Progress Energy Replaces 165% of Production Through Drillbit



    165 Percent Production Replacement Reinvesting 64 Percent of Cash Flow

    CALGARY, Feb. 28 /CNW/ - Progress Energy ("Progress" or the "Company")
today announced its operating and financial results for the year ended
December 31, 2007.

    
    2007 HIGHLIGHTS

    -   Completed two strategic acquisitions in the first half of 2007, both
        with producing assets in the Company's existing areas of operation in
        the Deep Basin of northwest Alberta and the Foothills of northeast
        British Columbia. The acquisitions included substantial undeveloped
        exploration acreage, low decline production and significant tax
        pools.
    -   Drill bit replacement was 165 percent on a proved plus probable basis
        reinvesting 64 percent of cash flow. Reserve growth in 2007 replaced
        361 percent of production on a proved plus probable basis.
    -   Year end 2007 reserves increased 34 percent to 86.8 million barrels
        of oil equivalent (boe) on a proved plus probable basis.
    -   Capital investment in land, seismic, drilling and facilities
        construction and acquisitions totalled $566.4 million in 2007.
    -   Finding, development and acquisition (FD&A) costs were $14.50 per boe
        proved plus probable, excluding changes in future development
        capital. Including changes in future development capital, FD&A costs
        were $16.67 per boe proved plus probable.
    -   Drill bit finding and development costs which are representative of
        our ongoing program, before changes in future development capital
        were $9.91 per boe on a proved plus probable basis. Including the
        change in future development capital it was $14.59 per boe proved
        plus probable.
    -   Progress' 3-year average drill bit finding and development cost is
        $12.59 per boe proved plus probable, including changes in future
        development capital.
    -   The Company's recycle ratio was 1.7 times based on its 2007 operating
        netback of $29.11 per boe divided by its proved plus probable FD&A of
        $16.67.
    -   The Company's reserve life index remained consistent at 9.8 years
        proved plus probable.
    -   Drilling in 2007 resulted in 48 net wells with a 95 percent success
        rate. Nearly all of the successful wells from the 2007 drilling
        program were tied-in and on production as at February 28, 2008.
    -   Production averaged 24,240 boe per day in the fourth quarter, an
        increase of two percent from the third quarter of 2007 and 34 percent
        higher compared to the fourth quarter of 2006. Production averaged
        23,031 boe per day for 2007, 29 percent higher than 2006 as a result
        of the two strategic acquisitions completed by the Company.
    -   Cash flow from operations before changes in non-cash working capital
        ("cash flow") was $214.3 million in 2007 or $2.02 per unit diluted.
        In the fourth quarter, cash flow was $54.7 million or $0.49 per unit
        diluted.
    -   The Company generated an operating netback of $29.11 per boe in 2007
        and $28.49 per boe in the fourth quarter as a result of its high-heat
        content, liquids-rich natural gas production stream and its low
        operating cost profile.
    -   Operating costs averaged $6.38 per boe for the year and in the fourth
        quarter they were $5.91 per boe, down 10 percent from the first nine
        months average in 2007 reflecting a trending down of operating costs
        as a result of optimization activities and increased throughput at
        Company-owned facilities.
    -   Cash distributed to unitholders in 2007 totalled $114.1 million or
        $1.20 per Trust unit achieving a payout ratio of 53 percent excluding
        exchangeable shares and 61 percent including exchangeable shares.
    -   Total debt as at December 31, 2007 was $444.2 million, consisting of
        bank debt of $296.6 million, convertible debentures of $122.2 million
        and a working capital deficiency of $25.5 million.

    2007 RESERVES SUMMARY
                                                                 Proved plus
    (mmboe)                                              Proved     Probable
    -------------------------------------------------------------------------
    Opening Balance                                       48.22        64.88
      Net additions                                       21.92        30.34
      Production                                          (8.41)       (8.41)
    -------------------------------------------------------------------------
    Closing Balance                                       61.74        86.82
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Reserve Life Index (years)                              7.0          9.8
    Percentage of proved reserves that
     are undeveloped (%)                                    7.0          7.0
    Finding, development and acquisition costs ($/boe)   $22.10       $16.67
    Finding, development and acquisition costs,
     excluding changes in future development
     capital ($/boe)                                     $20.07       $14.50
    Drill bit finding and development costs,
     excluding changes in future development
     capital ($/boe)                                     $15.93       $ 9.91
    -------------------------------------------------------------------------
    GLJ Petroleum Consultants Ltd., an independent qualified reserves
    evaluation firm, evaluated 100 percent of the Company's reserves.


    2008 UPDATE

    -   Progress currently has five drilling rigs active in the field and
        expects to have drilled 29 wells (14 net) by the end of the first
        quarter of 2008.
    -   Current production is approximately 24,500 boe per day
    

    OPERATIONAL

    Progress' land base totals approximately 545,000 undeveloped acres under
its control. This land base contains an extensive inventory of identified
drilling locations representing over three years of drilling opportunities at
current activity levels. The Company's primary focus regions in the Deep Basin
region of northwest Alberta and the Foothills of northeast British Columbia
were further reinforced by the assets acquired from two major international
producers in the first half of 2007.
    The Company's largest producing region remains the Deep Basin of
northwest Alberta which is located immediately south of the city of Grande
Prairie. The region is characterized by its multiplicity of producing zones
that produce liquids-rich natural gas and light oil. In 2007, Progress drilled
22 wells with a success rate of 95 percent. Progress conducted extensive
sub-surface mapping projects in 2007 resulting in several new pool discoveries
in the Falher and Charlie Lake formations as well as several Gething gas pool
discoveries. The Company anticipates running two drilling rigs continuously
throughout the year in the Deep Basin region.
    In the Foothills of northeast British Columbia, the Company is continuing
to build on the success of its 2007 drilling program and the acquisition of
the Bubbles property. The Company drilled 17 wells with a program success rate
of 93 percent. During the year, the Company more than doubled its land
position to over 170,000 undeveloped acres under its control through a
combination of corporate acquisitions, crown land sales and farm-ins.

