCKELVIE
    Director                    Director



    Consolidated Statements of Income, Comprehensive Income and Accumulated
    Income (Deficit) (unaudited)

                                    Three Months Ended,    Nine Months Ended,
    (thousands except                     September 30,         September 30,
     per-unit amounts)                 2007       2006       2007       2006
    -------------------------------------------------------------------------
    Revenue
    Production revenue            $  76,749  $  80,847  $ 261,642  $ 173,159
    Financial commodity contract
     settlements (note 3)            12,295      9,548     22,965     14,046
    Unrealized gain (loss) on
     commodity contracts (note 3)      (433)         -     (9,029)         -
    Reclassification to earnings
     of gains on hedges (note 3)      6,243          -     23,069          -
    Royalties                       (13,238)   (16,834)   (48,820)   (36,340)
    Facility income                     568        700      1,853      2,367
    -------------------------------------------------------------------------
                                     82,184     74,261    251,680    153,232
    -------------------------------------------------------------------------
    Expenses
    Transportation system charges     2,932      3,397      9,759      8,668
    Production                        7,406      7,044     23,682     16,172
    General and administrative        3,081      1,905      7,489      5,802
    Elimination of the Executive
     Bonus Plan                           -          -          -      2,872
    Interest and financing            4,285      3,721     12,454      6,104
    Depletion, depreciation
     & accretion                     49,373     53,207    150,346     82,809
    -------------------------------------------------------------------------
                                     67,077     69,274    203,730    122,427
    -------------------------------------------------------------------------
    Income before income taxes       15,107      4,987     47,950     30,805
    Income and other taxes
    Future income tax expense
     (reduction)                     (4,603)    (7,811)    (1,298)   (21,415)
    Current tax                         572          8        572        221
    -------------------------------------------------------------------------
                                     (4,031)    (7,803)      (726)   (21,194)
    -------------------------------------------------------------------------
    Non-controlling interest
     - exchangeable shares                -        119          -        678
    -------------------------------------------------------------------------
    Net income for the period        19,138     12,671     48,676     51,321
    Changes in other
     comprehensive income            (4,318)         -    (15,955)         -
    -------------------------------------------------------------------------
    Comprehensive income             14,820     12,671     32,721     51,321
    -------------------------------------------------------------------------

    Accumulated income (deficit),
     beginning of period            (88,199)   (11,262)   (51,528)      (258)
    Net income                       19,138     12,671     48,676     51,321
    Cash distributions              (33,597)   (37,274)   (99,806)   (86,928)
    -------------------------------------------------------------------------
    Accumulated deficit,
     end of period                $(102,658) $ (35,865) $(102,658) $ (35,865)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Net income per unit (note 15)
    Basic                         $    0.24  $    0.19  $    0.62  $    1.08
    Diluted                       $    0.24  $    0.16  $    0.61  $    0.99

    See Notes to Consolidated Financial Statements



    Consolidated Statements of Cash Flows (unaudited)

                                    Three Months Ended,    Nine Months Ended,
                                          September 30,         September 30,
    (thousands)                        2007       2006       2007       2006
    -------------------------------------------------------------------------
    Operating activities
    Net income for the period     $  19,138  $  12,671  $  48,676  $  51,321
    Items not affecting cash:
      Non-controlling interest
       - exchangeable shares              -        119          -        678
      Non-cash general and
       administrative expenses
       (notes 9 & 10)                 1,928        647      3,536      2,116
      Depletion, depreciation
       and accretion                 49,373     53,207    150,346     82,809
      Non-cash amortization of
       hedging contracts                  -      1,301          -      1,301
      Reclassification to earnings
       of gains on hedges            (6,243)         -    (23,069)         -
      Unrealized (gain) loss on
       commodity contracts              433          -      9,029          -
      Future income tax expense      (4,603)    (7,811)    (1,298)   (21,415)
    Reclamation costs                  (413)         -     (1,234)      (285)
    Net change in non-cash
     working capital items           (3,590)   (24,452)    13,269    (27,664)
    -------------------------------------------------------------------------
                                     56,023     35,682    199,255     88,861
    -------------------------------------------------------------------------
    Financing activities
    Unit issue costs                      -          -          -       (140)
    Proceeds from issue of
     trust units (pursuant
     to Distribution
     Reinvestment Plan)               4,367          -     10,631          -
    Proceeds from exercise of
     unit appreciation rights           372        276      1,300        737
    Increase (decrease) in
     long-term debt                  (4,500)    51,200    (15,500)   205,700
    Distributions paid              (33,542)   (39,586)  (101,120)   (81,101)
    -------------------------------------------------------------------------
                                    (33,303)    11,890   (104,689)   125,196
    -------------------------------------------------------------------------
    Investing activities
    Capital asset additions         (25,624)   (36,457)   (84,129)   (63,420)
    Acquisition expenditures           (278)         -     (4,251)  (142,500)
    Reclamation fund contributions,
     net of costs                    (1,116)    (1,207)    (3,260)    (2,103)
    Net change in non-cash
     working capital items            4,298     (9,911)    (2,926)   (10,730)
    -------------------------------------------------------------------------
                                    (22,720)   (47,575)   (94,566)  (218,753)
    -------------------------------------------------------------------------
    Increase (decrease) in cash
     and cash equivalents during
     the period                           -         (3)         -     (4,696)
    Cash at beginning of period           -          3          -      4,696
    -------------------------------------------------------------------------
    Cash at end of period         $       -  $       -  $       -  $       -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    See Notes to Consolidated Financial Statements



