Focus Energy Trust announces 2006 financial & operating results



    CALGARY, March 8 /CNW/ - Focus Energy Trust ("Focus") (FET.UN - TSX) is
pleased to report its 2006 year-end consolidated financial and operating
results.

    
    CONSOLIDATED HIGHLIGHTS
                                                                         Year
    (thousands of            Three Months Ended           Years Ended    Over
     dollars except                 December 31,          December 31,   Year
     where indicated)           2006       2005       2006       2005  Change
    -------------------------------------------------------------------------
    FINANCIAL
    Oil and gas revenues,
     before transportation
     system charges and
     royalties                98,434     52,315    285,639    191,669    49%
    Funds flow from
     operations(1)            64,412     32,350    181,223    116,368    56%
      Per unit(2)(3)       $    0.82  $    0.86  $    3.09  $    3.12    (1%)
    Cash distributions
     per trust unit
      Per unit             $    0.48  $    0.54  $    2.10  $    2.02     4%
      Payout ratio
       (per-unit basis)          59%        63%        68%        65%     3%
    Net income                21,646     17,858     72,967     63,464    15%
      Per unit             $    0.28  $    0.49  $    1.26  $    1.74   (28%)
    Capital expenditures(4)   26,986     10,865     90,406     43,035   101%
    Acquisitions(4)               45        (33) 1,091,339     10,363
    Long-term debt less
     working capital         308,122     92,518    308,122     92,518   233%
    Total Trust Units -
     outstanding (000's)(3)   78,504     37,456     78,504     37,456   109%
    Weighted average Total
     Trust Units (000's)(5)   78,453     37,442     58,583     37,344    57%
    -------------------------------------------------------------------------
    OPERATIONS
    Average daily production
      Crude oil (bbls/d)       1,965      1,714      1,747      1,765    (1%)
      NGLs (bbls/d)              706        762        728        777    (6%)
      Natural gas (mcf/d)    113,539     42,629     80,544     44,526    81%
      Barrels of oil
       equivalent (at 6:1)    21,594      9,582     15,899      9,963    60%
    Average product prices
     realized, net of
     transportation system
     charges(6)
      Crude oil (CDN$/bbl) $   57.51  $   59.20  $   65.61  $   56.61    16%
      NGLs (CDN$/bbl)      $   53.85  $   60.64  $   61.52  $   57.50     7%
      Natural gas
       (CDN$/mcf)          $    7.80  $    9.24  $    7.37  $    7.92    (7%)
    Field netback per BOE
      Revenue(6)           $   48.09  $   56.61  $   47.45  $   49.97    (5%)
      Royalties, net of
       ARTC                $   (8.94) $  (13.41) $   (9.32) $  (11.98)  (22%)
      Production expenses  $   (4.04) $   (4.61) $   (4.17) $   (4.11)    1%
      Field netback        $   35.11  $   38.58  $   33.96  $   33.88     0%
    Wells drilled
      Gross                       56          6        227         37   514%
      Net                       46.3        4.8      190.3       29.4   547%
      Success rate              100%       100%       100%       100%      -
    -------------------------------------------------------------------------
    TRUST UNIT TRADING
     STATISTICS
    Unit prices
      High                 $   24.30  $   26.74  $   25.89  $   26.74
      Low                  $   17.09  $   19.72  $   17.09  $   18.60
      Close                $   18.18  $   25.72  $   18.18  $   25.72   (29%)
    Daily average trading
     volume                  288,131    103,540    220,668    100,967   119%
    -------------------------------------------------------------------------

    RESERVES
    Proved plus probable(7)
      Crude oil (mbbls)                              5,239      5,608    (7%)
      NGLs (mbbls)                                   3,267      3,420    (4%)
      Natural gas (Mmcf)                           450,938    187,506   140%
      Barrels of oil
       equivalent (at 6:1)                          83,662     40,279   108%
    Reserve life index of
     proved plus probable(8)                           9.9       10.5    (6%)
    Gas weighting of proved
     plus probable reserves                            90%        78%    12%
    Proved reserves/proved
     plus probable reserves                            74%        77%    (3%)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) 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.

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

    (3) 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 1.46445 at
        December 31, 2006 and 1.37265 at December 31, 2005. These shares were
        redeemed for trust units on January 16, 2007. Each exchangeable
        partnership unit is exchangeable into one trust unit.

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

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

    (6) Net of settlements for financial hedging instruments and net of
        transportation system charges.

    (7) Reserve numbers are total proved plus probable company gross reserves
        (before deduction of royalties payable, not including royalties
        receivable) as defined in National Instrument 51-101.

    (8) Reserve life index is calculated by dividing year-end reserves by the
        forward year production estimate from the reserve reports.
    


    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, 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

    
    -   The most significant event for Focus during the year was the
        acquisition of Profico Energy Management Ltd. ("PEML") effective
        June 27th, 2006 which added a new core area and more than doubled
        production, reserves, undeveloped land and drilling inventory. The
        assets acquired are long life gas pools in the early stage of
        development, 98 percent weighted to natural gas and characterized by
        high working interest, operated production, low production expenses,
        low Crown royalty rates and a dominant land position.

    -   The addition of the PEML Shackleton asset in Southwest Saskatchewan
        strengthened our commitment to long-life natural gas production in
        one of the lowest cost operating environments in the Western Canadian
        Sedimentary Basin. In addition, we have a new core area that provides
        greater asset diversification and a balanced year-round operation.

    -   Production averaged 15,899 BOE per day in 2006, the highest in the
        Trust's history. The increase in annual and fourth quarter production
        is primarily a result of the Q2 2006 PEML acquisition. Production per
        unit was flat on a year-over-year basis and on a debt-adjusted basis
        decreased by 2.9 percent to 0.23 BOE per day per thousand units in
        2006, from 0.24 BOE per day per thousand units in 2005.

    -   Focus realized record funds flow from operations of $181 million in
        2006 largely as a result of the PEML acquisition. On a per-unit
        basis, funds flow of $3.09 in 2006 was essentially flat to 2005
        funds flow per unit of $3.12 even though average AECO prices
        decreased by 25 percent from $8.77 per mcf in 2005 to $6.55 per mcf
        in 2006. The Trust's production mix is approximately 88 percent
        natural gas, and as such gas prices have a large impact on funds
        flow.

    -   The Trust completed its most extensive drilling program to date with
        227 (190.3 net) wells being drilled in 2006 with 100 percent success.
        The majority of the 2006 drilling program was directed towards our
        two core properties with 151.3 net wells drilled at Shackleton and
        13.5 net wells drilled at Tommy Lakes.

    -   Our drilling inventory has expanded materially with the PEML
        acquisition. At the end of 2006 we have in excess of three years of
        drill-ready inventory at Shackleton and Tommy Lakes. The expansion of
        our inventory has been driven by our technical team's ability to
        generate new ideas on our existing asset base.

    -   We continue to add to our undeveloped land position in and around our
        Tommy Lakes and Shackleton assets. Undeveloped land increased from
        57,100 acres in 2005 to 389,500 acres in 2006, largely as a result of
        the PEML acquisition. The 2006 land position includes the Crown sale
        acquisition of 12,320 acres of land in the centre of the Shackleton
        natural gas pool with over 100 Milk River development drilling
        locations.

    -   For 2006, natural gas price protection increased revenue by
        approximately $38.6 million and increased the realized price for
        natural gas by $1.31 per mcf. This compares with a cost of
        $10.9 million or $0.67 per mcf in 2005. For 2007 we have
        approximately 60 percent of gas production price protected at
        $8.26 per mcf.

    -   Effective December 31, 2006, Focus had proved plus probable reserves
        of 83.7 MMBOE, an increase of 108 percent from the 40.3 MMBOE
        recorded at December 31, 2005. The significant increase in reserves
        is due to the PEML acquisition in Q2 of 2006. Reserves per unit are
        essentially flat on a year-over-year analysis, and on a debt-adjusted
        per-unit basis decreased by 10 percent compared to 2005. 2006 proved
        plus probable finding and development costs of $17.89 per BOE
        (including future development capital) represents a recycle ratio of
        1.9 times.

    -   2006 proved plus probable all-in finding, development and acquisition
        (FD&A) costs (including future development capital) of $28.77 are
        governed almost entirely by the PEML acquisition. Through older pool
        analog analysis, we believe that these relatively early stage shallow
        gas pools will see reserves appreciation on the existing producing
        wells and also through identification of additional infill and
        stepout locations.

    -   Our reserve life index continues to be long and the slight decrease
        from 10.5 in 2005 to 9.9 in 2006 will be reversed with the maturing
        of the relatively young Shackleton Milk River assets.

    -   In late 2006 we commenced our fifth Tommy Lakes winter drilling
        program. Twelve (12.0 net) development wells and two (1.0 net)
        exploration wells were drilled. All of these wells have been
        successfully completed and tied in. At Shackleton our winter program
        is also nearing completion. Most importantly, we have finished
        drilling activities in the winter access only portion of the field,
        and are currently completing and pipeline connecting these wells. We
        expect these activities will be completed prior to breakup.

    -   On October 31, 2006 the Federal Government announced tax proposals
        pertaining to the distributions of publicly traded trusts. The tax
        announcement had a significant impact on the Canadian equity market
        with a significant decrease of trust unit prices. Irrespective of
        this taxation announcement, our core business of creating value for
        our unitholders remains intact. We are currently assessing the draft
        legislation and alternatives with respect to the future structure of
        the Trust.
    

    YEAR-END RESERVES

    Based on independent engineering evaluations conducted by Paddock
Lindstrom and Associates Ltd. ("Paddock") and GLJ Petroleum Consultants Ltd.
("GLJ") effective December 31, 2006, Focus had proved plus probable reserves
of 83.7 MMBOE, an increase of 108 percent from the 40.3 MMBOE recorded at
December 31, 2005. Reserve additions from exploration and development
activities (including revisions) were 4.0 MMBOE, while 45.2 MMBOE were added
through acquisition (net of minor dispositions), resulting in total additions
of 49.2 MMBOE. Year-end reserves were evaluated in accordance with National
Instrument 51-101 ("NI 51-101"). Full tabular data relating to reserves, net
present values, price forecasts and reserve addition costs is presented in
Appendix B.
    GLJ and Paddock evaluated 100 percent of the Trust's reserves. The
portion of the evaluation conducted by GLJ represented 54 percent of the
proved plus probable reserves and 51 percent of the associated future net
revenue discounted at 10 percent. The remaining 46 percent of the proved plus
probable reserves and 49 percent of the associated future net revenue were
evaluated by Paddock. The GLJ December 31, 2006 price forecast was used in the
future net revenue determinations for both evaluations. The Trust's Reserves
Committee, made up of independent and qualified directors of the Trust, has
reviewed the reports prepared by GLJ and Paddock and other pertinent reserves
data. The Board of Directors, on the recommendation of the Reserves Committee,
has approved the content of the GLJ and Paddock reports and other reserves
data.
    Proved developed producing reserves represent 47 percent of proved plus
probable reserves, while total proved reserves represent 74 percent of total
proved plus probable reserves. On a BOE basis, total proved plus probable
reserves consist of 90 percent natural gas, six percent crude oil and four
percent natural gas liquids.
    On a proved basis, additions from exploration and development activities
(discoveries and extensions including infill drilling) were 5.7 MMBOE and
technical revisions were negative 1.4 MMBOE, resulting in total additions of
4.3 MMBOE. On a proved plus probable basis, additions from exploration and
development activities were 7.3 MMBOE and technical revisions were negative
3.3 MMBOE, resulting in total additions of 4.0 MMBOE. The proved plus probable
additions including revisions replaced 69 percent of the 5.8 MMBOE produced
during 2006.

    Net Present Value of Future Net Revenue

    The estimated net present value of Focus' crude oil, natural gas and
natural gas liquids reserves was evaluated using GLJ's December 31, 2006 price
forecast prior to provision for income taxes, interest, debt service charges
and general and administrative expenses. At a 10 percent discount rate, the
net present value of the Trust's proved plus probable reserves was
$1,276 million. Proved producing and total proved reserves make up
respectively 63 percent and 79 percent of the total proved plus probable
value.
    On October 31, 2006, the Federal Government announced proposals
pertaining to the taxation of distributions from publicly traded Canadian
income trusts, royalty trusts and partnerships. The proposals include a
31.5 percent tax imposed on income before distributions at the trust level and
taxed to the taxable Canadian investor, effectively as a dividend. If enacted,
the proposals would apply to the Trust effective January 1, 2011. On
December 21, 2006, the Department of Finance issued draft legislation
consistent with the proposals described above. As at December 31, 2006, the
legislative proposals are not substantively enacted. Any changes to income tax
legislation that may result from these proposals may adversely affect the net
present value of future net revenue of Focus' oil and gas reserves.

    Reserve Life Index

    Focus' proved plus probable RLI at year-end 2006 is 9.9 years, down
slightly from the year-end 2005 RLI of 10.5 years. The lower RLI reflects the
shorter reserve life index of the properties acquired in the Profico
transaction. Similarly, the Trust's proved year-end 2005 RLI is 7.7 years as
compared to 8.3 years at year-end 2005, again reflecting the impact of the
acquired properties. These RLIs are calculated using period-end reserves and
forward-year forecast production from the reserves report.

    Reserve Addition Costs

    Under NI 51-101, the methodology to be used to calculate FD&A costs
includes incorporating changes in future development capital ("FDC") required
to bring the proved undeveloped and probable reserves to production. Excluding
acquisitions and divestitures, Focus' 2006 reserve addition costs were
$16.09 per BOE on a proved basis and $17.89 per BOE on a proved plus probable
basis. Including acquisitions and divestitures, 2006 reserve addition costs
were $37.00 per BOE on a proved basis and $28.77 per BOE on a proved plus
probable basis. At year end, total estimated FDC was $259 million for proved
reserves and $337 million for proved plus probable reserves.
    Three-year average reserve addition costs, excluding acquisitions and
divestitures, are $18.30 per BOE on a proved basis and $21.44 per BOE on a
proved plus probable basis. Three-year average reserve addition costs,
including acquisitions and divestitures, are $30.58 per BOE on a proved basis
and $24.80 per BOE on a proved plus probable basis. The Trust believes that
these three-year average costs are the most accurate reflection of our ongoing
reserve addition costs. Using a three-year average mitigates the impact of
year-to-year variability in factors such as acquisition activity, the timing
of the development of proved undeveloped reserves, reserve revisions, and
changes to capital costs and estimates for future development capital.