    HEDGING UPDATE

    Progress has hedged 80,000 gigajoules (GJ) per day (approximately
70 million cubic feet per day), or 60 percent of its before royalty forecast
natural gas production, for the period from April 1, 2008 through to
October 31, 2008 at an average equivalent AECO net floor price of C$7.85 per
thousand cubic feet (mcf) based on the Company's high heat content natural gas
production. The summer hedging program was completed using a series of swaps
and bull spread structures. The swap and bull spread structure that Progress
utilizes sets a relatively high floor in the current market and allows
participation up to an equivalent average summer 2008 AECO gas price of C$9.45
per mcf.

    OUTLOOK

    The primary focus of Progress is per unit sustainability from internally
generated opportunities. In 2007, we made two strategic acquisitions in the
first half of the year which have substantially expanded our dominant position
in the Deep Basin and Foothills. In addition to the step change in our
drilling inventory, the acquisitions also provide significant tax pools which
will extend our tax horizon. We will continue to pursue the same disciplined,
internal value creation strategy in 2008 leveraging our large exploration land
base and extensive inventory of drilling locations. As we move toward 2011,
Progress will benefit from the recently announced combined federal and
provincial proposed tax rate reductions from the current level of 31.5 percent
to 25 percent in 2012, the lowest expected corporate rate in Canada.
    We are targeting capital investment of approximately $110 to $125 million
in 2008 and the drilling of between 45 to 55 net wells with approximately 20
to 25 of these wells located in northeast British Columbia and approximately
25 to 30 wells in northwest and central Alberta. This investment will provide
the springboard for future reserves and production growth beyond the existing
inventory of drilling locations. We are targeting average production in 2008
of approximately 23,500 boe per day which includes the scheduled major plant
turnaround at the Spectra-owned McMahon gas processing facility.
    On the commodity front, we are seeing positive changes in the
supply-demand balance for natural gas. Although natural gas production in
North America has shown minor growth, it requires an accelerating pace of
drilling in order to offset annual depletion, yet natural gas focused rig
activity has been stagnant for the past year. Liquefied natural gas supply
grew in 2007 and had a negative impact on North American natural gas prices.
The growth in supply was largely the result of a lack of weather related
demand in Europe through winter and spring. These LNG cargoes were then
diverted to higher netback markets in the U.S. thereby filling storage to
record levels. On the demand side, weather will continue to be a key factor in
consumption patterns for residential and commercial heating load in winter and
electric power generation for air conditioning load in the summer.
    Progress' employees, management and directors hold an 11 percent direct
ownership interest in the Company creating a very strong alignment with the
interests of our unitholders.

    On behalf of the Board of Directors,

    (Signed) "Michael R. Culbert"


    Michael R. Culbert
    President & Chief Executive Officer
    February 28, 2008


    ANNUAL MEETING OF UNITHOLDERS
    -----------------------------
    The Company's Annual Meeting of Unitholders is scheduled for 3:30 PM on
Thursday, May 1, 2008 at the Petroleum Club, 319 - 5th Avenue S.W. Calgary,
Alberta.

    Forward-Looking Statements - Certain information regarding Progress set
forth in this document, including management's assessment of Progress' future
plans and operations, contains forward-looking statements that involve
substantial known and unknown risks and uncertainties. These forward-looking
statements are subject to numerous risks and uncertainties, certain of which
are beyond Progress' 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 producers, the lack of availability of qualified
personnel or management, stock market volatility and ability to access
sufficient capital from internal and external sources. Progress' 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
so, what benefits that Progress will derive therefrom.

    In this news release, production and reserves information may be
presented on a boe basis with six mcf of natural gas being equivalent to one
barrel ("barrel") of crude oil or natural gas liquids. Boe's may be misleading
particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is
based on an energy equivalency conversion method primarily applicable at the
burner tip and does not represent a value equivalency at the wellhead.

    RESERVES

    Progress Energy Trust's ("Progress" or the "Trust") reserves were
prepared by the independent engineering firm of GLJ Petroleum Consultants
("GLJ") in 2007, as well as prior years back to 2001. Reserves included herein
are stated on a company interest basis (before royalty burdens and including
royalty interests) unless noted otherwise. All reserves information has been
prepared in accordance with National Instrument ("NI") 51-101. The Trust's
actual natural gas and petroleum reserves and future production will be
greater than or less than the estimates provided. The estimated future net
revenue from the production of the Trust's natural gas and petroleum reserves
does not represent the fair market value of the Trust's reserves. In addition
to the information disclosed in this release, more detailed information on a
gross interest basis (before royalty burdens and excluding royalty interests)
is included in the Trust's Annual Information Form.

    
    -   Total proved reserves at December 31, 2007 increased 28 percent to
        61.7 million boe compared to 48.2 million boe in 2006.
    -   Total proved plus probable reserves at December 31, 2007 increased
        34 percent to 86.8 million boe compared to 64.9 million boe in 2006.
    -   Reserve growth in 2007 was achieved through a corporate acquisition
        completed April 2, 2007 with assets in the Deep Basin and Foothills
        regions, an asset acquisition in the Wapiti area of the Deep Basin
        completed May 31, 2007, as well as through the drill bit.  As a
        result, Progress replaced 361 percent of production on a proved plus
        probable basis and 261 percent on a proved basis.