    Notes to Consolidated Financial Statements
    -------------------------------------------------------------------------
    SEPTEMBER 30, 2007 AND 2006 (UNAUDITED)

    1.  STRUCTURE OF THE TRUST

        Focus Energy Trust (the "Trust") was established on August 23, 2002
        under a Plan of Arrangement involving the Trust, Storm Energy Inc.,
        FET Resources Ltd., and Storm Energy Ltd. The Trust is an open-end
        unincorporated investment trust governed by the laws of the Province
        of Alberta and created pursuant to a trust indenture (the "Trust
        Indenture"). Valiant Trust Company has been appointed Trustee under
        the Trust Indenture. The beneficiaries of the Trust are the holders
        of the trust units (the "unitholders").

        Under the Trust Indenture, the Trust may declare payable to
        unitholders all or any part of the income of the Trust. The income of
        the Trust consists primarily of interest earned on promissory notes
        issued to FET Resources Ltd., Focus BC Trust, and FET Energy Ltd.,
        entities that are wholly owned by the Trust, distributions paid on
        subordinated units from Focus BC Trust units owned by the Trust, as
        well as amounts attributed to a net profits interest agreement (the
        "NPI Agreement").

        Pursuant to the terms of the NPI Agreement, the Trust is entitled,
        through a subsidiary, to a payment from FET Resources Ltd. each month
        essentially equal to the amount by which the gross proceeds from the
        sale of production exceed certain deductible expenditures (as
        defined). Under the terms of the NPI Agreement, deductible
        expenditures may include amounts, determined on a discretionary
        basis, to fund capital expenditures, to repay third party debt and to
        provide for working capital required to carry out the operations of
        FET Resources Ltd.

        The taxable income of the Trust includes a deduction for the
        allocation of taxable income to unitholders, which is paid or becomes
        payable in the year. The Trust Indenture provides that an amount at
        least equal to the taxable income of the Trust must be paid or
        payable each year to unitholders in order to reduce the Trust's
        taxable income to zero. Such taxable income relating to the payable
        amount is allocated to unitholders of record at the end of the year,
        and each unitholder at the distribution record date receives a pro
        rata share of the payable amount.

        FET Resources Ltd. (the "Company") is a subsidiary of the Trust.
        Under the Plan of Arrangement, the Company became the successor
        company to Storm Energy Inc. through amalgamation on August 23, 2002.
        The Company is actively engaged in the business of oil and natural
        gas exploitation, development, acquisition and production.

        FET Energy Ltd. is a subsidiary of the Trust. Under a Plan of
        Arrangement with Profico Energy Management Ltd. ("PEML") dated
        June 26, 2006, FET Energy Ltd. become the successor company to PEML
        through amalgamation on June 27, 2006. FET Energy Ltd., through its
        interest in a partnership, is engaged in the business of oil and
        natural gas exploitation, development, acquisition and production.

    2.  SUMMARY OF ACCOUNTING POLICIES

        The consolidated financial statements have been prepared by
        management in accordance with Canadian generally accepted accounting
        principles. The specific accounting principles used are described in
        the annual consolidated financial statements of the Trust and should
        be read in conjunction with these consolidated financial statements.
        The preparation of these consolidated financial statements requires
        management to make estimates and assumptions that affect the reported
        amounts of assets and liabilities and the disclosure of contingencies
        at the date of the financial statements, and revenues and expenses
        during the reporting period. Correspondingly, actual results could
        differ from estimated amounts. These consolidated financial
        statements have, in management's opinion, been properly prepared
        within reasonable limits of materiality.

        In particular, the amounts recorded for depletion and depreciation of
        the petroleum and natural gas properties and equipment and for asset
        retirement obligations are based on estimates of reserves and future
        costs. The cost impairment test is based on estimates of proved
        reserves, production rates, oil and natural gas prices, future costs
        and other relevant assumptions. By their nature, these estimates are
        subject to measurement uncertainty and the impact on the consolidated
        financial statements of future periods could be material.

        The Trust's most significant properties in terms of production and
        capital expenditures, prior to the acquisition of properties from
        PEML, are only accessible by road in the winter. This restricted
        access typically results in higher capital expenditures in the first
        and fourth quarters. Production is typically higher due to flush
        production from the winter drilling program at the end of the first
        quarter and beginning of the second quarter. Production from the new
        wells stabilizes within 12 months. The properties acquired from PEML
        allow year-round access which will reduce the significance of the
        seasonality of operations for the Trust.