    Net Asset Value (before tax)

    The following net asset value ("NAV") table shows what is commonly
referred to as a "produce out" NAV calculation before tax. The value is a
snapshot in time and is based on various assumptions including commodity
prices and foreign exchange rates that vary over time.

    
    NAV at December 31, 2006
     (before tax)                   Discounted at 10%      Discounted at 5%
    -------------------------------------------------------------------------
                                              Constant              Constant
    ($ millions except            GLJ Price      Price  GLJ Price      Price
     per-unit amounts)             Forecast   Forecast   Forecast   Forecast
    -------------------------------------------------------------------------
    Value of proved plus probable
     reserves                         1,276        923      1,669      1,181
    Undeveloped lands                    37         37         37         37
    Net debt including working
     capital                           (308)      (308)      (308)      (308)
    Reclamation fund                      6          6          6          6
    Abandonment and reclamation
     liability(1)                        (5)        (3)        (4)        (1)
    -------------------------------------------------------------------------
    Net asset value                   1,006        655      1,400        915
    Total Trust Units outstanding
     (millions)                        78.5       78.5       78.5       78.5
    -------------------------------------------------------------------------
    Per Total Unit (before tax)      $12.81      $8.34     $17.83     $11.65
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) In addition to abandonment and reclamation liability already included
        in reserve reports
    


    Net asset value per unit of $12.81, based on the GLJ Price Forecast and a
10 percent discount rate, decreased 22 percent on a year-over-year basis from
$16.50 at December 31, 2005, driven primarily by a lower commodity price
forecast. Note that the value of reserves does not include the effect of our
price protection program. Including the value of physical and financial
hedging contracts in place at December 31, 2006 would increase our net asset
value per unit from $12.81 to $13.11.

    SUSTAINABILITY

    Five years ago we set out to create a Trust with a strong operational
focus, that utilized the drill bit to create value and focused on a
sustainable business plan. The objective was to provide superior and
sustainable long-term returns to our unitholders. The four elements that we
believe define sustainability are production per unit, reserves per unit,
capital use versus funds flow, and drilling inventory.

    Production and Reserves per Unit

    
    Production per Unit             2006     2005     2004     2003     2002
    -------------------------------------------------------------------------
    Unadjusted(1)                   0.27     0.27     0.27     0.28     0.28
    Debt adjusted(3)                0.23     0.24     0.24     0.25     0.25
    -------------------------------------------------------------------------

    Reserves per Unit               2006     2005     2004     2003     2002
    -------------------------------------------------------------------------
    Unadjusted(2)                   1.07     1.08     1.11     0.93     0.96
    Debt adjusted(4)                0.88     0.98     1.01     0.88     0.86
    -------------------------------------------------------------------------
    (1) Average daily production per thousand units divided by weighted
        average total trust units

    (2) Proved plus probable reserves divided by period-end total trust units

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

    (4) Debt adjusted assumes year-end debt eliminated by adding units equal
        to the end of period debt divided by the closing unit price.
    


    Production per unit is a proxy for funds flow. Stable funds flow is
important in that it allows for stable capital and distribution programs. On
an unadjusted basis, production per unit has remained essentially flat since
inception of the Trust. On a debt-adjusted basis, production per unit
decreased by 2.9 percent to 0.23 from 0.24 in 2005. This decrease is the
result of lower than anticipated production levels, and the seasonality of
production additions. Production per unit on a debt-adjusted basis has
decreased by approximately 8 percent over the last five years.
    Reserves per unit is an important metric, as it points to whether value
is being created on a year-over-year basis. On an unadjusted basis the Trust's
per-unit reserves have increased by 11.5 percent since the Trust's inception,
with a corresponding 2.3 percent increase on a debt-adjusted basis.
    On a debt-adjusted basis, 2006 reserves per unit decreased by 10 percent
as compared to 2005. The decrease is impacted by the 29 percent drop in our
year-end unit prices on a year-over-year basis as well as the relative
immaturity of the Shackleton asset base which will see reserve appreciation as
it matures. We anticipate seeing reserve appreciation on the existing
producing wells as well as through identification of additional infill and
stepout locations.

    Financial Sustainability

    
    ($ millions)            2006    2005    2004    2003    2002  Cumulative
    -------------------------------------------------------------------------
    Capital Expenditures    90.4    43.0    25.2    16.8     4.1       179.6
    Distributions          124.2    73.7    61.4    41.0    11.1       311.4
    Reclamation fund &
     expenditures            3.2     1.4     1.0     1.3       -         6.9
    -------------------------------------------------------------------------
      Total                217.8   118.1    87.6    59.1    15.2       497.9
    Available funds flow   181.2   116.4    89.6    65.8    19.0       472.0
    -------------------------------------------------------------------------
      Difference           (36.6)   (1.8)    2.0     6.7     3.8       (25.9)
    -------------------------------------------------------------------------
    


    We adhere to a business strategy of sustainability where the sum of
capital expenditures, distributions and reclamation obligations is equal to or
less than funds flow. The above table demonstrates our performance in this
regard since Trust inception and points to 2006 where we had a significant
difference between available funds flow and total expenditures of $36.6
million. This difference resulted from the rapid decline in 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
programs, into the fourth quarter.
    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
distributions levels.

    Inventory

    
                                    2006     2005     2004     2003     2002
    -------------------------------------------------------------------------
    Reserve life index               9.9     10.5     10.6      9.8      9.1
    Undeveloped land
     (000's of net acres)          389.5     57.1     26.9     14.4     14.4
    -------------------------------------------------------------------------
    


    Our drilling inventory and undeveloped land have expanded materially with
the PEML acquisition. At the end of 2006 we have in excess of three years of
drill-ready inventory at Shackleton and Tommy Lakes. In addition, we have
concrete plans at both properties to expand that drill-ready inventory by
extending pool boundaries onto the surrounding undeveloped land.
    We continue to add to our land position in and around Shackleton and
Tommy Lakes. In August we increased our Shackleton land position with the
acquisition of 12,320 acres of additional land in the centre of the Shackleton
pool with over 100 Milk River drilling locations.
    The expansion of our drilling inventory in both breadth and depth has
been driven by the PEML acquisition, the August Saskatchewan land sale and our
technical team's efforts and ability to generate new ideas on our existing
asset base. Key strengths within Focus are the concentration and quality of
its long life natural gas assets, combined with an extensive undeveloped land
position surrounding the large natural gas pools, low operating costs and low
royalty rates resulting in attractive netbacks through all parts of the
commodity price cycle.

    RESULTS OF OPERATIONS

    The following is a discussion and analysis of the operating and financial
results of Focus for the three months and year ended December 31, 2006
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 March 5, 2007 and should be read in conjunction with the
Trust's audited consolidated financial statements for the years ended
December 31, 2006 and 2005, together with accompanying notes.
    The consolidated financial statements and accompanying notes for the
quarter and year ended December 31, 2006 are attached as Appendix A.
    Throughout this discussion, 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.
    Per barrel of oil equivalent ("BOE") amounts have been calculated using a
conversion of six thousand cubic feet of natural gas to one barrel of oil
(6 mcf equals 1 bbl).

    
                                                                        Year
                            Three Months Ended         Years Ended      Over
                                       Dec. 31,            Dec. 31,     Year
    OPERATIONS SUMMARY          2006      2005      2006      2005    Change
    -------------------------------------------------------------------------
    Average daily production
      Barrels of oil
       equivalent (at 6:1)    21,594     9,582    15,899     9,963       60%
      % Natural gas              88%       74%       84%       74%
    Average product prices
     realized(1)
      Crude oil sales
       (CDN$/bbl)           $  58.27  $  68.95  $  68.31  $  66.81        2%
        Financial hedging
         settlements
         (CDN$/bbl)         $  (0.76) $  (9.75) $  (2.70) $ (10.20)     (74%)
    -------------------------------------------------------------------------
        Realized price
         (CDN$/bbl)         $  57.51  $  59.20  $  65.61  $  56.61       16%
    -------------------------------------------------------------------------
      NGLs (CDN$/bbl)       $  53.85  $  60.64  $  61.52  $  57.50        7%
        NGL price/crude
         oil price               92%       88%       90%       86%        4%
      Natural gas sales
       (CDN$/mcf)           $   6.97  $  10.20  $   6.84  $   8.64      (21%)
        Transportation
         system charges
         (CDN$/mcf)         $  (0.33) $  (0.62) $  (0.41) $  (0.61)     (32%)
        Financial hedging
         settlements
         (CDN$/mcf)         $   1.16  $  (0.34) $   0.94  $  (0.11)     958%
    -------------------------------------------------------------------------
        Realized price
         (CDN$/mcf)         $   7.80  $   9.24  $   7.37  $   7.92       (7%)
    -------------------------------------------------------------------------
    Reference prices &
     differential to Focus
     sales price, after
     transportation and
     before price protection
      Crude oil (Edm. Light
       Price CDN$/bbl)      $  64.55  $  71.17  $  72.85  $  68.50        6%
        Differential
         (CDN$/bbl)         $  (6.29) $  (2.22) $  (4.54) $  (1.69)     168%
      Natural gas (AECO
       daily CDN$/mcf)      $   6.99  $  11.43  $   6.55  $   8.77      (25%)
        Differential
         (CDN$/mcf)         $  (0.61) $   0.17  $  (0.48) $  (0.17)    (184%)
    -------------------------------------------------------------------------
    Funds flow from
     operations per BOE
      Production revenue    $  43.79  $  62.62  $  45.06  $  55.00      (18%)
        Financial hedging
         settlements            6.03     (3.27)     4.48     (2.30)
        Transportation
         system charges        (1.74)    (2.74)    (2.09)    (2.73)     (24%)
    -------------------------------------------------------------------------
      Realized price(1)        48.09     56.61     47.45     49.97       (5%)
      Royalties, net of ARTC   (8.94)   (13.41)    (9.32)   (11.98)     (22%)
      Production expenses      (4.04)    (4.61)    (4.17)    (4.11)       1%
    -------------------------------------------------------------------------
      Field netback            35.11     38.58     33.96     33.88        0%
      Facility income           0.38      0.44      0.47      0.54      (13%)
      Business interruption
       insurance                   -         -      0.07         -      100%
      Interest income           0.01      0.01      0.01      0.01        0%
      General and
       administrative,
       cash portion            (0.99)    (1.27)    (0.97)    (1.22)     (20%)
      Elimination of the
       Executive Bonus Plan        -         -     (0.49)        -      100%
      Interest and financing
       and other               (2.09)    (1.07)    (1.77)    (0.97)      82%
      Current and large
       corporations tax            -      0.01     (0.04)    (0.24)     (84%)
    -------------------------------------------------------------------------
      Funds flow from
       operations per BOE   $  32.42  $  36.70  $  31.23  $  32.00       (2%)
    -------------------------------------------------------------------------
    Funds flow from
     operations/field
     netback                     92%       95%       92%       94%       (2%)
    Royalty rate (before
    hedging settlements and
     net of transportation
     system charges)             21%       22%       22%       23%       (1%)
    -------------------------------------------------------------------------
    Production revenue,
     before transportation
     system charges
     ($ thousands)
      Crude oil, before
       hedging settlements    10,563    10,925    43,720    43,182        1%
        Financial hedging
         settlements            (137)   (1,538)   (1,722)   (6,573)     (74%)
      NGLs                     3,497     4,255    16,346    16,321        0%
      Natural gas, before
       transportation system
       charges                72,939    40,017   201,393   140,516       43%
        Financial hedging
         settlements          12,114    (1,345)   27,746    (1,777)
        Non-cash amortization
         of hedging
         contracts(2)           (542)        -    (1,843)        -     (100%)
    -------------------------------------------------------------------------
        Production revenue    98,435    52,315   285,639   191,669       49%
    -------------------------------------------------------------------------
    Funds flow from operations
     ($ thousands)
      Cash flow from
       operating activities   60,008    36,818   150,323   114,744       31%
        Reclamation costs         (8)       34       277       632      (56%)
        Net change in
         non-cash working
         capital items         4,412    (4,502)   30,623       992
    -------------------------------------------------------------------------
        Funds flow from
         operations           64,412    32,350   181,223   116,368       56%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Net of settlements for financial hedging instruments and
        transportation system charges
    (2) See Note 14 of the notes to consolidated financial statements
    