    2007 SUMMARY OF OIL AND GAS RESERVES
    Forecast Prices and Costs
    Company Interest

                           Light and   Natural
                              Medium       Gas   Natural     Total     Total
                           Crude Oil   Liquids       Gas      2007      2006
    -------------------------------------------------------------------------
                              (mbbls)   (mbbls)     (bcf)    (mboe)    (mboe)
    Proved
      Developed producing      4,241     3,348     249.4    49,149    41,274
      Developed non-producing    193       434      30.7     5,745     3,776
      Undeveloped                108       448      37.7     6,842     3,171
    -------------------------------------------------------------------------
    Total proved               4,542     4,230     317.8    61,736    48,221
    Probable                   1,402     1,606     132.4    25,082    16,662
    -------------------------------------------------------------------------
    Total proved plus
     probable                  5,944     5,837     450.2    86,818    64,883
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Note:  May not add due to rounding



    Forecast Prices and Costs
    Net Present Value of Reserves After Income Taxes

                                          Discounted  Discounted  Discounted
    ($ millions)            Undiscounted       at 5%       at 8%      at 10%
    -------------------------------------------------------------------------
    Proved
      Developed producing          1,404       1,075         950         884
      Developed non-producing        151         116         102          94
      Undeveloped                    138          97          81          72
    -------------------------------------------------------------------------
    Total proved                   1,692       1,288       1,133       1,051
    Probable                         642         383         304         265
    -------------------------------------------------------------------------
    Total proved plus probable     2,335       1,671       1,436       1,316
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Note:  May not add due to rounding



    Forecast Prices and Costs
    Price Assumptions

    The January 1, 2008 pricing forecasts presented below have been prepared
by GLJ.  These prices have been utilized in determining the reserves and cash
flow forecasts.

                                         Crude Oil
                             Crude Oil    Edmonton  Natural Gas  Natural Gas
    Year                           WTI       Light         AECO   Sumas Spot
    -------------------------------------------------------------------------
                              ($US/bbl)  ($Cdn/bbl) ($Cdn/MMBtu)  ($US/MMBtu)
    2008                         92.00       91.10         6.75         6.90
    2009                         88.00       87.10         7.55         7.70
    2010                         84.00       83.10         7.60         7.70
    2011                         82.00       81.10         7.60         7.70
    2012                         82.00       81.10         7.60         7.70
    2013 - 2017(1)               82.34       81.44         7.96         8.06
    Thereafter(%/year)(2)         +2.0        +2.0         +2.0         +2.0
    -------------------------------------------------------------------------
    (1) Prices shown are an average over the period.
    (2) Percentage change of 2.0% represents the change in future prices each
        year after 2017 to the end of the reserve life.



    2007 RESERVE RECONCILIATION

    Forecast Prices and Costs
    Reconciliation of Company Interest Reserves by Principal Product Type

                               Light and                 Natural
                                  Medium     Natural         Gas
                                   Crude         Gas     Liquids       Total
    -------------------------------------------------------------------------
    Proved Producing               (mbbl)       (bcf)      (mbbl)     (mmboe)
      Opening balance              4,672      200.12       3,248        41.3
      Exploration discoveries          -        0.08           3           -
      Drilling extensions,
       improved recovery and
       infill drilling                 5       37.27         557         6.8
      Technical revisions            211      (20.34)       (439)       (3.6)
      Acquisitions                   138       74.86         506        13.1
      Dispositions                     -       (0.06)          -           -
      Production                    (784)     (42.57)       (528)       (8.4)
    -------------------------------------------------------------------------
      Closing Balance              4,241      249.36       3,348        49.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total Proved
      Opening balance              4,942      236.91       3,794        48.2
      Exploration discoveries          -        0.08           3           -
      Drilling extensions,
       improved recovery and
       infill drilling                 5       70.83         944        12.8
      Technical revisions            242      (23.23)       (496)       (4.1)
      Acquisitions                   138       75.82         513        13.3
      Dispositions                     -       (0.06)          -           -
      Production                    (784)     (42.57)       (528)       (8.4)
    -------------------------------------------------------------------------
      Closing Balance              4,542      317.78       4,230        61.7
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Proved Plus Probable
      Opening balance              6,341      321.13       5,021        64.9
      Exploration discoveries          -        0.09           4           -
      Drilling extensions,
       improved recovery and
       infill drilling                 7      110.46       1,408        19.8
      Technical revisions            211      (32.82)       (693)       (5.9)
      Acquisitions                   169       94.00         626        16.5
      Dispositions                     -       (0.07)          -           -
      Production                    (784)     (42.57)       (528)       (8.4)
    -------------------------------------------------------------------------
      Closing Balance              5,944      450.22       5,837        86.8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Note:  May not add due to rounding
    

    Reserve Revisions

    Downward revisions to prior year bookings were made this year to West Beg
and Town where Halfway natural gas production trends, which were believed to
be stabilizing, continued to decline to the regional average decline curve.
Many of these wells had been expected to stabilize at higher levels due to the
higher initial production rates, however ultimate recoveries will still be
above average due to the early flush period of approximately two years. At
Gold Creek, a revision was made to reflect performance that was less than
anticipated from a high rate well that was drilled late in 2006. Other
revisions were experienced due to matching of hydrocarbon liquid ratios to
2007 performance on producing and future wells across the Foothills assets.

    2007 FINDING, DEVELOPMENT AND NET ACQUISITION COSTS

    Finding, development and acquisition costs ("FD&A") associated with the
2007 capital program and acquisitions completed during the year, including
revisions and the change in future development capital, were $22.10 per proved
boe and $16.67 per proved plus probable boe. On April 2, 2007 Progress
acquired all of the issued and outstanding shares of a private company for
$527.4 million, net of certain assets retained by the vendor and in
conjunction with the acquisition, disposed of certain assets of the private
company to ProEx Energy Ltd. ("ProEx") for $134.4 million, for a total net
cost of $393.0 million. The amount allocated to property, plant and equipment
was $266.6 million, the difference is mainly comprised of a future income tax
asset balance. The majority of the assets included in the acquisition are in
the northeast British Columbia Foothills and the northwest Alberta Deep Basin
regions. On May 31, 2007 Progress acquired certain petroleum and natural gas
assets in the Wapiti area of the Deep Basin region for $41.3 million. There
were no acquisitions or dispositions of a material nature in 2006 and 2005.
Three year average FD&A costs, including revisions and the change in future
development capital were $18.14 per proved boe and $14.20 per proved plus
probable boe.