    3.  CHANGES IN ACCOUNTING POLICY

        Effective January 1, 2007, the Trust adopted the new recommendations
        of the Canadian Institute of Chartered Accountants (CICA) Handbook
        Section 1530, "Comprehensive Income"; Section 3861, "Financial
        Instruments - Disclosure and Presentation"; Section 3855, "Financial
        Instruments - Recognition and Measurement"; and Section 3865,
        "Hedges", prospectively and therefore the comparative interim
        financial statements have not been restated. These new Handbook
        Sections, which apply to fiscal years beginning on or after
        October 1, 2006, provide requirements for the recognition and
        measurement of financial instruments and on the use of hedge
        accounting.

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

        Increase (decrease) ($ thousands)
        ---------------------------------------------------------------------
        Derivative assets                                             25,950
        Derivative liabilities                                             -
        Future income tax liability                                   (8,003)
        ---------------------------------------------------------------------
        Accumulated other comprehensive income
          Hedges, net of income taxes                                 17,947
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The following table summarizes the income statement (before tax)
        effects of the financial commodity contracts:

                                                 Three Months    Nine Months
                                                        Ended,         Ended,
                                                 September 30,  September 30,
                                                         2007           2007
        ---------------------------------------------------------------------
        Financial commodity contract settlements      $12,295        $22,965
        Unrealized gain (loss) on
         commodity contracts                             (433)        (9,029)
        Reclassification to earnings of
         gains on hedges                                6,243         23,069
        ---------------------------------------------------------------------
                                                      $18,105        $37,005
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (a) Financial Instruments - Recognition and Measurement

        This new standard requires all financial instruments within its
        scope, including all derivatives, to be recognized on the balance
        sheet initially at fair value. Changes to the measurement of existing
        financial assets and liabilities at the date of adoption were
        adjusted to opening accumulated other comprehensive income as noted
        above.

        (b) Derivatives

        The Trust continues to utilize financial derivatives and non-
        financial derivatives, such as commodity sales contracts requiring
        physical delivery, to manage a portion of the price risk attributable
        to future sales of petroleum and natural gas production.

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

        Subsequent changes in fair value of derivatives that are not
        designated or do not qualify for hedge accounting are recognized in
        net earnings as incurred.

        Prior to January 1, 2007, the Trust applied hedge accounting to its
        financial derivatives. On January 1, 2007, the Trust discontinued
        hedge accounting for all existing financial derivatives. Net
        derivative gains of $17.9 million in accumulated other comprehensive
        income at January 1, 2007 are reclassified to earnings in future
        periods as the original hedged transactions affect net earnings. From
        that date forward, the changes in fair value of such derivatives will
        be recognized in net earnings when incurred. Discontinuing hedge
        accounting will not affect the Trust's reported financial position or
        cash flows.

        (c) Embedded Derivatives

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

        (d) Other Comprehensive Income

        The new standards require a new statement of comprehensive income,
        which consists of net earnings and other comprehensive income which,
        for the Trust, relates to changes in gains or losses on derivatives
        previously designated as hedges. This information is contained in
        Note 13.

    4.  ASSET RETIREMENT OBLIGATION

        The Trust's asset retirement obligations result from net ownership
        interests in petroleum and natural gas assets including well sites,
        gathering systems and processing facilities. The Trust estimates the
        total undiscounted amount of cash flows required to settle its asset
        retirement obligations is approximately $97.4 million which will be
        incurred between 2007 and 2040. The majority of the costs will be
        incurred after 2021. A credit-adjusted risk-free rate of 7.5 percent
        and an inflation rate of 2.1 percent were used to calculate the fair
        value of the asset retirement obligation.

        A reconciliation of the asset retirement obligation is provided
        below:

        ---------------------------------------------------------------------
        (thousands)                                         2007        2006
        ---------------------------------------------------------------------
        Balance, beginning of period                     $36,131     $15,090
          Accretion expense                                2,236       1,307
          Development activity and change in estimates     4,454         425
          Acquisition of PEML assets                           -      14,570
          Settlement of liabilities                       (1,234)       (285)
        ---------------------------------------------------------------------
        Balance as at September 30                       $41,587     $31,107
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    5.  LONG-TERM DEBT

        As at September 30, 2007 the Trust has a $350 million revolving
        syndicated credit facility among four Canadian financial institutions
        with an extendible 364-day revolving period and a two-year
        amortization period. In addition, the Trust has a $15 million demand
        operating line of credit. At September 30, 2007, the available
        borrowings under these facilities were reduced by $3.0 million of
        letters of credit. The credit facilities are secured by a floating
        charge debenture covering all of the assets of the Trust and a
        general security agreement.