    Overall 2006 Performance

    2006 was a year of significant growth and solid results for Focus in a
business environment which experienced a 25 percent decline in the average
reference price for natural gas and continued cost pressures for the industry.
Focus continued to adhere to its strategy of surfacing value on our existing
assets, maintaining cost efficiencies, maintaining financial strength and
acquiring quality assets. During the year, Focus undertook a large acquisition
of quality assets which will enhance our sustainability, value creation
through drilling, and financial strength going forward.
    The most significant event for Focus during the year was the acquisition
of PEML effective June 27, 2006 which added a new core area and more than
doubled production, reserves, undeveloped land and drilling inventory. The
assets acquired are long-life gas plays in the early stage of development,
98 percent weighted to natural gas, and characterized by high working
interest, low production expenses and operated production with a dominant land
position. The results for the last half of 2006 reflect the expanded asset and
unitholder base following the acquisition through substantially increased
production, funds flow from operations, development drilling activity and the
overall strength of the organization.
    Focus utilized $181.2 million of funds flow from operations plus
$36.6 million of debt to fund distributions of $124.2 million, $90.4 million
of capital expenditures, and $3.2 million of reclamation fund contributions
and expenditures in 2006. Distributions for the year include the payment of
$7.8 million on July 17, 2006 to the former shareholders of PEML in connection
with the acquisition on June 27, 2006. Capital expenditures include
$9.8 million spent by Focus at the Saskatchewan land sale in August to acquire
22 sections of undeveloped land in the centre of the Shackleton Milk River gas
play.
    Focus' production is 85 percent to 90 percent weighted to natural gas,
and fluctuations in natural gas prices have a significant impact on our funds
flow from operations and field netback. Natural gas prices were volatile in
2006 based on high natural gas storage levels and uncertainty with respect to
weather, hurricanes and the supply response to lower prices and higher capital
costs. The volatility of natural gas prices per mcf is demonstrated by a high
of $11.43 in the fourth quarter of 2005, $7.50 in the first quarter of 2006,
$6.04 for the second quarter of 2006, $5.66 in the third quarter of 2006 and a
rebound to $6.99 in the fourth quarter of 2006. Focus continues to actively
utilize a price protection program to reduce the volatility of commodity
prices and the corresponding funds flow from operations. For 2006, the longer
term physical delivery sales contracts and financial hedging contracts for
natural gas strongly supported our financial results with approximately
$38.6 million of additional natural gas revenue and a realized natural gas
price higher by $1.31 per mcf. For the fourth quarter of 2006, price
protection for natural gas added approximately $14.8 million of additional
revenue and increased the realized natural gas price by $1.42 per mcf.
    Funds flow from operations for the fourth quarter of 2006 was a record
$64.4 million and brought the total for 2006 to $181.2 million. This
represents $0.82 per unit for the fourth quarter of 2006 and $3.09 per unit
for 2006, compared with $0.86 in the fourth quarter of 2005 and $3.12 for
2005. The results for 2006 reflect the decline in the average natural gas
reference price being largely offset by the positive impact of the price
protection programs, a lower effective rate for royalties (due to financial
hedging settlements), and lower production expenses per BOE.
    Net income for 2006 was $72.9 million compared with $63.4 million in
2005. On a per unit basis, net income declined to $1.26 in 2006 compared with
$1.74 in 2005. With funds flow from operations per unit remaining relatively
constant for both years, this decline in net income per unit is primarily due
to the significantly higher charges recorded for depletion and depreciation in
the second half of 2006 resulting from the acquisition effective June 27,
2006, and a two percent decrease in funds flow from operations per BOE.
    Focus had active development programs in 2006 with reinvestment in our
core areas and a 100 percent drilling success rate. Focus invested
$90.4 million in capital programs for the year and drilled a record 190.3 net
wells, with 98 percent of net wells drilled targeting natural gas. There was a
significant increase in development activity in the second half of 2006
following the acquisition, with capital expenditures of $63.5 million and
174.9 net wells drilled. The 2006 Tommy Lakes winter drilling program resulted
in 11 new producing wells and two exploration wells. On the PEML assets
(primarily Shackleton), Focus invested $43.0 million and successfully drilled
155.9 net wells during the second half of 2006.

    Business Acquisition

    Effective June 27, 2006 Focus acquired PEML pursuant to a Plan of
Arrangement which was approved by both the unitholders of Focus and the
shareholders of PEML.

    Acquisition impacts:

    
        -  Production more than doubled, and the resulting production is
           weighted 88 percent towards natural gas.

        -  A much larger capital expenditure program going forward will be
           centered on development drilling opportunities at Shackleton in
           Saskatchewan and Tommy Lakes in British Columbia, conducted on a
           year-round basis.

        -  Total acquisition costs of approximately $1.1 billion, before
           asset retirement obligations and future tax, was financed through
           the issuance of equity of 30.8 million trust units and
           10.0 million exchangeable partnership units and the remaining
           $200 million was financed through debt and cash.

        -  The acquisition financing included $179 million of additional net
           debt. In connection with the acquisition, Focus increased its
           syndicated bank credit facility to $350 million, in addition to a
           $15 million demand operating line of credit.

        -  Reflecting the new production base and level of capital programs
           of the Trust, Focus strengthened the organization with the
           addition of personnel in all areas of the Trust. General and
           administrative expenses increased accordingly; however, general
           and administrative expenses on a per BOE basis are lower due to
           increases in production and overhead recoveries.
    

    Focus remains committed to long-term sustainability, value creation
through development drilling and maintaining a strong financial position.

    Seasonality of Operations

    Prior to the acquisition in June 2006, most of the natural gas properties
of Focus were in areas of British Columbia which were only accessible by road
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.
    With the acquisition in June 2006, only 30 percent of production is from
northeast British Columbia and seasonality will be less of a factor than it
has been historically. Winter access issues, especially for the Tommy Lakes
winter development program and some environmentally sensitive areas within
Shackleton, will continue to impact the operating results of Focus.

    Production

    2006 Q4:

    
        -  Production was essentially flat on a BOE basis during the fourth
           quarter to 21,594 BOE per day from 21,853 BOE per day in the
           third quarter. Production for the fourth quarter was weighted 88
           percent towards natural gas and three percent towards natural gas
           liquids.

        -  Oil and NGL production increased three percent to 2,671 BOE per
           day largely due to increases from three new wells in the Red
           Earth area which came on production in September. Natural gas
           production declined two percent from 115.6 mcf per day to
           113.5 mcf per day.

        -  The Saskatchewan properties contributed 74.6 mcf per day to
           natural gas production in the fourth quarter compared to 75.4 mcf
           per day in the third quarter. Production from Tommy Lakes of
           29.4 Mmcf per day in the fourth quarter is consistent with the
           pattern of fourth quarter production levels being the lowest of
           the year. Fourth quarter natural gas production increased at
           Sylvan Lake, with three new gas wells brought on stream in mid
           October, and Cabin where a well was brought back on production in
           late November.

    2006 compared with 2005:

        -  Production averaged 15,899 BOE per day in 2006 compared to
           9,963 BOE per day in 2005. The most significant factor impacting
           production was the PEML acquisition in late June 2006 which
           contributed 6,602 BOE per day to average 2006 production.

        -  Oil and NGL production decreased three percent to 2,475 BOE per
           day in 2006 from 2,542 BOE per day in 2005. Heavy oil acquired
           with the PEML acquisition contributed 158 BOE per day to the
           average. Overall crude oil production going forward will reflect
           the natural decline of the properties and limited capital
           investment in oil properties.

        -  Average 2006 natural gas production increased 81 percent to
           80.5 Mmcf per day from 44.5 Mmcf per day in 2005. Production from
           the PEML properties increased annual average production by
           38.7 Mmcf per day, based on average production of 75.0 Mmcf per
           day in the last half of 2006. Tommy Lakes natural gas production
           declined two percent on a year-over-year basis. Production at
           Medicine Hat increased 24 percent from 1.8 Mmcf per day to
           2.3 Mmcf per day. Natural gas production declines at Kotcho-Cabin
           were approximately 2.0 Mmcf per day.

    Pricing and Price Risk Management

    Natural Gas Pricing to June 30, 2006 (prior to the PEML 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 PEML 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 December 31, 2006:

                                    Three Months Ended           Years Ended
                                           December 31,          December 31,
    Realized Price Per Mcf             2006       2005       2006       2005
    -------------------------------------------------------------------------
    AECO daily average
     (CDN$/mcf)(1)                $    6.99  $   11.43  $    6.55  $    8.77
    Plus: heat content
           adjustment(1)(2)               -       1.29       0.17       0.83
    Less: differential to B.C.
           markets(1)(2)              (0.03)     (0.02)     (0.20)     (0.16)
    Less: transportation system
           charges(2)                 (0.33)     (0.62)     (0.41)     (0.61)
    Adjust: timing of actual
             gas sales(1)(2)          (0.24)     (0.48)     (0.04)     (0.23)
    -------------------------------------------------------------------------
    Price before price protection
     (physical & financial)            6.38      11.60       6.06       8.60
    Impact of longer term physical
     sales contracts(1)                0.26      (2.02)      0.37      (0.57)
    Financial hedging settlements      1.16      (0.34)      0.94      (0.11)
    -------------------------------------------------------------------------
    Focus realized price per mcf  $    7.80  $    9.24  $    7.37  $    7.92
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Focus natural gas sales
         price per mcf (before
         transportation system
         charges and financial
         hedging settlements)     $    6.97  $   10.20  $    6.84  $    8.64
    -------------------------------------------------------------------------
    (2) Differential of Focus
         sales price to AECO
         daily reference price
         after transportation and
         before price protection
         per mcf                  $   (0.61) $    0.17  $   (0.48) $   (0.17)
    -------------------------------------------------------------------------


    Natural Gas Pricing

        -  Natural gas reference prices recovered somewhat in the fourth
           quarter of 2006; however, the average natural gas reference price
           for 2006 was 25 percent below the average reference price for
           2005. The average AECO daily reference price per mcf for natural
           gas was $6.99 during the fourth quarter of 2006 compared with
           $5.66 for the third quarter of 2006, $6.04 for the second quarter
           of 2006 and $7.50 in the first quarter of 2006.

        -  Focus' realized natural gas price in the fourth quarter of 2006
           was 16 percent higher than the third quarter of 2006 due to a
           higher price protected (with physical and financial contracts) and
           through a 23 percent increase in the reference price. The realized
           price in the fourth quarter of 2006 was 16 percent lower than the
           fourth quarter of 2005 due to significant decrease in the
           reference price of natural gas.

        -  During the fourth quarter of 2006, the price protection program of
           Focus reduced some of the volatility in natural gas prices and
           increased the realized price received by $1.42 per mcf. During the
           quarter, 25 percent of natural gas was sold under forward physical
           sales contracts which resulted in natural gas sales being
           $2.7 million higher than if the natural gas had been sold based on
           the AECO daily reference price. A further 47 percent of natural
           gas production was hedged with financial instruments. The impact
           of the financial instrument settlements was positive $12.1 million
           for the fourth quarter of 2006.

        -  For 2006, price protection through physical delivery contracts and
           financial instruments increased revenue by approximately
           $38.6 million and increased the realized price for natural gas by
           $1.31 per mcf. This compares with a cost of $10.9 million, or
           $0.57 per mcf in 2005. At December 31, 2006, the mark-to-market
           value for natural gas of financial instruments was $25.8 million
           and $7.8 million for physical contracts.

        -  Accounting for financial contracts will change in 2007 to mark-to-
           market accounting from hedge accounting. This is further discussed
           in Note 14 of the notes to consolidated financial statements.

    Crude Oil

        -  The price realized by Focus for crude oil, after settlement of
           financial hedges, was $57.51 per barrel for the fourth quarter of
           2006 versus $59.20 for the comparable period in 2005, and
           $70.09 per barrel in the third quarter of 2006.

        -  The differential between the sales price of our crude oil compared
           with the Edmonton par reference price for light oil in the fourth
           quarter of 2006 was $6.29 per barrel. Heavy oil production,
           representing 16 percent of oil production for the quarter, had a
           differential of $25.53 per barrel compared with the light oil
           production which had a differential of $2.54 per barrel.
           Apportionment on the Rainbow pipeline resulted in additional
           trucking charges in the fourth quarter of 2006.

        -  Focus has utilized price protection for a portion of its crude oil
           production. For 2006, 700 barrels per day were hedged financially
           with a cost of $1.7 million, or $2.70 per barrel. This compares
           with a cost of $6.6 million in 2005 on the 1,100 barrels per day
           hedged, or $10.20 per barrel. For the fourth quarter of 2006,
           700 barrels per day were hedged, representing approximately
           36 percent of crude oil production, with a cost of $0.1 million or
           $0.76 per barrel. At December 31, 2006, the mark-to-market cost
           for crude oil financial instruments was $0.1 million.

    Price Protection

        -  Focus uses price protection through longer term physical delivery
           contracts and financial contracts to reduce the volatility in
           commodity prices and assist in maintaining sustainable
           distributions.

        -  Our current price protection program is outlined below. A full
           description of the outstanding financial instruments and the
           physical sales contracts and their estimated mark to market values
           as at December 31, 2006 is contained in Notes 14 and 15 of the
           notes to consolidated financial statements.

    -------------------------------------------------------------------------
    Price Protection at                          2007                  2008
     March 6, 2007               --------------------------------------------
     (volume and reference price)     Q1       Q2       Q3       Q4       Q1
    -------------------------------------------------------------------------
    Natural gas(1)  Mmcf/d          81.9     77.5     77.5     51.2     37.7
                    ---------------------------------------------------------
                    CDN$/mcf       $8.68    $8.01    $8.01   $8.36-   $8.76-
                                                              $8.51    $9.06
    Crude oil       bbls/d           400      800      800      400        -
                    ---------------------------------------------------------
                    CDN$/bbl     $70.00-  $70.47-  $70.47-  $70.00-
                                  $79.00   $79.00   $79.00   $79.00        -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) These amounts reflect our average natural gas heat content of 1.06 GJ
        per mcf.

    New CICA Handbook Standards sections, Financial Instruments - Recognition
and Measurement, Hedges, and Comprehensive Income are applicable beginning in
2007 (refer to Note 14 of the notes to consolidated financial statements).

    Production Revenue

        -  Production revenue for the fourth quarter of 2006 was
           $98.4 million compared to $90.4 million for the third quarter of
           2006. The nine percent increase is mostly due to the increase in
           realized natural gas prices which were partially offset by a
           reduction in crude oil and NGL realizations and lower natural gas
           production. Production revenue for the fourth quarter of 2006 was
           86 percent from natural gas compared to 88 percent in the third
           quarter of 2006 and 74 percent for the fourth quarter of 2005.

        -  Production revenue for 2006 increased 49 percent to $285.6 million
           from $191.7 million in 2005. The most significant contributor to
           the increase was the 81 percent increase in average natural gas
           production, mainly from the Saskatchewan properties acquired in
           mid 2006. Higher realizations for crude oil and NGL's were offset
           by the lower realizations for natural gas. Natural gas revenue
           made up 80 percent of production revenue in 2006 compared to 72
           percent in 2005.

    Production Expenses

    -------------------------------------------------------------------------
                                        2006    2005    2004    2003  2002(1)
    -------------------------------------------------------------------------
    Production expenses per BOE        $4.17   $4.11   $3.29   $3.39   $3.09
    -------------------------------------------------------------------------
    (1) The Trust was created in August 2002 and the results for 2002 include
        the 131-day period from August 23 to December 31.

        -  Production expenses for 2006 were $4.17 per BOE compared to
           $4.11 per BOE in 2005. Production expenses increased slightly as
           the addition of the lower production expense Saskatchewan
           properties acquired in late June offset general upward expense
           pressures due to high activity levels in the sector, competition
           for services and higher energy costs.