    
                                                            Proved
                                                              Plus    Proved
                                        Proved            Probable      Plus
                            Capital    Reserve   Proved    Reserve  Probable
                       Expenditures  Additions    Costs  Additions     Costs
    -------------------------------------------------------------------------
                        ($ millions)    (mmboe)  ($/boe)    (mmboe)   ($/boe)
    Total 2007 proved
     FD&A costs including
     future development
     costs                    484.4      21.92    22.10        n/a       n/a

    Total 2007 proved
     plus probable FD&A
     costs including
     future development
     costs                    505.7        n/a      n/a      30.34     16.67

    Three year average
     proved FD&A costs
     including future
     development costs        743.2      40.98    18.14        n/a       n/a

    Three year average
     proved plus probable
     FD&A costs including
     future development
     costs                    776.9        n/a      n/a      54.71     14.20
    -------------------------------------------------------------------------

    2007 FINDING AND DEVELOPMENT COSTS

    Finding and development costs ("F&D") associated with the 2007 capital
program, including revisions and the change in future development capital,
were $20.97 per proved boe and $14.59 per proved plus probable boe. Three year
average F&D costs, including revisions and the change in future development
capital were $16.00 per proved boe and $12.59 per proved plus probable boe.

                                                            Proved
                                                              Plus    Proved
                                        Proved            Probable      Plus
                            Capital    Reserve   Proved    Reserve  Probable
                       Expenditures  Additions    Costs  Additions     Costs
    -------------------------------------------------------------------------
                        ($ millions)    (mmboe)  ($/boe)    (mmboe)   ($/boe)
    Total 2007 proved
     F&D costs including
     future development
     costs                    181.4       8.65    20.97        n/a       n/a

    Total 2007 proved
     plus probable F&D
     costs including
     future development
     costs                    202.7        n/a      n/a      13.89     14.59

    Three year average
     proved F&D costs
     including future
     development costs        439.6      27.47    16.00        n/a       n/a

    Three year average
     proved plus probable
     F&D costs including
     future development
     costs                    472.7        n/a       n/a     37.55     12.59
    -------------------------------------------------------------------------

    Reconciliation of Changes in Future Development Capital

    In accordance with NI 51-101, the capital used to calculate FD&A and F&D
costs has been adjusted to account for the change in future development
capital. For that reason the capital may differ between the proved case and
the proved plus probable case.

    ($ millions)
                                                          Proved
                                                            Plus
    Year                          Proved      Change    Probable      Change
    -------------------------------------------------------------------------
    2007                           78.91       44.41      120.92       65.71
    2006                           34.50                   55.21
    -------------------------------------------------------------------------

    RESERVE LIFE INDEX

    The Trust's reserve life index ("RLI") using annualized fourth quarter
production is 7.0 years proved (2006 - 7.3 years) and 9.8 years proved plus
probable (2006 - 9.8 years).

                                    2007        2007        2006        2006
                                   Using       Using       Using       Using
                              Annualized    2008 GLJ  Annualized    2007 GLJ
                                      Q4    Forecast          Q4    Forecast
                              Production  Production  Production  Production
    -------------------------------------------------------------------------
    Production (mmboe)             8.872       9.537       6.592       7.091
    Proved reserves (mmboe)         61.7        61.7        48.2        48.2
    Proved RLI (years)               7.0         6.5         7.3         6.8
    Production (mmboe)             8.872      10.088       6.592       7.641
    Proved plus probable
     reserves (mmboe)               86.8        86.8        64.9        64.9
    Proved Plus Probable RLI
     (years)                         9.8         8.6         9.8         8.5
    -------------------------------------------------------------------------

    RESERVE REPLACEMENT

    The Trust's 2007 capital program replaced production by a factor of
2.6 times on a proved basis (2006 - 1.4 times) and 3.6 times on a proved plus
probable basis (2006 - 1.9 times). Reserve growth in 2007 was achieved through
both acquisitions and the drill bit. Reserve growth in 2006 was achieved
entirely through the drill bit.

                                                            2007        2006
    -------------------------------------------------------------------------
    Production (mmboe)                                      8.41        6.52
    Proved reserve additions (mmboe)                       21.92        8.78
    Proved placement ratio                                   2.6         1.4
    Proved plus probable reserve additions (mmboe)         30.34       12.48
    Proved plus probable replacement ratio                   3.6         1.9
    -------------------------------------------------------------------------

    RECYCLE RATIO

    The recycle ratio is a measure for evaluating the effectiveness of a
company's reinvestment program. It accomplishes this by comparing the
operating netback per boe to that year's reserve FD&A costs.

                                                            2007        2006
    -------------------------------------------------------------------------
    Operating netback ($/boe)                              29.11       32.28
    Proved FD&A costs after revisions of prior periods
     and including the change in future development
     costs ($/boe)                                         22.10       16.20
    Proved recycle ratio                                     1.3         2.0
    Proved plus probable FD&A costs after revisions of
     prior periods and including the change in future
     development costs ($/boe)                             16.67       12.39
    Proved plus probable recycle ratio                       1.7         2.6
    -------------------------------------------------------------------------
    

    AFTER TAX NET ASSET VALUE

    The Trust's after tax net asset value is measured with reference to the
present value of future estimated cash flows from reserves estimates prepared
by GLJ, the independent reserve engineers, and including undeveloped land,
seismic data, adjustments for working capital deficiency, bank debt,
convertible debentures and asset retirement obligations at year end. This
calculation can vary significantly depending on the natural gas and oil price
assumptions used by GLJ. This calculation does not represent a "going-concern"
value since it only assumes the reserves contained in the GLJ report.
    On October 25, 2007 the Alberta government announced the New Royalty
Framework ("framework") which is proposed to take effect on January 1, 2009.
The framework proposes a new simplified royalty formula for natural gas that
will operate on a sliding scale determined by commodity prices, well
productivity and drilling depth. The impact of the royalty increase is a
decrease to the net present value of the Trust's reserves by approximately one
to two percent when using a 10 percent discount rate and using GLJ forecast
prices as at January 1, 2008. The table below does not include the framework
as it has not become law.