        Advances bear interest at the bank's prime rate, bankers' acceptance
        rates plus stamping fees, or U.S. LIBOR rates plus applicable margins
        depending on the form of borrowing by the Trust. Stamping fees and
        margins vary from zero percent to 1.5 percent dependent upon
        financial statement ratios and type of borrowing. The effective rate
        on debt outstanding at September 30, 2007 is approximately
        5.33 percent.

        The credit facility will revolve until June 24, 2008, whereupon it
        may be renewed for a further 364-day term subject to review by the
        lenders. If not extended, principal payments will commence after
        expiry of the revolving period and will consist of three quarterly
        payments of eight and one-third percent commencing 15 months after
        the term date and the remaining 75 percent at the end of the term.

    6.  NON-CONTROLLING INTEREST - EXCHANGEABLE SHARES

        The exchangeable shares of FET Resources Ltd. were convertible at any
        time into trust units (at the option of the holder) based on the
        exchange ratio. The exchange ratio was increased monthly based on the
        cash distribution paid on the trust units divided by the ten-day
        weighted average unit price preceding the record date. The
        exchangeable shares of FET Resources Ltd. were listed for trading on
        the Toronto Stock Exchange under the symbol FTX.

        The exchangeable shares of FET Resources Ltd. were redeemable by FET
        Resources Ltd. at any time when the aggregate number of issued and
        outstanding exchangeable shares was less than 1,000,000. As a result
        of a minimal number of exchangeable shares outstanding, FET Resources
        Ltd. elected to redeem all of its exchangeable shares outstanding on
        January 16, 2007. In connection with this redemption, FET Resources
        Ltd. exercised its overriding redemption call right to purchase such
        exchangeable shares from holders of record. Each redeemed
        exchangeable share was purchased for trust units of the Trust in
        accordance with the exchange ratio in effect at January 15, 2007,
        rounded to the nearest whole trust unit. A Notice of Redemption was
        mailed to all exchangeable shareholders outlining the terms of this
        redemption.

                                                               Consideration
                                    Number of Shares              (thousands)
        Exchangeable Shares     ---------------------------------------------
         of FET Resources Ltd.      2007        2006        2007        2006
        ---------------------------------------------------------------------
        Balance as at January 1  502,587     560,218   $   4,550   $   4,131
        Net income attributable
         to non-controlling
         interest                      -           -           -         678
        Exchanged for trust
         units                  (502,587)    (54,731)     (4,550)       (440)
        ---------------------------------------------------------------------
        Balance as at
         September 30                  -     505,487   $       -   $   4,369
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    7.  UNITHOLDERS' CAPITAL

        An unlimited number of trust units may be issued pursuant to the
        Trust Indenture. Each trust unit entitles the holder to one vote at
        any meeting of the unitholders and represents an equal fractional
        undivided beneficial interest in any distribution from the Trust and
        in any net assets in the event of termination or winding up of the
        Trust. The trust units are redeemable at the option of unitholders up
        to a maximum of $250,000 per annum. This limitation may be waived at
        the discretion of the Trust.

        In October 2006, the Trust put in place the Distribution Reinvestment
        and Optional Trust Unit Purchase Plan ("DRIP Plan") which provides
        the option for unitholders to reinvest cash distributions into
        additional units, either issued from treasury at 95 percent of the
        prevailing market price or through the facilities of the Toronto
        Stock Exchange at prevailing market rates with no additional
        commissions or fees. To date the Trust has issued units from treasury
        at a discount to satisfy the distribution reinvestment component of
        the DRIP Plan. The Trust will determine and announce, prior to each
        distribution payment date, the amount of equity, if any, that will be
        made available from treasury under the DRIP Plan on that date. As at
        September 30, 2007, the Trust has listed and reserved 311,033 trust
        units for the DRIP Plan.

                                                               Consideration
                                         Number of Units          (thousands)
        Trust Units of Focus     --------------------------------------------
         Energy Trust                   2007        2006      2007      2006
        ---------------------------------------------------------------------
        Balance as at January 1   67,768,125  36,687,167  $922,426  $244,426
        Issued pursuant to Plan
         of Arrangement
         with PEML(i)                         30,802,817             672,901
        Issued on conversion of
         exchangeable shares(ii)     740,311      77,572    13,066     1,842
        Issued pursuant to the
         Executive Bonus Plan(iii)         -      42,530         -     1,033
        Issued pursuant to the
         Distribution Reinvestment
         Plan(iv)                    630,174           -    10,631         -
        Issued on conversion of
         exchangeable partnership
         units(v)                    809,729           -    17,693         -
        Exercise of Unit
         Appreciation Rights(vi)     353,750      86,500     1,704     1,026
        ---------------------------------------------------------------------
        Balance as at
         September 30             70,302,089  67,696,586  $965,520  $921,228
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    (i)    Issued pursuant to Plan of Arrangement with PEML at a fair value
           of $21.85 per trust unit.

    (ii)   Issued on conversion of exchangeable shares to trust units with
           the consideration recorded being equal to the market value of the
           trust units received on the date of conversion.