    -------------------------------------------------------------------------
                           2006                            2005
                  Q4      Q3      Q2      Q1      Q4      Q3      Q2      Q1
    -------------------------------------------------------------------------
    Production
     expenses
     per BOE   $4.04   $3.50   $4.62   $5.50   $4.61   $3.56   $4.10   $4.19
    -------------------------------------------------------------------------

        -  For the fourth quarter of 2006, production expenses increased 15
           percent from the third quarter 2006 to $4.04 per BOE. Production
           expenses in the fourth quarter were impacted by seasonal costs at
           properties which are only accessible in the winter, increased
           utility costs and facility turnarounds completed in the quarter.

    General and Administrative Expenses

                                Three Months Ended               Years Ended
                                       December 31,              December 31,
    -------------------------------------------------------------------------
    (thousands)                  2006         2005         2006         2005
    -------------------------------------------------------------------------
    Cash G&A expenses     $     4,126  $     1,941  $    11,103  $     6,899
    Overhead recoveries        (2,163)        (822)      (5,453)      (2,470)
    -------------------------------------------------------------------------
    Total cash G&A expenses     1,963        1,119        5,650        4,429
    Non-cash G&A expense(1)         -          348          804        1,455
    Trust Unit Rights
     Plan expense(2)              809          266        2,120          884
    -------------------------------------------------------------------------
    Net G& A reported     $     2,772  $     1,733  $     8,574  $     6,768
    -------------------------------------------------------------------------

    Cash based G&A
     per BOE              $      0.99  $      1.27  $      0.97  $      1.22
    Net reported G&A
     per BOE              $      1.40  $      1.97  $      1.48  $      1.86
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Gross general and administrative expenses for 2006 included
        $1.6 million related to the Executive Bonus Plan (2005 -
        $2.9 million). 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) Trust Unit Rights Plan compensation expense is calculated using the
        fair value method adopted in 2003 and represents a non-cash charge.
        Details of this compensation expense are contained in Note 11 of the
        notes to consolidated financial statements.
    

    Cash-based general and administrative expenses were $0.99 per BOE for the
fourth quarter of 2006 compared with $0.63 per BOE for the third quarter of
2006 and $1.27 per BOE in the fourth quarter of 2005. Fourth quarter 2006
expenses included annual cash bonus expenses and expenses associated with
compliance with the new regulations regarding internal controls over financial
reporting.
    With the acquisition of PEML in late June, Focus increased its
organizational strength with the addition of personnel in all areas of the
Trust as required by the expanded production base, capital programs and
corporate requirements. This growth increased general and administrative costs
associated with personnel, rent and corporate activities. Notwithstanding that
Focus has grown in size, general and administrative expenses per BOE have
declined due to increased production of the Trust after the acquisition and
additional overhead recoveries from the acquired operated properties.

    Elimination of the Executive Bonus Plan

    Late in the second quarter of 2006, the Board of Directors approved a new
compensation plan that would better suit the expanded employee base of the
Trust and be more comparable with the standard industry compensation framework
for a trust of this size. As part of the change to compensation arrangements,
the Executive Bonus Plan was eliminated. In eliminating the Executive Bonus
Plan, $3.0 million was to be paid to the participants in the Plan. Half was
paid on July 4, 2006 and the remainder will be paid on July 3, 2007. In
addition, participants received, in aggregate, an additional 495,600 trust
unit appreciation rights during the third quarter of 2006. The financial
statements for the second quarter of 2006 recognized the full $3.0 million
amount, of which $2,871,856 was allocated to general and administrative
expenses and $128,144 was allocated to production expenses.

    Interest and Financing Expenses

    Interest and financing expenses increased from $3.7 million in the third
quarter of 2006 to $4.1 million in the fourth quarter of 2006 due to an
increase in average debt outstanding.
    Interest and financing expenses for 2006 were $10.3 million, an increase
from $3.5 million in 2005. The increase is largely due to the additional debt
associated with the business acquisition of $179 million, which was incurred
at the end of June 2006. The increase is also due to a slight increase in
interest rates. Outstanding long-term debt at December 31, 2006 was
$297.0 million compared to $87.5 million at December 31, 2005.

    Depletion and Depreciation

    The depletion and depreciation rate, excluding the impact of exchangeable
share conversions, for the three months ended December 31, 2006, increased to
$22.95 per BOE ($24.61 per BOE, including the exchangeable share impact)
compared to $11.47 per BOE ($15.08 per BOE, including the exchangeable share
impact) in the fourth quarter of 2005.
    The depletion and depreciation rate incorporates the results of
independent reserve reports dated December 31, 2006 and actual capital
expenditures. The increase in the rate is largely due to the significant
business acquisition in June 2006 for which the Trust recorded a higher
proportionate cost per BOE of proved reserves compared to the historic Focus
properties.

    Asset Retirement Obligation

    The asset retirement obligation increased $21.0 million to $36.1 million
at December 31, 2006 from $15.1 million at December 31, 2005. The obligation
includes $14.6 million associated with the business acquisition in June 2006.
The remainder of the increase is due to drilling activity, new construction
activity and higher accretion expense. The asset retirement obligation
recorded represents the net present value of cash flows required to settle
asset retirement obligations, and a full description is contained in Note 5 of
the notes to consolidated financial statements.
    The higher asset retirement obligation has resulted in a higher accretion
expense beginning in the second half of 2006.

    Income and Other Taxes

    Income and other taxes include a future income tax recovery of
$30.2 million in 2006 compared to a recovery of $5.7 million in 2005. The
recovery of future income tax results from a reduction in corporate income tax
rates in 2006, distributions to unitholders which transfers taxable income
from the Trust to individual unitholders and from the depletion associated
with accounting for exchangeable shares.
    Large corporations tax, predominantly based on year-end debt and equity
levels, in 2006 was nil compared to $0.8 million in 2005 due to the
elimination of the large corporations tax effective January 1, 2006.
    Certain of the Trust's assets are held by entities which transfer taxable
income to unitholders. The excess of the carrying value of these assets over
the tax value is approximately $77.2 million. Total available tax pools of the
Trust and subsidiary entities is approximately $322 million at December 31,
2006 before adjusting for deferred income amounts ($184 million after
adjusting for deferred income amounts).
    On October 31, 2006, the Federal Government announced proposals
pertaining to the taxation of distributions from publicly traded Canadian
income trusts, royalty trusts and partnerships. The proposals include a
31.5 percent tax imposed on income before distributions at the trust level and
taxed to the taxable Canadian investor, effectively as a dividend. If enacted,
the proposals would apply to the Trust effective January 1, 2011. On
December 21, 2006, the Department of Finance issued draft legislation
consistent with the proposals described above.
    As at December 31, 2006, the legislative proposals are not substantively
enacted and thus there is no impact on the recognition of future income taxes
in 2006. If the legislation is enacted, the Trust's taxable status will change
resulting in recognition of future tax liabilities at substantively enacted
tax rates in respect of temporary differences described above, which were
$77.2 million at December 31, 2006. This temporary difference amount is
reduced each year by depletion and increased through the use of tax claims and
therefore the temporary difference amount in 2011 is not necessarily
$77.2 million. Also, as the Trust would become a taxable entity in 2011, under
the proposals future income tax recoveries would likely not be recognized for
income transfers from the Trust to unitholders for 2011 onward.
    The Trust is currently assessing various structural alternatives in light
of the Government's proposals. However, the legislation is not yet enacted and
the Trust cannot conclude on a form of structure nor the total implication to
the Trust. Despite the structural implication of the proposals, the core
business of the Trust remains the same.
    On December 15, 2006, the Government announced guidance regarding "normal
growth" for equity capital during the transitional period from October 31,
2006 to 2011. This amount will be measured with reference to the Trust's
market capitalization on October 31, 2006. 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 through 2010, for a total of 100 percent. In
addition, Trusts will be permitted to repay existing debt outstanding on
October 31, 2006 without impacting the normal growth limits.

    Capital Expenditures

    Capital expenditures for field operations were $27.0 million in the
fourth quarter of 2006. The majority of the capital was concentrated at
Shackleton, Tommy Lakes and Medicine Hat. At Shackleton the Trust finished
drilling its 159-well summer program, completed and tied in these wells, and
commissioned two new compressor stations. Additionally, due to favorable
weather conditions and rig availability we were able to get an early start on
our 2007 Shackleton winter program, drilling 18 wells prior to year end. At
Tommy Lakes we were also able to get an early start, and as a result we
drilled a total of eight wells prior to the end of the year, including two
successful 50 percent working interest wells on the Trutch exploratory Halfway
play to the west of our main Tommy Lakes field. Due to the early commencement
of these winter projects we spent approximately $5.0 million more in the
quarter than we had anticipated. This will be offset by lower expenditures on
these projects in the first quarter of 2007. At Medicine Hat, we completed our
17-well program and tied 15 of these wells into our existing infrastructure.
In total Focus drilled 56 wells during the quarter, including 31 wells
(26.1 net) at Shackleton, eight wells (7.0 net) at Tommy Lakes and 17 wells
(13.2 net) at Medicine Hat.
    For 2006, total capital expenditures for field operations were
$90.4 million, excluding the amount recorded for asset retirement obligations.
Our expectation for 2006 was that we would spend approximately $84.0 million,
and our budgeted 2006 projects came in essentially in line with this
expectation. The $6.4 million difference between expectation and actual is
largely due to the $5.0 million of 2007 spending accelerated into December
2006, as described above. The remaining difference is due to an increase in
inventory at year end due to the timing of bulk purchases of items such as
line pipe and coiled tubing.
    The majority of the 2006 capital expenditures were directed towards
development of our two core properties, with 35 percent of total capital spent
at Shackleton and 32 percent at Tommy Lakes. In addition, 13 percent of total
capital was spent on other gas properties including Pouce Coupe, Sylvan Lake
and Medicine Hat, and nine percent was spent on our Red Earth oil properties.
The remaining 11 percent, or $10.2 million, was spent to acquire undeveloped
land at Crown land sales, primarily at Shackleton. During 2006 Focus continued
to maximize the value of our existing asset base and acquired properties
through the drill bit.
    In June 2006 Focus invested approximately $1.1 billion, before asset
retirement obligations and future tax, to acquire PEML. On a proved plus
probable basis, acquired reserves were 45.5 MMBOE, consisting of 267 Bcf of
natural gas and 0.9 Mmbls of heavy oil. More detail with respect to the PEML
acquisition is contained in the Business Acquisition section of this
discussion.
    Focus will continue to actively develop and expand its core properties in
2007 with a capital budget for field operations of approximately $95.0 million
to $115.0 million. Significant development activities will continue at
Shackleton, Tommy Lakes, Loon Lake, and Medicine Hat; however, the ultimate
overall size of our development program will be guided by our sustainable
business strategy, realized commodity prices, and service costs. There will be
a continued emphasis on natural gas development and on those projects that we
operate and control.