    
    ($ millions, except per             Discounted at 8%   Discounted at 10%
     unit amounts)                        2007      2006      2007      2006
    -------------------------------------------------------------------------
    Proved plus probable reserve
     value(1)                            1,436     1,129     1,316     1,022
    Undeveloped acreage(2)                 137        81       137        81
    Seismic(3)                              55        36        55        36
    Working capital deficiency             (25)      (14)      (25)      (14)
    Bank debt                             (297)      (75)     (297)      (75)
    Convertible debentures                (122)     (120)     (122)     (120)
    Asset retirement obligations(4)        (27)      (17)      (24)      (15)
    -------------------------------------------------------------------------
    After tax net asset value            1,157     1,020     1,040       915
    -------------------------------------------------------------------------
    Total units outstanding and
     issuable for exchangeable
     shares (thousands)                110,781    88,114   110,781    88,114
    -------------------------------------------------------------------------
    After tax net asset value
     per unit                           $10.44    $11.58     $9.39    $10.38
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Reserve values are based on after tax estimates of future cash flows
        as evaluated by our independent qualified reserve evaluators using
        their future commodity price forecasts as presented above.
    (2) Based on internal estimate of market value considering recent sales
        of similar properties in the same general area.
    (3) Seismic inventory values are an internal estimate of replacement
        value.
    (4) Proved plus probable reserve value includes $8.1 million and
        $7.4 million for the 8% and 10% discounted values, respectively (2006
        - $6.9 and $5.7 million, respectively) for asset retirement
        obligations on wells with assigned reserves.
    

    MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A")

    The following discussion and analysis of financial results, dated
February 28, 2008, should be read in conjunction with Progress Energy Trust's
("Progress" or the "Trust") accompanying audited consolidated financial
statements and related notes for the years ended December 31, 2007 and 2006.
The financial data presented has been prepared in accordance with Canadian
generally accepted accounting principles ("GAAP"). The reporting and the
measurement currency is the Canadian dollar.

    Non-GAAP Measurements

    Management uses cash flow from operations (before changes in non-cash
working capital) ("cash flow") and diluted cash flow per unit to analyze
operating performance and leverage. Cash 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 for other entities. Cash
flow as presented is not intended to represent operating profit for the period
nor should it be viewed as an alternative to operating profit, net earnings or
other measures of financial performance calculated in accordance with Canadian
GAAP. The reconciliation between cash flow, as defined above, and cash flow
from operations after changes in non-cash working capital for the years ended
December 31, 2007 and 2006 is as follows:

    
    ($ thousands)                                           2007        2006
    -------------------------------------------------------------------------
    Cash flow (as defined above)                         214,290     190,329
    Changes in non-cash working capital                    6,139        (170)
    -------------------------------------------------------------------------
    Cash flow from operations after changes in
     working capital                                     220,429     190,159
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Management considers cash flow to be a key measure as it demonstrates the
Trust's ability to generate the cash necessary to pay distributions, repay
debt and to fund future capital investments. Cash flow is used by research
analysts to value and compare oil and gas trusts and is frequently included in
published research when providing investment recommendations. Cash flow per
unit is calculated using the diluted weighted average number of units for the
period. All references to cash flow throughout the MD&A are based on cash flow
before changes in non-cash working capital unless otherwise specified.
    Management uses certain industry benchmarks such as operating netback and
total debt to cash flow ratio to analyze financial and operating performance.
These benchmarks as presented do not have any standardized meaning prescribed
by Canadian GAAP and therefore may not be comparable with the calculation of
similar measures for other entities. Operating netback and total debt to cash
flow ratio are used by research analysts to compare operating performance and
a trust's ability to maintain current distributions. Operating netback is the
net result of the Trust's revenue net of realized gains and losses on
financial instruments, and royalty, operating and transportation expenses as
found in the accompanying consolidated financial statements. The total debt to
cash flow ratio is calculated by dividing total debt at the end of the period
(comprised of the working capital deficit, outstanding bank debt and the debt
portion of the Trust's convertible unsecured debentures) by the 12 month
trailing cash flow as defined above.

    Forward Looking Statements

    Certain information regarding Progress set forth in this document,
including Management's assessment of Progress' future plans and operations,
contains forward-looking statements that involve substantial known and unknown
risks and uncertainties. These forward-looking statements are subject to
numerous risks and uncertainties, certain of which are beyond Progress'
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 producers,
the lack of availability of qualified personnel or management, stock market
volatility and the ability to access sufficient capital from internal and
external sources. Progress' 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 so, what benefits that Progress will derive therefrom.

    DESCRIPTION OF BUSINESS

    Progress is an open-ended, unincorporated investment trust governed by
the laws of the province of Alberta. The principal undertaking of the Trust is
to indirectly explore for, develop and hold interests in petroleum and natural
gas properties. Progress Energy Ltd., a wholly owned subsidiary of Progress,
carries on the business of the Trust and directly owns the petroleum and
natural gas properties and assets related thereto. The Trust's unitholders and
exchangeable shareholders are the sole beneficiaries of the Trust. Under the
Trust Indenture, the Trust may declare payable to unitholders all or any part
of the income of the Trust which is primarily comprised of interest earned on
debt notes issued to Progress Energy Ltd., as well as, amounts attributed to a
net profits interest agreement entered into with Progress Energy Ltd. The
aggregate amounts received by the Trust each period are based on the
consolidated cash flow each period, as adjusted on a discretionary basis, for
cash withheld to fund capital expenditures.
    Progress is a Calgary based, natural gas focused, trust targeting
sustainable production and reserves per trust unit through utilization of its
technical capability and capital investment efficiencies. Primary operating
areas include the Deep Basin of northwest Alberta and the northeast British
Columbia Foothills and Fort St. John Plains regions. Trust units of Progress
trade on the Toronto Stock Exchange ("TSX") under the symbol PGX.UN.
Exchangeable shares and the 6.75 percent and 6.25 percent convertible
unsecured subordinated debentures (the "Debentures") of Progress trade on the
TSX under the symbols PGE, PGX.DB and PGX.DB.A, respectively.