    (iii)  Pursuant to the Executive Bonus Plan, 50 percent of all amounts
           due under such plan are payable through the issuance of trust
           units priced at the five day weighted average trading price for
           the last five trading days of the month for which the bonus
           relates. The Executive Bonus Plan was eliminated in 2006.

    (iv)   Issued pursuant to the DRIP Plan, with units issued from treasury
           at 95 percent of the average market price for the 10 days
           immediately preceding the distribution date.

    (v)    Issued on conversion of exchangeable partnership units to trust
           units with the consideration recorded being equal to the
           historical value of the exchangeable partnership units.

    (vi)   Exercise of Unit Appreciation Rights includes cash consideration
           of $1,300,448 (2006 - $736,623) and contributed surplus credit of
           $402,907 (2006 - $289,628).

    8.  EXCHANGEABLE PARTNERSHIP UNITS

        The exchangeable partnership units of Focus Limited Partnership are
        convertible after January 1, 2007 into trust units, at the option of
        the holder, on a one-for-one basis. Cash distributions equal to the
        distribution paid to Trust unitholders are paid to the holders of the
        exchangeable partnership units.

        The Board of Directors may redeem the exchangeable partnership units
        after January 8, 2017, unless certain conditions are met to permit an
        earlier redemption date.

        The exchangeable partnership units are entitled to vote on Focus
        matters with Trust unitholders through the Special Voting Unit. The
        exchangeable partnership units are not listed on any stock exchange
        and are not transferable.

                                                               Consideration
        Exchangeable Partnership         Number of Units          (thousands)
         Units of Focus          --------------------------------------------
         Energy Trust                   2007        2006      2007      2006
        ---------------------------------------------------------------------
        Balance as at January 1    9,999,992           -  $218,500  $      -
        Issued pursuant to Plan
         of Arrangement with PEML          -   9,999,992         -   218,500
        Exchanged for trust units   (809,729)          -    17,693         -
        ---------------------------------------------------------------------
        Balance as at
         September 30              9,190,263   9,999,992  $200,807  $218,500
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The exchangeable partnership units were issued at a fair value of
        $21.85 per unit.

    9.  TRUST UNIT RIGHTS INCENTIVE PLAN

        The Trust Unit Rights Incentive Plan ("Rights Plan") was established
        August 23, 2002 as part of the Plan of Arrangement. The Rights Plan
        granted rights to employees, directors, consultants and other service
        providers of the Trust and any of its subsidiaries.

        At the Annual General and Special Meeting on May 17, 2007,
        unitholders approved amendments to the Rights Plan and approved the
        new Unit Award Incentive Plan ("Unit Award Plan"). The amendments to
        the Rights Plan included reducing the current maximum of 5 percent of
        the outstanding trust units (including trust units issuable upon
        exchange of Focus Limited Partnership B Units) by the number of trust
        units reserved under the Unit Award Plan such that the combined
        maximum number of trust units issuable under the Rights Plan and Unit
        Award Plan will be 5 percent of the outstanding trust units
        (including trust units issuable upon exchange of Focus Limited
        Partnership B Units). To September 30, 2007, the Trust has listed
        and reserved 3,469,571 trust units in respect of the Rights Plan and
        Unit Award Plan.

        There were no further grants under the Rights Plan after May 17,
        2007. At September 30, 2007, there were rights outstanding to
        purchase 2,035,031 trust units pursuant to the terms of the Rights
        Plan.

        The initial exercise price of rights granted under the Rights Plan is
        equal to the weighted average of the closing price of the trust units
        on the immediately preceding five trading days. At the option of the
        unitholder, the exercise price per right is calculated by deducting
        from the grant price the aggregate of all distributions, on a per-
        unit basis, made by the Trust after the grant date which represents a
        return of more than 0.833 percent of the Trust's recorded cost of
        capital assets (excluding any ceiling test write-downs and
        adjustments due to the conversion of exchangeable shares or any other
        fully paid exchangeable securities of the Corporation and Limited
        Partnership units of Focus Limited Partnership into trust units) less
        depletion, depreciation and amortization charges and any future
        income tax liability associated with such capital assets at the end
        of each month. Provided this test is met, then the entire amount of
        the distribution is deducted from the grant price. Rights granted
        prior to June 2006 have a life of five years and vest equally over a
        four-year period commencing on the first anniversary of the grant.
        Rights granted under the Rights Plan subsequent to May 2006 have a
        life of four years and vest equally over a three-year period
        commencing on the first anniversary of the grant.