    LIQUIDITY AND CAPITAL RE

SOURCES As at December 31, 2006 Focus had a working capital deficit of $11.1 million compared with a working capital deficit of $5.0 million at December 31, 2005. The increase in the working capital deficit of $6.1 million from December 31, 2005 is mainly due to an increase in activity level resulting from the acquisition of PEML. The increase in receivable accounts due to the increase in production levels is more than offset by the increase in payables from drilling programs at Shackleton and an increase in distributions payable resulting from the issuance of trust units and exchangeable partnership units in connection with the acquisition. The working capital deficit at December 31, 2006 has decreased from $19.8 million at September 30, 2006, largely due to an increase in accrued natural gas revenue commensurate with the increase in natural gas prices. The September realized natural gas price was $7.32 per mcf compared to a December realized natural gas price of $7.90 per mcf. In addition, the estimated net working capital deficiency assumed with the acquisition of PEML decreased by $5.1 million. 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 and accrued revenue and royalties for the current month. Long-term debt at December 31, 2006 was $297.0 million compared with $87.5 million at December 31, 2005 and $293.5 million at September 30, 2006. The increase in long-term debt of $209.5 million is largely due to $142.5 million incurred with the acquisition in June 2006 and debt incurred to settle net obligations related to the acquisition. The remainder of the increase in long-term debt is a result of payments for distributions, capital expenditures and reclamation activities being greater than funds flow received for the period. Focus had a $350 million revolving syndicated credit facility among four financial institutions and a $15 million operating facility at December 31, 2006. The credit facility revolves until June 25, 2007, 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. Management intends to request the extension. The credit facilities are secured by a floating charge debenture covering all of the assets of the Trust and a general security agreement. Long-term debt plus the working capital deficiency increased $215.6 million during 2006 from $92.5 million at December 31, 2005 to $308.1 million at December 31, 2006. This increase of $215.6 million during the year primarily resulted from the following factors. - Funds flow from operations of $181.2 million plus $36.6 million of debt and working capital were used to fund $124.2 million in distributions declared to unitholders, $90.4 million invested in capital expenditures for field operations, and $3.2 million of contributions to the reclamation fund and reclamation costs. Capital of $90.4 million includes $9.8 million spent at a Saskatchewan land sale in August 2006. - With respect to the PEML acquisition, Focus paid $199.8 million and obtained net working capital of $20.8 million for a net change in debt and working capital deficiency of $179 million. - Proceeds were $1.8 million from the issuance of equity pursuant to the exercise of trust unit appreciation rights and from the Distribution Reinvestment and Optional Trust Unit Purchase Plan ("DRIP Plan"). - Working capital includes $1.8 million charge for non-cash mark-to- market losses. Central to Focus' business strategy is the concept of sustainability where the sum of 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 and by issuing units from treasury. On October 11, 2006 Focus announced the introduction of the DRIP Plan which provides eligible unitholders of Focus trust units the advantage of accumulating additional trust units by reinvesting their cash distributions paid by Focus and 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 the financial flexibility of Focus. Focus wants to maintain financial flexibility at a time of shifting commodity prices. Consistent with the experience of other trusts for this basic type of plan, we expect the DRIP Plan will generate between $5 million and $10 million through the issuance of equity on an annual basis. From inception of the plan to December 31, 2006, the plan generated $1.0 million and 58,793 trust units were issued from treasury. Focus will generally use funds generated by this plan to reduce debt and invest in additional capital projects (including land purchases and expanded development operations). Capitalization Table December 31, December 31, (thousands except per-unit amounts) 2006 2005 ------------------------------------------------------------------------- Long-term debt $ 297,000 $ 87,500 Plus: working capital deficiency 11,122 5,018 ------------------------------------------------------------------------- Total debt $ 308,122 $ 92,518 Total units outstanding and issuable for exchangeable shares and exchangeable partnership units 78,504 37,456 Market price $ 18.18 $ 25.72 Market capitalization $ 1,427,203 $ 963,368 Total capitalization $ 1,736,507 $ 1,055,886 ------------------------------------------------------------------------- Total debt as a percentage of total capitalization 17.8% 8.8% Funds flow from operations $ 181,223 $ 116,368 Total debt to funds flow(1) 1.2 0.8 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) The calculation of debt to annualized funds flow at December 31, 2006 is based on the funds flow 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. 2006 CASH DISTRIBUTIONS Ex-Distribution Distribution Distribution Date Record Date Payment Date Per Unit ------------------------------------------------------------------------- January 27, 2006 January 31, 2006 February 15, 2006 $0.19 February 24, 2006 February 28, 2006 March 15, 2006 $0.19 March 29, 2006 March 31, 2006 April 17, 2006 $0.19 April 26, 2006 April 30, 2006 May 15, 2006 $0.19 May 29, 2006 May 31, 2006 June 15, 2006 $0.19 June 28, 2006 June 30, 2006 July 17, 2006 $0.19 July 27, 2006 July 31, 2006 August 15, 2006 $0.16 August 29, 2006 August 31, 2006 September 15, 2006 $0.16 September 27, 2006 September 30, 2006 October 16, 2006 $0.16 October 27, 2006 October 31, 2006 November 15, 2006 $0.16 November 28, 2006 November 30, 2006 December 15, 2006 $0.16 December 27, 2006 December 31, 2006 January 15, 2007 $0.16 ------------------------------------------------------------------------- Total $2.10 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Focus declared distributions of $2.10 per unit in respect of 2006 production. On January 11, 2007 the Trust announced that distributions in respect of January to March production would be at a rate of $0.14 per month. The distribution rate reflects Focus' commitment to a business strategy of sustainability where the sum of 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. The cash distributions are taxed as ordinary income to the investor. Cash distributions were not paid on the exchangeable shares and the cash flow related to the exchangeable shares was retained by the Trust for reduction of debt or for additional capital expenditures. The exchangeable shares of FET Resources Ltd. were convertible into trust units of Focus based on the exchange ratio, which was adjusted monthly to reflect the distribution paid on the trust units. All outstanding exchangeable shares were redeemed for trust units on January 16, 2007. Taxation of Cash Distributions Focus Energy Trust, for purposes of the Canadian Income Tax Act, is treated as a mutual fund trust and each year the Trust files an income tax return with the taxable income allocated to the unitholders. Distributions paid to the unitholders may be both a return on capital (income) and a return of capital. The allocation between these two streams is dependent upon the income tax deductions that the Trust is able to claim against the income it earns. The return of capital portion reduces the adjusted cost base of the trust units held. The Trust has net income for each year that is required to be calculated on an accrual basis of accounting. Net income includes all interest income from FET and other income that accrues to the Trust to the end of the year. Under the Trust Indenture, net income of the Trust for each year will be paid or payable by way of cash distributions to the unitholders. 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 and a deduction relating to income tax pools residing at the Trust level. 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 is allocated to unitholders. Any taxable income relating to a payable amount is allocated to unitholders of record at December 31, 2006, and each unitholder receives a pro rata share of that payable amount on January 15, 2007. For 2006, cash distributions will be 100 percent taxable income (return on capital). For a more detailed breakdown, as well as tax information for U.S. investors, please visit our website at www.focusenergytrust.com. 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 18 of the notes to consolidated financial statements for further details. Off Balance Sheet Arrangements The Trust has certain lease agreements that are entered into in the normal course of operations. All leases are treated as operating leases whereby the lease payments are included in operating expenses or general and administrative expenses depending on the nature of the lease. No asset or liability value has been assigned to these leases in the balance sheet as at December 31, 2006. Focus has not entered into any guarantee or off balance sheet arrangements other than in the normal course of operations. 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 the Trust expects 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. The Trust has 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. The management team's mandate includes ongoing development of procedures, standards and systems to allow the Trust to make the best estimates possible. Disclosure Controls and Internal 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. As at the end of the period covered by this report, the design and operating effectiveness of the Trust's disclosure controls were evaluated by the Chief Executive Officer and the Chief Financial Officer. According to this evaluation, the Trust's disclosure controls and procedures are effective to ensure that any material, or potentially material, information is made known to the Committee and is properly included in this report. This evaluation took into consideration Focus' Disclosure, Confidentiality & Trading Policy and the functioning of its senior management, Board of Directors and board committees. 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 and has concluded, as of December 31, 2006, that the design of internal controls over financial reporting was effective. There were no changes in internal control over financial reporting that have materially affected or are reasonably likely to materially affect the Trust's internal control over financial reporting. Subsequent to the PEML acquisition, which significantly increased activity and staff levels, and during the review of the design of internal controls over financial reporting, management made some changes to the Trust's internal controls. These changes related mainly to changes in formalization and documentation of reviews, as well as further segregation of duties. 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 widely during recent years and are determined by demand and supply factors, including weather and general economic conditions as well as conditions in other oil and natural gas producing regions. The following chart summarizes Focus' 2007 outlook. No acquisitions are assumed for the purposes of these forecasts. In 2007, Focus will continue its active development drilling programs on its major natural gas properties. It is anticipated that these development activities 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 (full year average) ------------------------------------------------------------------------- Production 21,500 - 23,500 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 Payout ratio 55% - 65% Approximate taxable portion of distributions 100% Funds from operations/net debt 1.1x - 1.3x ------------------------------------------------------------------------- The table below shows the potential impact on the Trust's funds flow (before price protection) resulting from changes to the business environment or operations. ------------------------------------------------------------------------- Change to Funds Flow ---------------------- Change $000's $/Unit ------------------------------------------------------------------------- Business Environment Price per barrel of crude oil (US$ WTI) $1.00 825 0.01 Price per mcf of natural gas (CDN$ AECO) $0.25 8,500 0.11 US/CDN exchange rate $0.01 3,400 0.04 Interest rate on debt 1% 3,300 0.04 ------------------------------------------------------------------------- Operations Oil production - bbls/d 100 1,825 0.02 Gas production - mcf/d 1,000 1,850 0.02 Operating expenses ($ per BOE) $0.25 2,050 0.03 Cash G&A expenses ($ per BOE) $0.25 2,050 0.03 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Focus is 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 in the business; - Pursue quality acquisitions that are strategic and accretive; - Protect margins and improve profitability; - Surface 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. - Prior to the PEML acquisition in late June 2006, many of Focus' natural gas areas were only accessible by road in the winter. This includes the Tommy Lakes area, which is very significant from a production and development program perspective. Please refer to the "Seasonality of Operations" section for additional information. - Focus completed a major acquisition in June 2006, for approximately $1.1 billion where production more than doubled, weighted 88 percent towards natural gas. Properties acquired allow for year round access. 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 $179 million. See "Business Acquisition" section for additional information. Summary of Quarterly Results ------------------------------------------------------------------------- 2006 ($ thousands except as indicated) Q4 Q3 Q2 Q1 ------------------------------------------------------------------------- FINANCIAL Oil and gas revenues, before royalties 98,434 90,395 48,663 48,146 Funds flow from operations 64,412 60,134 27,988 28,688 Per unit - basic $0.81 $0.77 $0.70 $0.77 Cash distributions per trust unit $0.48 $0.48 $0.57 $0.57 Payout ratio - per-unit basis 59% 63% 82% 74% Net income(1) 21,646 12,671 21,873 16,778 Per unit - basic(1) $0.28 $0.19 $0.57 $0.46 Capital expenditures 26,986 36,457 2,674 24,289 Acquisition expenditures, net 45 - 1,091,294 - Long-term debt plus working capital 308,122 313,013 297,451 109,094 Total Units - outstanding (000's) 78,504 78,425 78,359 37,521 ------------------------------------------------------------------------- OPERATIONS Average daily production Crude oil (bbls/d) 1,965 1,844 1,563 1,610 NGLs (bbls/d) 706 746 682 784 Natural gas (mcf/d) 113,539 115,612 46,753 45,137 BOE (at 6:1) 21,594 21,853 10,038 9,917 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- 2005 ($ thousands except as indicated) Q4 Q3 Q2 Q1 ------------------------------------------------------------------------- FINANCIAL Oil and gas revenues, before royalties 52,315 48,790 46,583 43,981 Funds flow from operations 32,350 29,773 27,436 26,809 Per unit - basic $0.86 $0.80 $0.73 $0.72 Cash distributions per trust unit $0.54 $0.52 $0.48 $0.48 Payout ratio - per-unit basis 63% 65% 66% 67% Net income(1) 17,858 17,573 14,682 13,351 Per unit - basic(1) $0.49 $0.48 $0.40 $0.37 Capital expenditures 10,865 5,658 3,962 22,475 Acquisition expenditures, net (33) 10,394 - 77 Long-term debt plus working capital 92,518 94,252 88,965 94,548 Total Units - outstanding (000's) 37,456 37,418 37,339 37,290 ------------------------------------------------------------------------- OPERATIONS Average daily production Crude oil (bbls/d) 1,714 1,718 1,779 1,850 NGLs (bbls/d) 762 833 770 743 Natural gas (mcf/d) 42,629 44,910 46,997 43,575 BOE (at 6:1) 9,582 10,036 10,382 9,856 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) 2005 Q1 had been restated for the change in accounting policy, EIC-151 "Exchangeable Shares Issued by Subsidiaries of Income Trusts". APPENDIX A - CONSOLIDATED FINANCIAL STATEMENTS Consolidated Balance Sheets December 31, December 31, (thousands) 2006 2005 ------------------------------------------------------------------------- ASSETS Current assets Cash and cash equivalents $ - $ 4,696 Accounts receivable 51,392 21,065 Prepaid expenses and deposits 5,467 1,952 Commodity contracts (note 14) 2,959 - ------------------------------------------------------------------------- 59,818 27,713 Petroleum and natural gas properties and equipment (notes 3 & 4) 1,301,056 430,865 Goodwill (note 3) 453,241 5,100 Reclamation fund (note 6) 5,649 2,711 ------------------------------------------------------------------------- $ 1,819,764 $ 466,389 ------------------------------------------------------------------------- ------------------------------------------------------------------------- LIABILITIES Current Accounts payable and accrued liabilities $ 50,426 $ 26,127 Cash distributions payable 12,443 6,604 Current bank debt 4,948 - Commodity contracts (note 14) 3,123 - ------------------------------------------------------------------------- 70,940 32,731 Long-term debt (note 7) 297,000 87,500 Asset retirement obligation (note 5) 36,131 15,090 Future income taxes (note 17) 318,800 81,634 ------------------------------------------------------------------------- 722,871 216,955 ------------------------------------------------------------------------- NON-CONTROLLING INTEREST Exchangeable shares (note 8) 4,550 4,131 UNITHOLDERS' EQUITY Unitholders' capital (note 9) 922,426 244,426 Exchangeable partnership units (note 10) 218,500 - Contributed surplus (note 11) 2,945 1,135 Accumulated income (note 13) (51,528) (258) ------------------------------------------------------------------------- 1,092,343 245,303 ------------------------------------------------------------------------- Commitments and contingencies (note 18) ------------------------------------------------------------------------- Subsequent event (note 19) ------------------------------------------------------------------------- $ 1,819,764 $ 466,389 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See Notes to Consolidated Financial Statements Approval on behalf of the Board: (signed) (signed) STUART G. CLARK JAMES H. MCKELVIE Director Director Consolidated Statements of Income and Accumulated Income Three Months Ended Years Ended, (thousands except December 31, December 31, per-unit amounts) 2006 2005 2006 2005 ------------------------------------------------------------------------- (unaudited) Revenue Production revenue $ 98,434 $ 52,315 $ 285,639 $ 191,669 Royalties (17,881) (11,945) (54,563) (44,067) Alberta Royalty Tax Credit 128 126 470 490 Facility income 748 384 3,115 1,950 Interest income 16 11 35 40 ------------------------------------------------------------------------- 81,445 40,891 234,696 150,082 ------------------------------------------------------------------------- Expenses Transportation system charges 3,449 2,415 12,117 9,931 Production 8,021 4,068 24,192 14,948 General and administrative 2,772 1,733 8,574 6,768 Elimination of the executive bonus plan (note 12) - - 2,872 - Interest and financing 4,142 945 10,265 3,531 Depletion and depreciation (note 4) 48,877 13,291 130,379 53,916 Accretion on asset retirement obligation (note 5) 1,137 271 2,445 889 ------------------------------------------------------------------------- 68,398 22,723 190,844 89,983 ------------------------------------------------------------------------- Income before income and other taxes 13,047 18,168 43,852 60,099 Income and other taxes (note 17) Future income tax reduction (8,804) (50) (30,219) (5,678) Current and large corporations tax - (6) 220 876 ------------------------------------------------------------------------- (8,804) (56) (29,999) (4,802) ------------------------------------------------------------------------- Non-controlling interest - exchangeable shares 205 366 884 1,437 ------------------------------------------------------------------------- Net income for the period 21,646 17,858 72,967 63,464 Accumulated income (deficit), beginning of period (35,865) 1,683 (258) 9,955 ------------------------------------------------------------------------- Cash distributions (37,309) (19,799) (124,237) (73,677) ------------------------------------------------------------------------- Accumulated income (deficit), end of period (51,528) (258) (51,528) (258) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net income per unit (note 16) Basic $ 0.28 $ 0.49 $ 1.26 $ 1.74 Diluted $ 0.28 $ 0.48 $ 1.25 $ 1.71 See Notes to Consolidated Financial Statements Consolidated Statements of Cash Flows Three Months Ended Years Ended, December 31, December 31, (thousands) 2006 2005 2006 2005 ------------------------------------------------------------------------- (unaudited) Operating activities Net income for the period $ 21,646 $ 17,858 $ 72,967 $ 63,464 Add non-cash items: Non-controlling interest - exchangeable shares 205 366 884 1,437 Non-cash general and administrative expenses (notes 11 & 12) 809 614 2,924 2,340 Depletion and depreciation 48,877 13,291 130,379 53,916 Accretion on asset retirement obligation 1,137 271 2,445 889 Non-cash amortization of hedging contracts 542 - 1,843 - Future income tax recovery (8,804) (50) (30,219) (5,678) Reclamation costs 8 (34) (277) (632) Net change in non-cash working capital items (4,412) 4,502 (30,623) (992) ------------------------------------------------------------------------- 60,008 36,818 150,323 114,744 ------------------------------------------------------------------------- Financing activities Proceeds from issue of trust units (net of costs) 1,028 - 889 - Proceeds from exercise of unit appreciation rights 69 90 806 813 Increase (decrease) in long-term debt 3,800 (6,000) 209,500 13,000 Cash distributions paid (37,298) (19,790) (118,399) (72,829) ------------------------------------------------------------------------- (32,401) (25,700) 92,796 (59,016) ------------------------------------------------------------------------- Investing activities Capital asset additions (26,986) (10,865) (90,406) (43,035) Acquisition expenditures (note 3) (45) 33 (143,998) (10,363) Reclamation fund contributions, net of costs (834) (55) (2,938) (788) Net change in non-cash working capital items 258 3,065 (10,473) 3,110 ------------------------------------------------------------------------- (27,607) (7,822) (247,815) (51,076) ------------------------------------------------------------------------- Increase (decrease) in cash and cash equivalents during the period - 3,296 (4,696) 4,652 Cash and cash equivalents, beginning - 1,400 4,696 44 ------------------------------------------------------------------------- Cash and cash equivalents, ending $ - $ 4,696 $ - $ 4,696 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See Notes to Consolidated Financial Statements Notes to Consolidated Financial Statements ------------------------------------------------------------------------- December 31, 2006 and 2005 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 ("GAAP"). 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 and within the framework of the accounting policies summarized below. 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. a) Principles of Consolidation The consolidated financial statements of the Trust include the accounts of Focus Energy Trust, its subsidiaries FET Resources Ltd., FET Gas Production Ltd., Focus B.C. Trust and FET Energy Ltd., and its share of three partnerships. All inter-entity transactions and balances have been eliminated. b) Petroleum and Natural Gas Properties and Equipment The Trust follows the full cost method of accounting for petroleum and natural gas properties, whereby all costs of acquiring petroleum and natural gas properties and related development costs, whether productive or unproductive, are capitalized and accumulated in one Canadian cost centre, including asset retirement costs. Such costs include acquisition, drilling, geological, geophysical, and equipment costs and overhead expenses related to the properties and development activities. Costs of acquiring and evaluating unproved properties are excluded from depletion calculations until it is determined in the period that proved reserves are attributable to the properties or impairment has occurred. Maintenance and repairs are charged against income, and renewals and enhancements which extend the economic life of the properties and equipment are capitalized. Gains or losses are not recognized upon disposition of petroleum and natural gas properties unless crediting the proceeds against accumulated costs would result in a change in the rate of depletion by 20 percent or more. Depletion of petroleum and natural gas properties and depreciation of equipment are provided for using the unit-of-production method based on estimated proved petroleum and natural gas reserves, before royalties, as determined by independent engineers calculated in accordance with National Instrument 51-101. Production and reserves of natural gas are converted to equivalent barrels of crude oil based on the energy equivalent conversion ratio of six thousand cubic feet of natural gas to one barrel of oil. The depletion and depreciation cost base includes total capitalized costs, less prior depletion and depreciation charges, less costs of unproved properties, less the estimated future net realizable value of production equipment and facilities, plus provision for future development costs and future asset retirement costs of proved undeveloped reserves. c) Cost Impairment Test The Trust places a limit on the aggregate carrying value of petroleum and natural gas properties and equipment, which may be amortized against revenues of future periods (the "cost impairment test"). The cost impairment test requires an evaluation of petroleum and natural gas assets in each reporting period to determine that the carrying amount in a cost centre is recoverable and does not exceed the fair value of the properties in the cost centre. Cost impairment is recognized if the carrying amount of the petroleum and natural gas properties exceeds the sum of the undiscounted cash flows expected to result from the Trust's proved reserves. Cash flows are calculated based on third party quoted forward prices, adjusted for the Trust's contract prices and quality differentials. Upon recognition of impairment, the Trust would then measure the amount of impairment by comparing the carrying amounts of the petroleum and natural gas properties to an amount equal to the estimated net present value of future cash flows from proved plus risked probable reserves. The Trust's risk-free interest rate is used to arrive at the net present value of the future cash flows. Any excess carrying amount above the net present value of the Trust's future cash flows would be recognized as a permanent impairment. The cost of unproved properties is excluded from the cost impairment test calculation and is subject to a separate impairment test. d) Asset Retirement Obligation The Trust uses the asset retirement obligation method of recording the future cost associated with removal, site restoration and asset retirement costs. The fair value of the liability for the Trust's asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using the credit adjusted risk-free interest rate and the corresponding amount recognized by increasing the carrying amount of property, plant and equipment. The asset recorded is depleted on a unit-of-production basis over the life of the reserves. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is charged to earnings in the period. Revisions to the estimated timing of cash flows or to the original estimated undiscounted cost could also result in an increase or decrease to the obligation. Actual costs incurred upon settlement of the retirement obligation are charged against the obligation to the extent of the liability recorded. e) Goodwill Goodwill is the residual amount that results when the purchase price of an acquired business exceeds the fair value for accounting purposes of the net identifiable assets and liabilities of the acquired business. Net identifiable liabilities of the acquired business include an estimate of future income taxes. The goodwill balance is assessed for impairment annually at year end or more frequently if events change and circumstances indicate that the asset might be impaired. The test for impairment is the comparison of the carrying amount to the fair value of the reporting entity. If the fair value of the consolidated Trust is less than the book value, impairment is measured by allocating the fair value of the consolidated Trust to the identifiable assets and liabilities at their fair values. The excess of this allocation is the fair value of goodwill. Any excess of the book value of goodwill over this implied value is the impairment amount. Impairment is charged to income in the period in which it occurs. Goodwill is stated at cost less impairment and is not amortized. An impairment test of goodwill was completed at December 31, 2006 resulting in no impairment amount. f) Financial Instruments The Trust uses financial instruments to reduce its exposure to fluctuations in commodity prices and foreign exchange rates. The Trust's policy is not to use financial instruments for speculative or trading purposes. Gains and losses on contracts which constitute effective hedges are recognized in production income at the time of sale of the related production. Financial instruments which do not qualify as hedges are recorded on a mark-to-market basis at the balance sheet date with the resulting gains or losses being taken into income in the period. g) Income Taxes Income taxes are calculated using the liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the amounts reported in the consolidated financial statements of the Trust and their respective tax base, using substantively enacted income tax rates. The effect of a change in income tax rates on future tax liabilities and assets is recognized in income in the period in which the change occurs. Temporary differences arising on acquisitions result in future income tax assets and liabilities. The Trust is a taxable entity under the Income Tax Act (Canada) and is taxable only on income that is not distributed or distributable to the unitholders. As the Trust allocates all of its taxable income to the unitholders in accordance with the Trust Indenture, and meets the requirements of the Income Tax Act (Canada) applicable to the Trust, no provision for income tax expense or liability has been made in the Trust. See Note 17 for further discussion. In the Trust structure, payments are made between the Company and the Trust which result in the transferring of taxable income from the Company to individual unitholders. These payments may reduce future income tax liabilities previously recorded by the Company which would be recognized as a recovery of income tax in the period incurred. h) Non-Controlling Interest The exchangeable shares issued by a subsidiary, FET Resources Ltd., are reflected as non-controlling interest on the consolidated balance sheet and in turn, net income is reduced by the amount of net income attributed to the non-controlling interest. See Note 8 for further information. The non-controlling interest on the consolidated balance sheet consists of the book value of exchangeable shares at the time of the Plan of Arrangement with Storm Energy Inc. in August 2002, plus net income attributable to the exchangeable shareholders, less exchangeable shares converted. The net income attributable to the non-controlling interest on the consolidated statement of income and accumulated income represents the cumulative share of net income attributable to the non-controlling interest based on the trust units issuable for exchangeable shares in proportion to Total Trust Units issued and issuable each period end. i) Unit-Based Compensation Plan The Trust has a unit-based compensation plan (the "Plan") for employees, directors and consultants of the Trust and its subsidiaries which are described in Note 11. Compensation expense associated with rights granted under the Plan is deferred and recognized in earnings over the vesting period of the Plan with a corresponding increase or decrease in contributed surplus. Compensation expense is based on the fair value of the unit-based compensation at the date of grant using a modified Black Scholes option pricing model. The fair value method has been adopted prospectively with rights granted in 2003. Consideration paid upon the exercise of the rights together with the amount previously recognized in contributed surplus is recorded as an increase in unitholders' capital. The Trust has not incorporated an estimated forfeiture rate for rights that will not vest, rather, the Trust accounts for actual forfeitures as they occur. j) Per-Unit Amounts Net income per unit is calculated using the weighted average number of trust units and exchangeable partnership units outstanding during the year. Diluted net income per unit includes additional trust units for the dilutive impact of the Rights Plan and exchangeable shares converted at the average exchange rate. The treasury stock method is used to determine the dilutive effect of unit-based compensation. The treasury stock method assumes that the proceeds received from the exercise of in-the-money trust unit rights are used to repurchase units at the average market rate during the period. The weighted average number of units outstanding is then adjusted by the net change. Net income is also increased for the net income attributable to the exchangeable shareholders in calculating dilutive per-unit amounts. k) Revenue Recognition Revenue associated with sales of crude oil, natural gas, and natural gas liquids is recognized when title passes to the purchaser, normally at the pipeline delivery point for natural gas and at the wellhead for crude oil. l) Joint Operations Certain of the Trust's exploration and production activities are conducted jointly with others. The accounts of the Trust reflect its proportionate interest in such activities. m) Cash and Cash Equivalents The Trust considers all highly liquid investments with a maturity of three months or less at the time of purchase to be cash equivalents. These cash equivalents consist primarily of funds on deposit for various terms. Cash and cash equivalents are stated at cost which approximates fair value. n) Foreign Currency Translation Monetary assets and liabilities denominated in a foreign currency are translated at the rate of exchange in effect at the balance sheet date. Revenues and expenses are translated at the monthly average rates of exchange. Translation gains and losses are included in income in the period in which they arise. o) Transportation System Charges The Trust records revenue gross of transportation system charges and a transportation system charge on the income statement. p) Comparative Figures Certain of the comparative figures have been reclassified to conform to the current year's presentation. 