    RELATIONSHIP WITH PROEX

    The Trust provides personnel and certain administrative and technical
services to ProEx Energy Ltd. ("ProEx") in connection with the management,
development, exploitation and operation of the assets of ProEx and the
marketing of its production. The Trust provides these services in accordance
with the technical services agreement ("Technical Services Agreement") entered
into with ProEx as described below. ProEx has granted stock options and shares
to employees and executives of Progress as service providers and has also
participated in a long term incentive plan by granting ProEx common shares to
employees of Progress, excluding the executives. To facilitate this plan,
during 2007, Progress purchased 173,789 ProEx common shares and has been
reimbursed by ProEx for the cost incurred. The ProEx common shares will be
held until the vesting date, two years from date of grant. Any forfeited
shares will revert back to ProEx.
    The Trust and ProEx have joint interest in certain properties and
undeveloped land in the northeast British Columbia Foothills and Fort St. John
Plains regions. These joint interest properties are governed by standard
industry agreements and in addition the Trust has entered into a protocol
arrangement ("Protocol Arrangement") with ProEx that specifies how each
company will manage the joint lands in specifically identified areas of
interest. To ensure good governance practices, both the Trust and ProEx have
each created independent committees of their Board of Directors to monitor
compliance with the Technical Services Agreement and the Protocol Arrangement.
    On April 2, 2007, Progress acquired all of the issued and outstanding
shares of a private company for $527.4 million, net of certain assets retained
by the vendor. In conjunction with the acquisition, on April 2, 2007, Progress
disposed of certain assets of the private company to ProEx for $134.4 million.
When considering the bid process for the acquisition, each of Progress and
ProEx identified assets that they were interested in acquiring and values that
they were willing to pay to acquire such assets. Progress made a single bid on
behalf of ProEx and Progress and the ultimate purchase price was based on the
prices that each of Progress and ProEx were willing to pay for the assets that
they had selected to acquire. The resale of assets from Progress to ProEx was
based on these allocations. The technical services committee reviewed the
details of the transaction prior to the purchase and sale agreement being
signed. All lands are managed in accordance with the Protocol Arrangement.
    On November 30, 2007, Progress and ProEx jointly acquired certain assets
in the Foothills region of British Columbia. The total cost of the acquisition
of $17.9 million was split in accordance with working interests currently held
in the surrounding area. As a result, Progress acquired a 20 percent interest
in the assets ($3.6 million) and ProEx an 80 percent interest ($14.3 million).

    Technical Services Agreement

    The Technical Services Agreement has no set termination date and will
continue until terminated by either party with one year prior written notice
to the other party or some other date as mutually agreed. The Trust provides
services including management, development, exploitation, operations,
administrative, and marketing, as well as, information technology systems to
ProEx on an expense reimbursement basis, based on ProEx's monthly capital
activity and production levels relative to the combined capital activity and
production levels of both the Trust and ProEx.

    Protocol Arrangement

    The Protocol Arrangement identifies methods and processes to be followed
on both existing and new lands, joint facilities, marketing, seismic and
surface rights. The Protocol Arrangement also outlines the practices to be
followed in the event either party enters into areas outside of the identified
areas of interest.

    CORPORATE ACQUISITION

    On April 2, 2007, Progress acquired all of the issued and outstanding
shares of a private company for $527.4 million, net of certain assets retained
by the vendor ("Corporate Acquisition"). In conjunction with the Corporate
Acquisition, on April 2, 2007, Progress disposed of certain assets of the
private company to ProEx for $134.4 million. The resulting net cash
consideration of $393.0 million was financed by the issuance of 21,000,000
trust units at a price of $12.00 per trust unit for proceeds of $252.0 million
($238.7 million net of issue costs) and through increased bank debt. Included
in the Corporate Acquisition was approximately $720.9 million of tax pools
which are available to Progress to shelter future taxable income resulting in
the recognition of a $137.2 million future income tax asset.
    The Corporate Acquisition included approximately 6,400 boe per day of
production, 95 percent natural gas and approximately 240,000 net acres of
undeveloped land.

    OPERATING SUMMARY

    In accordance with Canadian industry practice, production volumes,
reserve volumes and revenues are reported on a Trust interest basis (working
interest plus royalty interest), before deduction of crown and other
royalties, unless otherwise indicated. The Trust's results of operations are
dependent on production volumes of natural gas, crude oil and natural gas
liquids and the prices received for this production. Prices for these
commodities have shown significant volatility during recent years and are
determined by supply and demand factors, including weather and general
economic conditions and changes in the Canadian/United States currency
exchange rate.
    In this MD&A, production and reserves information may be presented on a
"barrel of oil equivalent" or "boe" basis with six thousand cubic feet ("mcf")
of natural gas being equivalent to one barrel ("bbl") of crude oil or natural
gas liquids. Boe's may be misleading, particularly if used in isolation. A boe
conversion ratio of 6 mcf:1 bbl is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a value
equivalency at the well-head.