                                                  2007                  2006
                                 --------------------------------------------
                                              Weighted              Weighted
                                               Average               Average
                                  Number of   Exercise  Number of   Exercise
                                     Rights      Price     Rights      Price
        ---------------------------------------------------------------------
        Balance as at January 1   2,438,063  $   16.52  1,311,100  $   12.52
        Granted                      52,670  $   18.16  1,244,446  $   23.03
        Exercised                  (353,750) $    4.82    (86,500) $    8.52
        Forfeitures                (101,952) $   21.54    (95,000) $   21.34
        ---------------------------------------------------------------------
        Before reduction of
         exercise price           2,035,031  $   18.34  2,374,046  $   17.82
        Reduction of
         exercise price                   -  $   (1.09)         -  $   (1.00)
        ---------------------------------------------------------------------
        Balance as at
         September 30             2,035,031  $   17.25  2,374,046  $   16.82
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        -  The average exercise price at the grant date was $20.75.

        -  The average contractual life of the rights outstanding is
           2.5 years.

        -  The number of rights exercisable at September 30, 2007 is 588,100.

        -  The average fair value at the grant date for the nine months ended
           September 30, 2007 is $4.91.  The fair value of rights is
           estimated using a modified Black Scholes option pricing model and
           amortized over the vesting period.

        The Trust has recorded non-cash compensation expense of $766,010 and
        $2,373,481 for the quarter and nine months ended September 30, 2007.
        The Trust recorded non-cash compensation expense of $647,301 and
        $1,312,019 for the quarter and nine months ended September 30, 2006.

    10. UNIT AWARD INCENTIVE PLAN

        At the Annual General and Special Meeting on May 17, 2007,
        unitholders approved a Unit Award Plan which authorizes the Board of
        Directors to grant awards of restricted trust units ("RTUs") and
        performance trust units ("PTUs"). On July 11, 2007 the Board of
        Directors approved the initial grant of RTUs and PTUs.

        The Unit Award Plan will settle in trust units which may be issued
        from treasury or purchased on the Toronto Stock Exchange. The number
        of trust units reserved under the Unit Award Plan is such that the
        combined maximum number of trust units issuable under the Rights Plan
        and Units Award Plan will be 5 percent of the outstanding trust units
        (including trust units issuable upon exchange of Focus Limited
        Partnership B Units). The number of RTUs is fixed and will vest over
        a period of two years and nine months. The number of PTUs issued is
        dependent upon the performance of the Trust and will vest over a
        period of two years and nine months. The number of PTUs issued is
        dependent upon the payout multiplier which will vary between zero and
        two. The payout multiplier is determined annually and is based on
        value measures ratios as defined by the Board of Directors.

        The Trust recorded non-cash compensation expense of $1.2 million for
        the nine and three months ended September 30, 2007. The compensation
        expense is based on the fair value of the trust units on the date of
        grant, and the PTU portion is based on an estimated payout multiplier
        of one. Compensation expense is recognized in income over the two
        years and nine month vesting period with a corresponding increase in
        contributed surplus.

        At settlement dates, holders of RTUs and PTUs will receive additional
        trust units in respect of accrued cumulative distributions relating
        to those units from the grant date to settlement date. These
        additional trust units to be issued for accrued cumulative
        distributions are accounted for in equity with a corresponding
        payable. The accrued distribution amount for the three and nine
        months ended September 30, 2007 was $0.3 million. This is also
        accounted for over the two year and nine month vesting period.

        The following table summarizes the restricted trust unit and
        performance trust unit movement for the nine months ended
        September 30, 2007:

                                                         Number of Number of
                                                              RTUs      PTUs
        ---------------------------------------------------------------------
        Balance, beginning of period                             -         -
        Granted                                            325,317   608,502
        Forfeited                                           (4,506)   (1,503)
        ---------------------------------------------------------------------
        Balance as at
         September 30, 2007                                320,811   606,999
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    11. ACCUMULATED INCOME (DEFICIT)

        (thousands)                                           2007      2006
        ---------------------------------------------------------------------
        Accumulated income, before cash distributions     $308,601  $225,608
        Accumulated distributions(1)                      (411,259) (261,473)
        ---------------------------------------------------------------------
        Balance as at September 30                       $(102,658) $(35,865)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (1)   Included in accumulated distributions are the accrued
              cumulative distributions related to the Unit Award Incentive
              Plan.  See Note 10 of the notes to consolidated financial
              statements for further discussion.

    12. FINANCIAL INSTRUMENTS

        As described in Note 3 of the notes to consolidated financial
        statements, on January 1, 2007 Focus adopted the new CICA
        requirements relating to financial instruments.

        The Company's financial instruments included in the balance sheet
        consist of accounts receivable, other receivables, accounts payable
        and accrued liabilities and bank debt.

        Credit risk:

        The Company's accounts receivable are due from a diverse group of
        customers and as such are subject to normal credit risks.

        Interest rate risk:

        The Company is also exposed to interest rate risk to the extent that
        long-term debt is at a floating rate of interest.

        Fair values:

        The fair values of short-term financial instruments, being accounts
        receivable, accounts payable and accrued liabilities and cash
        distributions payable approximate their carrying values due to their
        short term to maturity.  The fair value of long-term debt
        approximates its carrying value due to the floating interest rate and
        the revolving nature of the obligation.