3. BUSINESS ACQUISITION Effective June 27, 2006 Focus acquired PEML pursuant to a Plan of Arrangement with PEML. On June 26, 2006, the unitholders of the Trust and the shareholders of PEML voted to approve resolutions to effect the Plan of Arrangement by which security holders of PEML received a total of 5.17 Focus Energy Trust units and/or Focus Limited Partnership exchangeable units and $25.12 cash for each PEML common share and the Trust received the assets and assumed the liabilities of PEML for total consideration of $1,091.3 million. Of this amount, $1,070.5 million was for the acquisition of oil and gas assets, and the remaining $20.8 million was for the acquisition of working capital. This amount consisted of the issuance of 30,802,817 Focus Energy Trust units, 9,999,992 Focus Limited Partnership exchangeable units and $199.8 million in cash and transaction costs. Both the Trust and Partnership units had a fair value of $21.85 per unit. The Board of Directors approved the Information Circular dated May 25, 2006 with respect to the Plan of Arrangement on May 24, 2006. The Trust's aggregate consideration for the acquisition of PEML consists of the following: Consideration for the acquisition: ($ thousands) Trust units issued 673,041 Exchangeable partnership units issued 218,500 Cash 198,253 Transaction costs 1,500 ----------- 1,091,294 ----------- This transaction has been accounted for using the purchase method whereby the assets acquired and the liabilities assumed are recorded at their fair values with the excess consideration over the fair value of the identifiable net assets allocated to goodwill. The following summarizes the allocation of the aggregate consideration of the PEML acquisition. Allocation of purchase price: ($ thousands) Cash acquired 55,800 Net working capital (36,717) Petroleum and natural gas properties and equipment 903,645 Fair value of commodity contracts 1,679 Goodwill 448,141 Asset retirement obligation (14,570) Future income taxes (266,684) ----------- 1,091,294 ----------- Effective June 27, 2006, the results from operations from the assets purchased from PEML have been included in the consolidated financial statements of the Trust. 4. PETROLEUM AND NATURAL GAS PROPERTIES AND EQUIPMENT (thousands) 2006 2005 --------------------------------------------------------------------- Petroleum and natural gas properties and equipment, at cost $ 1,619,627 $ 655,693 Accumulated depletion and depreciation (318,571) (224,828) --------------------------------------------------------------------- Petroleum and natural gas properties and equipment, at cost, net $ 1,301,056 $ 430,865 --------------------------------------------------------------------- --------------------------------------------------------------------- The calculation of depletion and depreciation in 2006 included an estimate of $258.6 million (2005 - $61.6 million) for future development costs and $27.3 million (2005 - $3.4 million) for future asset retirement costs associated with proved undeveloped reserves. Unproved property costs of $26.7 million (2005 - $4.7 million) and estimated net realizable value of production equipment and facilities of $45.4 million (2005 - $25.0 million) were excluded from the depletion calculation. The Trust performed a cost impairment test at December 31, 2006 to assess the recoverable amount of the net carrying value of petroleum and natural gas properties and equipment. Future prices for crude oil and natural gas were obtained for the period 2007 to 2011 inclusive from the Trust's year-end independent reserve evaluations and then escalated based on escalation factors in the same evaluations. Based on these assumptions, the recoverable value was in excess of the carrying value of the Trust's net carrying value of the petroleum and natural gas properties and equipment. The future prices used for the cost impairment test for December 31, 2006 are as follows: Consultant's Price Forecasts 2007 2008 2009 2010 2011 --------------------------------------------------------------------- Crude Oil - WTI ($U.S/bbl) $62.00 $60.00 $58.00 $57.00 $57.00 Natural Gas - AECO ($CDN/Mmbtu) $ 7.20 $ 7.45 $ 7.75 $ 7.80 $ 7.85 5. 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 $84.6 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) 2006 2005 --------------------------------------------------------------------- Balance, as at January 1 $ 15,090 $ 11,461 Accretion expense 2,445 889 Liabilities incurred Acquisitions 14,570 366 Development activity and change in estimates 4,303 3,006 Settlement of liabilities (277) (632) --------------------------------------------------------------------- Balance, as at December 31 $ 36,131 $ 15,090 --------------------------------------------------------------------- --------------------------------------------------------------------- 6. RECLAMATION FUND (thousands) 2006 2005 --------------------------------------------------------------------- Balance as at January 1 $ 2,711 $ 1,923 Contributions 3,215 1,420 Reclamation costs (277) (632) --------------------------------------------------------------------- Balance as at December 31 $ 5,649 $ 2,711 --------------------------------------------------------------------- --------------------------------------------------------------------- At the inception of the Trust in 2002, a reclamation fund was established to fund the payment of environmental and site reclamation costs. Annual contributions will be made to the reclamation fund such that the currently estimated future environmental and site reclamation costs will be funded after 20 years. The Company may use the reclamation fund for purposes of funding its environmental and site reclamation costs. The reclamation fund is held on deposit at a Canadian financial institution. 7. LONG-TERM DEBT 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 December 31, 2006, 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 December 31, 2006 is approximately 5.2 percent. The credit facility will revolve until June 25, 2007, 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. 8. NON-CONTROLLING INTEREST - EXCHANGEABLE SHARES The exchangeable shares of FET Resources Ltd. are convertible at any time into trust units (at the option of the holder) based on the exchange ratio. The exchange ratio is increased monthly based on the cash distribution paid on the trust units divided by the ten-day weighted average unit price preceding the record date. During the period of January 1 to December 31, 2006, a total of 57,631 exchangeable shares were converted into 81,818 trust units at exchange ratios prevailing at the time. At December 31, 2006, the exchange ratio was 1.46445 trust units for each exchangeable share. Cash distributions are not paid on the exchangeable shares. The exchangeable shares of FET Resources Ltd. are listed for trading on the Toronto Stock Exchange under the symbol FTX. The Trust announced that as a result of minimal number of exchangeable shares outstanding, FET Resources Ltd. has elected to redeem all of its exchangeable shares outstanding on January 16, 2007. In connection with this redemption, FET Resources Ltd. has exercised its overriding "redemption call right" to purchase such exchangeable shares from holders of record. Each redeemed exchangeable share will be 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 has been mailed to all exchangeable shareholders outlining the terms of this redemption. Exchangeable Shares of FET Resources Ltd. Number of Shares Consideration (thousands) ------------------------------------------------------ 2006 2005 2006 2005 --------------------------------------------------------------------- Balance as at January 1 560,218 977,346 $ 4,131 $ 4,934 Net income attributable to non- controlling interest 884 1,437 Exchanged for trust units (57,631) (417,128) (465) (2,240) --------------------------------------------------------------------- Balance as at December 31 502,587 560,218 $ 4,550 $ 4,131 --------------------------------------------------------------------- --------------------------------------------------------------------- 9. 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. The Trust expects to issue units from treasury at a discount to satisfy the distribution reinvestment component of the DRIP Plan. As at December 31, 2006, the Trust has listed and reserved 941,207 trust units for the DRIP Plan. Trust Units of Focus Energy Trust Number of Units Consideration (thousands) ------------------------------------------------------ 2006 2005 2006 2005 --------------------------------------------------------------------- Balance as at January 1 36,687,167 35,973,651 $ 244,426 $ 230,478 --------------------------------------------------------------------- Issued pursuant to Plan of Arrangement with PEML(i) 30,802,817 - 673,041 - Issued on conversion of exchangeable shares(ii) 81,818 546,473 1,922 11,479 Issued pursuant to the Executive Bonus Plan(iii) 42,530 67,293 1,032 1,408 Issued pursuant to the Distribution Reinvestment Plan(iv) 58,793 - 1,029 - Exercise of Unit Appreciation Rights(v) 95,000 99,750 1,116 1,061 Trust unit issue expense - (140) - --------------------------------------------------------------------- Balance as at December 31 67,768,125 36,687,167 $ 922,426 $ 244,426 --------------------------------------------------------------------- --------------------------------------------------------------------- (i) Issued pursuant to the 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. (iv) Issued pursuant to the Distribution Reinvestment Plan, units are either issued from treasury at 95% of the average market price for the 10 days immediately preceding the distribution date or through facilities of the TSX, at prevailing market prices. (v) Exercise of Unit Appreciation Rights includes cash consideration of $805,743 (2005 - $813,123) and contributed surplus credit of $310,639 (2005 - $247,446). 10. 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. Exchangeable Partnership Units of Focus Energy Trust Number of Units Consideration (thousands) ------------------------------------------------------ 2006 2005 2006 2005 --------------------------------------------------------------------- Balance as at January 1 - - - - Issued pursuant to Plan of Arrangement with PEML 9,999,992 - $ 218,500 - --------------------------------------------------------------------- Balance as at December 31 9,999,992 - $ 218,500 - --------------------------------------------------------------------- --------------------------------------------------------------------- The exchangeable partnership units were issued at a fair value of $21.85 per unit. 11. TRUST UNIT RIGHTS PLAN The Trust Unit Rights Plan (the "Plan") was established August 23, 2002 as part of the Plan of Arrangement. The Trust may grant rights to employees, directors, consultants and other service providers of the Trust and any of its subsidiaries. The Trust is authorized to grant up to five percent of the outstanding trust units, including units issuable upon exchange of exchangeable shares and exchangeable partnership units. As at December 31, 2006, the Trust has listed and reserved 3,848,321 trust units and there are rights outstanding to purchase 2,438,063 trust units pursuant to the terms of the Plan. The initial exercise price of rights granted under the 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 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 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. 2006 2005 ------------------------------------------------------ Weighted Weighted Average Average Number of Exercise Number of Exercise Rights Price Rights Price --------------------------------------------------------------------- Balance as at January 1 1,311,100 $ 12.52 1,113,100 $ 11.78 Granted 1,338,447 $ 22.82 337,750 $ 21.68 Exercised (95,000) $ 8.48 (99,750) $ 8.15 Cancelled (116,484) $ 19.74 (40,000) $ 15.10 --------------------------------------------------------------------- Before reduction of exercise price 2,438,063 $ 17.99 1,311,100 $ 14.51 Reduction of exercise price - $ (1.47) - $ (1.99) --------------------------------------------------------------------- Balance as at December 31 2,438,063 $ 16.52 1,311,100 $ 12.52 --------------------------------------------------------------------- --------------------------------------------------------------------- - The average exercise price at the grant date is $19.49 ($15.89 for 2005). - The average contractual life of the rights outstanding is 2.96 years (3.21 years for 2005). - The number of rights exercisable at December 31, 2006 is 434,500 (273,500 for 2005). - The average value at the grant date for the year ended December 31, 2006 is $5.05 ($4.77 for 2005). The fair value of rights is estimated using a modified Black Scholes option pricing model. The Trust has recorded non-cash compensation expense of $2,120,550 for the year ended December 31, 2006. The Trust recorded non-cash compensation expense of $884,362 for the year ended December 31, 2005. The fair value of rights granted in 2006 was estimated using a modified Black Scholes option pricing model with the following weighted average assumptions: risk-free interest rate of 4.29 percent, volatility of 27 percent, life of 2.8 years and a dividend yield rate of 11 percent. Users are cautioned that the assumptions made are estimates of future events and actual results could differ materially from those estimated. 12. ELIMINATION OF THE EXECUTIVE BONUS PLAN Late in the second quarter of 2006, the Board of Directors approved a new compensation plan that would better suit the expanded employee base of the Trust and be more comparable with the standard compensation framework within the sector. In eliminating the Executive Bonus Plan, $3.0 million is being paid to the participants in the Executive Bonus Plan. Half was paid at the end of June 2006 and the remainder will be paid on July 1, 2007. In addition participants received, in aggregate, an additional 495,600 trust unit appreciation rights. 13. ACCUMULATED INCOME (thousands) 2006 2005 --------------------------------------------------------------------- Accumulated income, before cash distributions $ 259,925 $ 186,958 Accumulated cash distributions (311,453) (187,216) --------------------------------------------------------------------- Balance as at December 31 $ (51,528) $ (258) --------------------------------------------------------------------- --------------------------------------------------------------------- 14. 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. The fair market value of the contracts outstanding at December 31, 2006, which have no book value, would have resulted in a net payment to the Trust of $25.7 million. Financial Daily Price Contracts Quantity Contract Price Index Term --------------------------------------------------------------------- Crude oil 400 bbls $ 70.00-79.00 Cdn WTI January 2007 - December 2007 400 bbls $ 70.93 Cdn WTI April 2007 - September 2007(*) Natural gas 6,000 GJ $ 8.01 Cdn AECO August 2006 - March 2007 7,000 GJ $ 9.00 Cdn AECO August 2006 - March 2007 20,000 GJ $ 7.66 Cdn AECO August 2006 - March 2007 11,000 GJ $ 8.73 Cdn AECO November 2006 - March 2007 13,000 GJ $ 9.32 Cdn AECO November 2006 - March 2007 7,300 GJ $ 7.70 Cdn AECO March 2007 - October 2007 15,000 GJ $ 7.77 Cdn AECO April 2007 - October 2007 10,000 GJ $ 7.90 Cdn AECO April 2007 - October 2007 5,000 GJ $ 8.00 Cdn AECO April 2007 - October 2007 5,000 GJ $ 7.52 Cdn AECO April 2007 - October 2007 5,000 GJ $ 7.50 Cdn AECO April 2007 - October 2007 5,000 GJ $ 7.53 Cdn AECO April 2007 - October 2007 5,000 GJ $ 7.50 Cdn AECO April 2007 - October 2007 15,000 GJ $ 8.25-9.00 Cdn AECO November 2007 - March 2008 15,000 GJ $ 8.02 Cdn AECO November 2007 - March 2008(*) 10,000 GJ $ 8.60 Cdn AECO November 2007 - March 2008(*) --------------------------------------------------------------------- (*) contract entered into subsequent to December 31, 2006 --------------------------------------------------------------------- --------------------------------------------------------------------- Focus has designated their commodity contracts as effective accounting hedges on their respective contract dates. New CICA Handbook Standards, Financial Instruments - Recognition and Measurement - Section 3855, Hedges - Section 3865, and Comprehensive Income - Section 1530 are applicable for the Trust beginning in 2007. As a result, hedge accounting for financial contracts will not be continued in future periods beyond 2006. All derivative contracts will be recorded at fair value on the balance sheet. Derivatives will be adjusted to fair value each period with the change recognized in the determination of income. Settlement of derivatives will be included in the Statement of Cash Flows as an operating activity. Unrealized gains and losses will be subtracted or added back as a non-cash item. Adoption of these new standards is applied retrospectively which means the opening balance of retained earning is restated in 2007. Prior periods are not restated. Focus has recognized an asset for commodity contracts of $1.7 million as part of the business acquisition with PEML. This amount will be amortized over the term of those contracts, November 2006 to March 2007. In 2006, $0.7 million has been recognized in the income statement leaving an asset balance of $1.0 million at December 31, 2006. In July 2006, Focus amended certain commodity contracts effectively canceling a number of contracts with terms of November 2006 to March 2007 and writing new contracts with the same volume over the term of August 2006 to March 2007. The result of these amendments was recognition of the fair value of the original commodity contracts as an asset and liability in the balance sheet. The asset is being amortized over the original contracts and has a balance of $2.0 million at December 31, 2006. The liability is being amortized over the original contracts and has a balance of $3.1 million at December 31, 2006. The difference of $1.1 million has been recognized in the income statement. Total amortization of hedging contracts was $1.8 million in 2006. 