    
    Production

                              Fourth    Fourth
                             Quarter   Quarter
                             of 2007   of 2006      2007      2006    Change
    -------------------------------------------------------------------------
    Daily Production
    Natural gas (mcf/d)      123,740    88,568   116,630    85,749       36%
    Crude oil (bbls/d)         2,068     2,030     2,147     2,196      (2)%
    Natural gas liquids
     (bbls/d)                  1,548     1,269     1,446     1,366        6%
    -------------------------------------------------------------------------
    Total daily production
     (boe/d)                  24,240    18,060    23,031    17,853       29%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Natural gas as a %
     of total production         85%       82%       84%       80%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Production in 2007 averaged 23,031 boe per day consisting of 116,630 mcf
per day of natural gas, 2,147 bbls per day of crude oil and 1,446 bbls per day
of natural gas liquids. This production was 29 percent higher than 2006 with
production averaging 17,853 boe per day due to the Corporate Acquisition and
successful drilling results. Production for 2007 was within Management's
expectations for the year and the assets acquired through the Corporate
Acquisition are performing as expected. The Trust replaced 361 percent of
production on a proved plus probable basis, resulting in a finding,
development and acquisition cost of $16.67 per proved plus probable boe. The
Trust's production portfolio in 2007 was weighted 84 percent to natural gas,
10 percent to crude oil and six percent to natural gas liquids.
    Natural gas production increased 36 percent in 2007 to 116,630 mcf per
day compared to 85,749 mcf per day in 2006. The increase was due to the
Corporate Acquisition as well as, successful drilling results in late 2006 and
through 2007 in Progress' core regions. Production in the last half of 2007
was hampered by wet field conditions which delayed drilling and tie-in work.
The 2006 natural gas production was negatively impacted by scheduled plant
maintenance turnarounds in several areas including Karr, Gold Creek-Dunes, Two
Creek, Strachan and Gilby in Alberta and the Fort Nelson gas processing
facility in British Columbia.
    Crude oil and natural gas liquids production in 2007 of 3,593 bbls per
day was slightly higher than 2006 of 3,562 bbls per day.
    The Trust's 2007 fourth quarter production averaged 24,240 boe per day,
comprised of 123,740 mcf per day of natural gas, 2,068 bbls per day of crude
oil and 1,548 bbls per day of natural gas liquids. This was higher than the
fourth quarter of 2006 which averaged 18,060 boe per day, comprised of 88,568
mcf per day of natural gas, 2,030 bbls per day of crude oil and 1,269 bbls per
day of natural gas liquids. The difference was due to the Corporate
Acquisition and successful drilling. For a full analysis of fourth quarter
production refer to the Fourth Quarter Analysis section in this MD&A.
    Progress' December 2007 production averaged approximately 25,000 boe per
day and Management anticipates production to average approximately 23,500 boe
per day in 2008 dependent on the actual capital invested. This forecast is
inclusive of a major turnaround at the McMahon gas plant in northeast British
Columbia that is scheduled in June 2008, and natural reservoir declines.
Capital investment in 2008 is forecasted to be between $110 million to
$125 million.

    
    Production by Region

                         Fourth   Fourth
                        Quarter  Quarter
    (boe/d)                2007     2006   Change     2007     2006   Change
    -------------------------------------------------------------------------
    Foothills             6,434    3,769      71%    5,814    3,690      58%
    Fort St. John
     Plains               1,949    2,118     (8)%    1,993    2,098     (5)%
    Deep Basin - Ojay       989        -               782        -
    Other                   285      348    (18)%      319      369    (14)%
    -------------------------------------------------------------------------
    Total British
     Columbia             9,657    6,235      55%    8,908    6,157      45%
    -------------------------------------------------------------------------

    Deep Basin           12,030    9,099      32%   11,412    8,825      29%
    Central Alberta       1,706    1,714       -%    1,840    1,742       6%
    Other                   621      736    (16)%      630      803    (22)%
    -------------------------------------------------------------------------
    Total Alberta        14,357   11,549      24%   13,882   11,370      22%
    -------------------------------------------------------------------------

    Saskatchewan            226      276    (18)%      241      326    (26)%
    -------------------------------------------------------------------------
    Total daily
     production          24,240   18,060      34%   23,031   17,853      29%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Pricing and Risk Management


    Natural Gas Markets

    Progress' realized natural gas price for the year ended December 31, 2007
was $6.85 per mcf (2006 - $7.19 per mcf) compared to the Canadian Alberta
Energy Company interconnect with the TransCanada Alberta system ("AECO") daily
index average of $6.11 per gigajoule ("gj") and the AECO monthly index average
of $6.27 per gj (2006 - $6.17 per gj and $6.62 per gj, respectively). Progress
markets its natural gas at a mix of daily and monthly pricing.
    The first quarter of 2007 began with moderate weather and weak demand for
natural gas. However, mid January brought unexpected winter storms and colder
than normal weather across Canada and the northeastern United States ("US").
The resulting demand for natural gas created some of the largest monthly
storage withdrawals in several years as supplies shrank below the benchmark
5 year average and recovered from the high levels reached in the fall of 2006.
By the end of February, AECO gas prices had traded at the highest point they
would see for the rest of 2007. The second quarter was typical of any shoulder
season as moderate weather throughout most of the continent created minimal
gas demand for either heating or cooling. Market pricing remained relatively
flat while gas demand to re-fill storage absorbed any lower priced excess
supply. Moderate weather throughout a majority of North America created
minimal demand for natural gas during the third quarter. The supply situation
was further compounded by the addition of substantial liquefied natural gas
("LNG") import volumes. The resulting situation created a buyers market for
natural gas storage purchasers as they bought significant volumes in order to
benefit from the declining prices of the over-supplied market. Gas prices
continued to suffer from bearish fundamentals through October as warmer than
normal weather and record high storage volumes created significant downward
pressure. Crude oil prices which had steadily increased during the year jumped
to new highs which provided price support to natural gas through the increased
price of heating oil. Winter weather forecasts calling for colder than normal
temperatures initially supported gas prices until those same forecasts were
revised for warmer temperatures early in November. The week ending
November 8th saw storage hit a total of 3.545 Tcf for a new all-time high
which market analysts expected to be sufficient to cover any likely winter gas
demand scenario. Late November saw cold weather move into the northeastern US
which had previously been forecast to warm through December. However, as the
days passed, the forecast warming trend continued to be deferred but never
actually occurred in December. The resulting storage withdrawals during
December eliminated a sizable portion of the year over year surplus and
statistically placed the December 2007 storage total well within the 5 year
average band.
    Even though high storage volumes and the resulting oversupply of natural
gas weighed heavily on prices through the year, prices for 2007 averaged
US$6.91 per million btu for the New York Mercantile Exchange ("NYMEX") and
$6.11 per gj at AECO.

    Oil

    Although crude oil prices have achieved record highs throughout 2007
peaking at US$95.58 per barrel and averaging US $72.24 per barrel for the full
year, the strengthening of the Canadian dollar relative to the US dollar was
responsible for eroding most of the gains and negatively impacted the price of
crude oil in Canadian dollar terms. Progress' realized prices for its liquids
streams for the year ended December 31, 2007 were $72.86 per bbl (2006 -
$67.88 per bbl) for crude oil and $62.77 per bbl (2006 - $62.65 per bbl) for
natural gas liquids.
    Looking toward 2008, we anticipate WTI oil prices will average within the
US$80.00 to US$90.00 per bbl range and AECO natural gas to average between
$7.00 to $7.50 per gj with the Canadian/US exchange rate trading at par.
Progress produces predominantly light oil and high heat content liquids rich
natural gas that attract premium market prices.