        The following financial contracts were outstanding at the date of
        writing.

        Financial        Daily           Contract     Price
        Contracts     Quantity              Price     Index             Term
        ---------------------------------------------------------------------
        Crude oil     400 bbls  $ 70.00-79.00 Cdn       WTI   October 2007 -
                                                               December 2007
                      400 bbls  $ 70.00-79.00 Cdn       WTI   January 2008 -
                                                                 June 2008(*)
                      400 bbls  $       78.53 Cdn       WTI   January 2008 -
                                                             December 2008(*)
        Natural gas   7,300 GJ  $        7.70 Cdn      AECO     October 2007
                     15,000 GJ  $        7.77 Cdn      AECO     October 2007
                     10,000 GJ  $        7.90 Cdn      AECO     October 2007
                      5,000 GJ  $        8.00 Cdn      AECO     October 2007
                      5,000 GJ  $        7.52 Cdn      AECO     October 2007
                      5,000 GJ  $        7.50 Cdn      AECO     October 2007
                      5,000 GJ  $        7.53 Cdn      AECO     October 2007
                      5,000 GJ  $        7.50 Cdn      AECO     October 2007
                     15,000 GJ  $   8.25-9.00 Cdn      AECO  November 2007 -
                                         9.00 Cdn                 March 2008
                     15,000 GJ  $        8.02 Cdn      AECO  November 2007 -
                                                                  March 2008
                     10,000 GJ  $        8.60 Cdn      AECO  November 2007 -
                                                                  March 2008
                     15,000 GJ  $        6.35 Cdn      AECO     April 2008 -
                                                              October 2008(*)
        ---------------------------------------------------------------------
        (*)contract entered into subsequent to September 30, 2007

        New CICA Handbook Standards, Section 3855 "Financial Instruments -
        Recognition and Measurement", Section 3865 "Hedges", and Section 1530
        "Comprehensive Income" are applicable for the Trust beginning in
        2007.

        As a result, hedge accounting for financial contracts has not been
        continued in future periods beyond 2006. All derivative contracts
        commencing January 1, 2007 are recorded at fair value on the balance
        sheet. Derivatives are adjusted to fair value each period with the
        change recognized in the determination of income. Settlement of
        derivatives is included in the Statement of Cash Flows as an
        operating activity. Unrealized gains and losses are subtracted or
        added back as a non-cash item.

    13. ACCUMULATED OTHER COMPREHENSIVE INCOME

        (thousands)                                                     2007
        ---------------------------------------------------------------------
        Accumulated other comprehensive income,
         beginning of period                                        $      -
        Adoption of financial instruments (notes 3 and 13),
         net of tax ($8.0 million)                                    17,947
        Reclassification to earnings of gains on hedges,
         net of tax ($7.1 million)                                   (15,955)
        ---------------------------------------------------------------------
        Balance as at September 30                                  $  1,992
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        As described in Note 3 of the notes to consolidated financial
        statements, on January 1, 2007 Focus adopted the new CICA
        requirements relating to financial instruments. The new standards
        require a new statement of comprehensive income, which consists of
        net earnings and other comprehensive income which, for the Trust,
        relates to changes in gains or losses on derivatives previously
        designated as cash flow hedges.

        At December 31, 2006 the fair value of the Trust's outstanding hedges
        was $25.8 million. The adjustment to accumulated other comprehensive
        income is shown net of tax. This value will be reclassified and
        brought through income over the life of the original contracts until
        March 2008 at which time the balance will be nil.

    14. PHYSICAL SALES CONTRACTS

        In addition to the financial contracts described above, the following
        physical contracts were outstanding at the date of writing. The fair
        market value of these contracts at September 30, 2007, which have no
        book value, would have resulted in a net payment to the Trust of
        $6.8 million.

                                         Daily    Contract
        Physical Sales Contracts      Quantity       Price              Term
        ---------------------------------------------------------------------
        Natural gas - fixed price    15,000 GJ   $7.15 Cdn      October 2007
                                     10,000 GJ   $7.18 Cdn      October 2007
                                     10,000 GJ   $8.96 Cdn   November 2007 -
                                                                  March 2008
                                     10,000 GJ   $7.12 Cdn   November 2007 -
                                                                  March 2008
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    15. PER-UNIT AMOUNTS AND SUPPLEMENTARY CASH FLOW INFORMATION

        Basic per-unit calculations are based on the weighted average number
        of trust units and exchangeable partnership units outstanding during
        the period. Diluted per-unit calculations include additional trust
        units for the dilutive impact of rights outstanding pursuant to the
        Rights Plan and include exchangeable partnership units and
        exchangeable shares converted at the average exchange ratio.

        Basic per-unit calculations for the three-month period ended
        September 30 are based on the weighted average number of trust units
        outstanding in 2007 of 79,310,594 (2006 of 77,638,100). Basic per-
        unit calculations for the nine-month period ending September 30, 2007
        are based on the weighted average number of trust units outstanding
        in 2007 of 78,956,374 (2006 of 51,126,735).