15. 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 December 31, 2006, which have no book value, would have resulted in a net payment to the Trust of $7.8 million. Physical Sales Daily Contract Contracts Quantity Price Term --------------------------------------------------------------------- Natural gas - fixed price 5,000 GJ $10.32 Cdn November 2006 - March 2007 12,500 GJ $7.31 Cdn August 2006 - March 2007 10,000 GJ $6.77 Cdn August 2006 - March 2007 15,000 GJ $7.15 Cdn April 2007 - October 2007 10,000 GJ $7.18 Cdn April 2007 - October 2007 --------------------------------------------------------------------- 16. 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 shares converted at the average exchange ratio and include exchangeable partnership units. Basic per-unit calculations for the year ended December 31 are based on the weighted average number of trust units and exchangeable partnership units outstanding in 2006 of 57,828,890 (2005 of 36,432,905). Diluted calculations for the year ended December 31 include additional trust units for the dilutive impact of the Rights Plan in 2006 of 529,664 (2005 of 564,620) and 753,769 exchangeable shares (2005 of 910,887) 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. Supplementary cash flow information for the year ended December 31: (thousands) 2006 2005 --------------------------------------------------------------------- Interest paid $ 13,490 $ 3,345 Interest received $ 33 $ 40 Taxes paid $ 30,993 $ 791 Cash distributions paid $ 118,399 $ 72,829 --------------------------------------------------------------------- 17. INCOME TAXES Effective July 1, 2006, the Saskatchewan general corporate income tax rate decreased from 17 percent to 14 percent with a further reduction to 13 percent expected on July 1, 2007 and to 12 percent on July 1, 2008. Effective April 1, 2006, the Alberta general corporate income tax rate decreased from 11.5 percent to 10 percent. In 2003, Royal Assent was received legislating the reduction of the federal general corporate income tax rate on income from resource activities from 28 percent to 21 percent and for the elimination of the existing 25 percent resource allowance deduction and introduced the deductibility of actual provincial and other Crown royalties paid, to be phased in over a five-year period. The phase in will be complete in 2007. In addition, the Federal Government further announced in 2006 a reduction in the general corporate tax rate from 21 percent to 19 percent from 2008 to 2010 and the elimination of the corporate surtax in 2008 and the large corporations tax in 2006. The Trust's expected future income tax rate is approximately 30.8 percent at December 31, 2006 compared to 34 percent at December 31, 2005. The Trust recorded a future income tax recovery of $30.2 million in 2006. This amount includes a recovery of $8.2 million relating to accounting for non- controlling interest - exchangeable shares ($5.7 million in 2005). The Trust recognized future income tax liabilities of $266.7 million in 2006 related to the acquisition of PEML, a private company. Certain of the Trust's assets are held by entities which transfer taxable income to unitholders. The excess of the carrying value of these assets over the tax value is $77.2 million at December 31, 2006. On October 31, 2006, the Federal Government announced proposals pertaining to the taxation of distributions from publicly traded Canadian income trusts, royalty trusts and partnerships. The proposals include a 31.5 percent tax imposed on income before distributions at the trust level and taxed to the taxable Canadian investor, effectively as a dividend. If enacted, the proposals would apply to the Trust effective January 1, 2011. On December 21, 2006, the Department of Finance issued draft legislation consistent with the proposals described above. As at December 31, 2006, the legislative proposals are not substantively enacted and thus there is no impact on the recognition of future income taxes in 2006. If the legislation is enacted, the Trust's taxable status will change resulting in recognition of future tax liabilities at substantively enacted tax rates in respect of temporary differences described above. The provision for future income taxes is different from the amount computed by applying the combined statutory Canadian Federal and Provincial income tax rate to income for the period before income taxes. The differences are as follows: (thousands) 2006 2005 --------------------------------------------------------------------- Income before income and other taxes and non-controlling interest - exchangeable shares $ 43,852 $ 60,099 --------------------------------------------------------------------- Statutory combined federal and provincial income tax rate 35.5% 38.08% Expected income tax expense at statutory rates $ 15,567 $ 22,885 Add (deduct) the income tax effect of: Income attributable to the Trust, not subject to income tax (39,726) (28,779) Non-deductible Crown charges 3,294 9,969 Resource allowance (3,718) (8,781) Alberta Royalty Tax Credit (58) (121) Reduction in corporate tax rate (10,094) (1,832) Capital tax - 836 Other 4,736 1,021 --------------------------------------------------------------------- Income and other taxes $ (29,999) $ (4,802) --------------------------------------------------------------------- --------------------------------------------------------------------- The components of the future tax liability at December 31 are as follows: (thousands) 2006 2005 --------------------------------------------------------------------- Capital assets in excess of tax value $ 331,150 $ 87,973 Provision for asset retirement obligation (11,143) (5,170) Other (1,207) (1,169) --------------------------------------------------------------------- Future income taxes $ 318,800 $ 81,634 --------------------------------------------------------------------- --------------------------------------------------------------------- 18. COMMITMENTS AND CONTINGENCIES The Trust is involved in 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 ($ thousands) Total 2007 2008-2009 2010-2011 thereafter --------------------------------------------------------------------- Office premises 2,436 626 1,315 495 - Operating leases 342 342 - - - Mineral and surface leases(2) 26,434 4,406 8,811 8,811 4,406 Transportation and processing 20,138 11,250 5,276 1,038 2,574 Asset retirement obligations(3) 36,131 193 490 950 34,498 --------------------------------------------------------------------- Total contractual obligations 85,481 16,817 15,892 11,294 41,478 --------------------------------------------------------------------- --------------------------------------------------------------------- (1) The table does not include the Trust's obligations for financial instruments and physical sales contracts which are fully disclosed in Notes 14 and 15. (2) The Trust makes payments for mineral and surface leases. The table includes payments for each of the years 2007 to 2011 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. 19. SUBSEQUENT EVENT On January 16, 2007 FET Resources Ltd. redeemed all of its outstanding exchangeable shares. Each redeemed exchangeable share was exchanged for trust units in accordance with the exchange rate in effect at January 15, 2007 of 1.47300. APPENDIX B - RESERVES INFORMATION The following cautionary statements are specifically required by NI 51- 101. 1. It should not be assumed that the estimates of future net revenues presented in the tables represent the fair market value of the reserves. There is no assurance that the constant price and cost assumptions and forecast prices and costs assumptions will be attained and variances could be material. 2. Disclosure provided herein in respect of BOE may be misleading, particularly if used in isolation. In accordance with NI 51-101, a BOE conversion ratio of 6 mcf:1 bbl has been used in all cases in this disclosure. This BOE conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. 3. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during the year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year. 4. Estimates of reserves and future net revenues for individual properties may not reflect the same confidence level as estimates of reserves and future net revenues for all properties due to the effects of aggregation. 5. In all cases, the F&D or FD&A cost is calculated by dividing the identified capital expenditures by the applicable reserves additions. 2006 RESERVES SUMMARY Company Gross Reserves at December 31, 2006 (before deduction of royalties payable, not including royalties receivable) (based on Forecast Prices and Costs) Light & Medium Natural Oil Crude Oil Gas NGLs Equivalent (mbbl) (Mmcf) (mbbl) (MBOE) ------------------------------------------------------------------------- Proved producing 3,971 199,538 1,709 38,936 Proved non-producing 57 14,467 147 2,615 ------------------------------------------------------------------------- Total proved developed 4,028 214,005 1,856 41,552 Proved undeveloped 188 116,936 693 20,370 ------------------------------------------------------------------------- Total proved 4,216 330,941 2,549 61,922 Probable additional 1,023 119,997 718 21,740 ------------------------------------------------------------------------- Total proved + probable 5,239 450,938 3,267 83,662 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Company Net Reserves at December 31, 2006 (after deduction of royalties payable, including royalties receivable) (based on Forecast Prices and Costs) Light & Medium Natural Oil Crude Oil Gas NGLs Equivalent (mbbl) (Mmcf) (mbbl) (MBOE) ------------------------------------------------------------------------- Proved producing 3,438 172,322 1,313 33,471 Proved non-producing 45 10,785 113 1,956 ------------------------------------------------------------------------- Total proved developed 3,483 183,107 1,426 35,427 Proved undeveloped 166 100,708 548 17,499 ------------------------------------------------------------------------- Total proved 3,649 283,815 1,974 52,926 Probable additional 892 103,168 560 18,646 ------------------------------------------------------------------------- Total proved + probable 4,541 386,983 2,534 71,572 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 1) Numbers may not add due to rounding. 2006 RESERVE RECONCILIATION Company Gross Reserves (before deduction of royalties payable, not including royalties receivable) Light & Medium Natural Oil Crude Oil Gas NGLs Equivalent TOTAL PROVED (mbbl) (Mmcf) (mbbl) (MBOE) ------------------------------------------------------------------------- December 31, 2005 4,087 145,828 2,631 31,022 Discoveries 0 377 0 63 Extensions 135 30,322 404 5,593 Improved recovery 0 0 0 0 Technical revisions (120) (6,284) (216) (1,384) Economic factors 0 0 0 0 Acquisitions 749 191,567 0 32,677 Dispositions 0 (1,470) 0 (245) Production (634) (29,399) (270) (5,804) ------------------------------------------------------------------------- December 31, 2006 4,216 330,941 2,549 61,922 ------------------------------------------------------------------------- ------------------------------------------------------------------------- PROBABLE ------------------------------------------------------------------------- December 31, 2005 1,521 41,678 789 9,257 Discoveries 0 75 0 13 Extensions 45 8,881 79 1,604 Improved recovery 0 0 0 0 Technical revisions (731) (6,077) (149) (1,893) Economic factors 0 0 0 0 Acquisitions 187 75,552 0 12,779 Dispositions 0 (113) 0 (19) Production 0 0 0 0 ------------------------------------------------------------------------- December 31, 2006 1,023 119,997 718 21,740 ------------------------------------------------------------------------- ------------------------------------------------------------------------- PROVED PLUS PROBABLE ------------------------------------------------------------------------- December 31, 2005 5,608 187,506 3,420 40,279 Discoveries 0 452 0 75 Extensions 180 39,203 483 7,196 Improved recovery 0 0 0 0 Technical revisions (851) (12,361) (366) (3,277) Economic factors 0 0 0 0 Acquisitions 936 267,119 0 45,456 Dispositions 0 (1,583) 0 (264) Production (634) (29,399) (270) (5,804) ------------------------------------------------------------------------- December 31, 2006 5,239 450,938 3,267 83,662 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 1) All reserves are based on Forecast Prices and Costs. 2) Numbers may not add due to rounding. NET PRESENT VALUE SUMMARY Net Present Value of Future Net Revenue Before Income Taxes - Forecast Prices and Costs Undiscounted Discounted Discounted Discounted Discounted ($ thousands) at 5% at 10% at 15% at 20% ------------------------------------------------------------------------- Proved producing 1,217,303 961,714 802,245 693,059 613,455 Proved non-producing 73,094 53,491 42,806 35,835 30,849 ------------------------------------------------------------------------- Total proved developed 1,290,397 1,015,205 845,051 728,894 644,304 Proved undeveloped 416,016 257,184 168,295 113,351 76,974 ------------------------------------------------------------------------- Total proved 1,706,413 1,272,389 1,013,346 842,245 721,278 Probable additional 676,660 397,089 262,405 187,039 140,339 ------------------------------------------------------------------------- Total proved + probable 2,383,073 1,669,478 1,275,751 1,029,284 861,617 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 1) Numbers may not add due to rounding. December 31, 2006 Price Forecast - GLJ Petroleum Consultants Ltd. Westcoast Edmonton Henry Hub AECO C Station 2 WTI Light Natural Natural Natural Exchange Crude Oil Crude Oil Gas Gas Gas Rate $US/bbl $CDN/bbl $US/Mmbtu $CDN/Mmbtu $CDN/Mmbtu $US/$CDN ------------------------------------------------------------------------- 2007 62.00 70.25 7.25 7.20 7.20 0.87 2008 60.00 68.00 7.50 7.45 7.45 0.87 2009 58.00 65.75 7.50 7.75 7.75 0.87 2010 57.00 64.50 7.50 7.80 7.80 0.87 2011 57.00 64.50 7.50 7.85 7.85 0.87 2012 57.50 65.00 7.75 8.15 8.15 0.87 2013 58.50 66.25 7.90 8.30 8.30 0.87 2014 59.75 67.75 8.05 8.50 8.50 0.87 2015 61.00 69.00 8.20 8.70 8.70 0.87 2016 62.25 70.50 8.40 8.90 8.90 0.87 2017 63.50 71.75 8.55 9.10 9.10 0.87 Escalate thereafter at 2%/yr 2%/yr 2%/yr 2%/yr 2%/yr 0%/yr ------------------------------------------------------------------------- Net Present Value of Future Net Revenue Before Income Taxes - Constant Prices and Costs Undiscounted Discounted Discounted Discounted Discounted ($ thousands) at 5% at 10% at 15% at 20% ------------------------------------------------------------------------- Proved producing 925,108 751,029 637,173 556,728 496,768 Proved non-producing 52,374 39,843 32,397 27,330 23,623 ------------------------------------------------------------------------- Total proved developed 977,482 790,872 669,570 584,058 520,391 Proved undeveloped 222,035 129,795 76,307 42,662 20,290 ------------------------------------------------------------------------- Total proved 1,199,517 920,667 745,877 626,720 540,681 Probable additional 421,439 260,694 176,952 127,643 96,083 ------------------------------------------------------------------------- Total proved + probable 1,620,956 1,181,361 922,829 754,363 636,764 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 1) Numbers may not add due to rounding. Constant Prices at December 31, 2006 Westcoast Edmonton Light AECO C Station 2 Crude Oil Natural Gas Natural Gas $CDN/bbl $CDN/Mmbtu $CDN/Mmbtu ------------------------------------------------------------------------- 2007 and thereafter 67.58 6.07 6.22 FINDING AND DEVELOPMENT COSTS Company Gross Reserves Excluding the Effect of Acquisitions and Three-Year Dispositions(1) 2006 2005 2004 Total ------------------------------------------------------------------------- Capital expenditures - $MM 57.2 43.0 25.2 125.4 Net change in future development capital - $MM Proved 11.5 13.9 9.5 35.0 Proved plus probable 14.3 15.9 3.6 33.8 Total capital including change in future development capital - $MM Proved 68.7 57.0 34.6 160.3 Proved plus probable 71.5 58.9 28.8 159.1 ------------------------------------------------------------------------- Reserve additions - MMBOE Proved 4.27 2.61 1.88 8.76 Proved plus probable 4.00 1.63 1.80 7.42 ------------------------------------------------------------------------- Finding and development cost - $/BOE Proved $16.09 $21.86 $18.40 $18.30 Proved plus probable $17.89 $36.15 $15.99 $21.44 ------------------------------------------------------------------------- (1) Reserves are based on Forecast Prices and Costs. (2) Numbers may not add due to rounding. FINDING, DEVELOPMENT AND ACQUISITION COSTS Company Gross Reserves Including the Effect of Acquisitions and Three-Year Dispositions(1) 2006 2005 2004 Total ------------------------------------------------------------------------- Capital expenditures - $MM 1,161.0 53.4 154.8 1,369.2 Net change in future development capital - $MM Proved 197.1 14.1 18.6 229.8 Proved plus probable 254.2 18.9 21.4 294.4 Total capital including change in future development capital - $MM Proved 1,358.1 67.5 173.4 1,599.0 Proved plus probable 1,415.2 72.3 176.2 1,663.6 ------------------------------------------------------------------------- Reserve additions - MMBOE Proved 36.70 3.09 12.50 52.30 Proved plus probable 49.19 2.42 15.48 67.09 ------------------------------------------------------------------------- Finding and development cost - $/BOE Proved $37.00 $21.84 $13.87 $30.58 Proved plus probable $28.77 $29.87 $11.38 $24.80 ------------------------------------------------------------------------- (1) Reserves are based on Forecast Prices and Costs. (2) Numbers may not add due to rounding. 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.

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

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