        Diluted calculations for the three-month period ended September 30
        include additional trust units for the dilutive impact of the Rights
        Plan in 2007 of 79,661,704 (2006 of 540,451) and nil exchangeable
        shares (2006 of 761,279) converted at the average exchange rate. Net
        income has been increased for the net income attributable to the
        exchangeable shareholders in calculating dilutive per-unit amounts.
        Diluted calculations for the nine-month period ended September 30,
        include additional trust units for the dilutive impact of the Rights
        Plan and the Unit Award Plan in 2007 of 79,291,404 (2006 of 523,998)
        and 40,953 for exchangeable shares (2006 of 765,691) converted at the
        average exchange rate.

        Supplementary cash flow information for the nine months ended
        September 30:

        (thousands)                                          2007       2006
        ---------------------------------------------------------------------
        Interest paid                                   $  15,196  $   8,396
        Interest received                               $     130  $      17
        Taxes paid                                      $      95  $  26,593
        Cash distributions paid                         $ 100,861  $  81,101
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    16. INCOME TAXES

        On June 22, 2007, Bill C-52, the Federal Government's legislation
        containing provisions to impose a tax on publicly traded income
        trusts and partnerships, received Royal Assent. The legislation
        includes a 31.5 percent tax for taxation years beginning in 2011 on
        income of the Trust before distributions. Distributions will
        effectively be taxed as a dividend to the taxable Canadian investor.

        Certain of the Trust's assets are held by entities which transfer
        taxable income to unitholders. Prior to the legislation becoming
        enacted, future income taxes were not required to be recorded on
        temporary differences related to the carrying value of these assets
        over their tax value. As a result of the legislation becoming
        enacted, the Trusts' tax status has changed for purposes of Canadian
        accounting guidelines. A non-cash, future income tax expense of
        $13.8 million was recorded on these temporary differences in the
        second quarter of 2007 because of this change in tax status.

        The Federal Government also announced a reduction in the general
        corporate tax rate in 2011 to 18.5 percent. Prior to that, the
        government had announced a reduction in the general corporate tax
        rate from 21 percent to 19 percent from 2007 to 2010 and the
        elimination of the corporate surtax in 2008. The Saskatchewan
        general corporate tax rate decreased from 14 percent to 13 percent on
        July 1, 2007 and will further decrease to 12 percent on July 1, 2008.

    17. COMMITMENTS AND CONTINGENCIES

        The Trust is involved in litigation and claims arising in the normal
        course of operations. Management is of the opinion that any
        resulting settlements would not materially affect the Trust's
        financial position or reported results in operations.

        The following table is a summary of all contractual obligations and
        commitments for the next five years.

                                                                        2012
                                                                         and
                                                       2008-   2010-  there-
        ($ thousands)                  Total    2007    2009    2011   after
        ---------------------------------------------------------------------
        Office premises                3,407     761   1,920     726       -
        Operating leases                 731     422     309       -       -
        Mineral and surface
         leases(2)                    29,196   4,866   9,732   9,732   4,866
        Transportation and
         processing                   29,925  13,343  11,484   1,881   3,217
        Asset retirement
         obligations(3)               41,587   1,308     486     950  38,843
        ---------------------------------------------------------------------
        Total contractual
         obligations                 104,846  20,700  23,931  13,289  46,926
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (1)   The table does not include the Trust's obligations for
              financial instruments and physical sales contracts which are
              fully disclosed in Notes 12 and 14.

        (2)   The Trust makes payments for mineral and surface leases. The
              table includes payments for each of the years 2007 to 2012
              under these leases, assuming continuation of the leases. The
              continuation of leases is based on decisions by the Trust
              relating to each of the underlying properties. Payments for the
              period after 2012 have not been included in the table but would
              continue at the same yearly rate if there were no change to the
              underlying properties.

        (3)   Based on the estimated timing of expenditures to be made in
              future periods.

        In addition, the Trust has income and capital tax filings that are
        subject to audit and potential reassessment. The findings from such
        audit may impact the tax liability of the Trust. The final results
        are not reasonably determinable at this time and management believes
        it has adequately provided for income and capital taxes.

    Focus Energy Trust is a natural gas weighted energy trust. Focus is
committed to maintaining its emphasis on operating high-quality oil and gas
properties, delivering consistent distributions to unitholders and ensuring
financial strength and sustainability.

    Focus Energy Trust units trade on the TSX under the symbol FET.UN.
    

    %SEDAR: 00018353E




For further information:

For further information: Derek W. Evans, President and Chief Executive
Officer or Bill Ostlund, Senior Vice President and Chief Financial Officer,
Focus Energy Trust, Suite 3300, 205 - 5 Avenue S.W., Calgary, Alberta, T2P
2V7, Telephone: (403) 781-8409, Fax: (403) 781-8408

Organization Profile

FOCUS ENERGY TRUST

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