    
    Commodity Prices

                                                2007        2006      Change
    -------------------------------------------------------------------------
    Average Benchmark Prices
    Natural gas - AECO (daily) ($/gj)           6.11        6.17        (1)%
    Natural gas - AECO (monthly) ($/gj)         6.27        6.62        (5)%
    Natural gas - Station No.2 (daily) ($/gj)   6.05        5.90          3%
    Crude oil - WTI (US$/bbl)                  72.24       66.22          9%
    Crude oil - Edmonton par price (Cdn$/bbl)  76.06       72.74          5%
    Exchange rate - (US$/Cdn$)                1.0740      1.1343        (5)%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Average Realized Prices
    -------------------------------------------------------------------------
    Natural gas ($/mcf)                         6.85        7.19        (5)%
    Crude oil ($/bbl)                          72.86       67.88          7%
    Natural gas liquids ($/bbl)                62.77       62.65          -%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Natural Gas Pricing

    US natural gas prices are typically referenced off NYMEX at Henry Hub,
Louisiana while Alberta natural gas is referenced off the AECO Hub and British
Columbia natural gas off of Sumas Washington or Station No.2 market centers.
Virtually all of Progress' natural gas is sold at market prices at one of the
Alberta or British Columbia hubs. Progress typically sells 50 percent of its
natural gas production on monthly indexes and 50 percent on daily indexes.

    Natural Gas Production and Prices by Province

                                             2007                2006
    -------------------------------------------------------------------------
                                         mcf/d     $/mcf     mcf/d     $/mcf
    -------------------------------------------------------------------------
    Alberta                             69,419      7.02    54,268      7.32
    British Columbia                    46,992      6.62    30,882      6.98
    Saskatchewan                           219      5.37       599      6.47
    -------------------------------------------------------------------------
    Total production and
     average sales price               116,630      6.85    85,749      7.19
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Alberta Natural Gas Prices

                                                            2007        2006
    -------------------------------------------------------------------------
    NYMEX (US$/mmbtu 12 month average - last 3 days)        6.91        7.26
    Less: AECO basis differential to Henry Hub (US$/mmbtu) (0.91)      (1.52)
    -------------------------------------------------------------------------
    AECO (US$/mmbtu)                                        6.00        5.74
    Average exchange rate                                 1.0740      1.1343
    -------------------------------------------------------------------------
    AECO price (Cdn$/mmbtu daily average)                   6.44        6.51
    Premium: Progress realized price vs spot(1)             0.58        0.81
    -------------------------------------------------------------------------
    Progress average realized Alberta price (Cdn$/mcf)      7.02        7.32
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Includes the conversion of mmbtu's to mcf.



    British Columbia Natural Gas Prices

                                                            2007        2006
    -------------------------------------------------------------------------
    NYMEX (US$/mmbtu 12 month average - last 3 Days)        6.91        7.26
    Less: Station No.2 basis differential
     to Henry Hub (US$/mmbtu)                              (0.97)      (1.78)
    -------------------------------------------------------------------------
    Station No.2 (US$/mmbtu)                                5.94        5.48
    Average exchange rate                                 1.0740      1.1343
    -------------------------------------------------------------------------
    Station No.2 price (Cdn$/ mmbtu daily average)          6.38        6.22
    Premium: Progress realized price vs. spot(1)            0.24        0.76
    -------------------------------------------------------------------------
    Progress average realized British Columbia
     price (Cdn$/mcf)                                       6.62        6.98
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Includes the conversion of mmbtu's to mcf.
    

    Price Risk Management

    The Trust has entered into several natural gas financial contracts for
the purpose of protecting its cash flow from the volatility of natural gas
prices. For the year ended December 31, 2007, the Trust's natural gas price
risk management program had a net realized gain of $16.1 million (2006 -
$29.9 million).
    On January 1, 2007 the Trust adopted the new accounting standards
regarding the accounting for financial instruments. In addition to the
adoption of the new standards, Management elected not to use hedge accounting
and therefore, records the fair value of its natural gas financial contracts
at each reporting period with the change in the fair value being classified as
unrealized gains or losses on the statement of earnings. The accounting for
hedging relationships for prior fiscal periods are not retroactively changed,
therefore, there was no restatement of the financial position or results of
operation as at and for the year ended December 31, 2006.
    On January 1, 2007 the fair value of the commodity price contracts was an
asset of $15.6 million and resulted in an increase to accumulated other
comprehensive income and the future income tax liability of $10.5 million and
$5.1 million, respectively. The $10.5 million recognized in accumulated other
comprehensive income was amortized over the term of the contracts through
other comprehensive income with a corresponding unrealized gain on financial
instruments on the statement of earnings. As a result, for the year ended
December 31, 2007 $10.5 million, net of tax, was charged to other
comprehensive income with a corresponding unrealized gain on financial
instruments of $15.6 million and a charge to future income tax expense of
$5.1 million. The unrealized gain of $15.6 million was offset by the change in
fair value of the commodity price contracts from January 1, 2007 of
$15.6 million resulting in a net unrealized gain of nil for 2007.
    The Trust's hedging activities are conducted pursuant to the Trust's Risk
Management Policy approved by the Board of Directors. The Risk Management
Policy has the following objectives:

    
    -   To reduce risk exposure to budgeted annual cash flow projections
        resulting from uncertainty or changes in commodity prices, interest
        rates or foreign exchange.
    -   To provide greater certainty and stability to monthly distributions.
    -   To limit the permissible structures to ensure hedging effectiveness.
    -   To limit hedging up to a maximum of 50 percent of budgeted production
        before royalties.
    -   To limit hedging activity to counter-parties that provide sufficient
        collateral in support of payment or have investment grade credit
        ratings.

    There were no natural gas financial instruments outstanding as at December
31, 2007. Subsequent to December 31, 2007 Progress entered into several
derivative financial instruments for the following production volumes:

    Financial Price               Contract Natural Gas     % of Estimated of
    Risk Management                 Volumes ('000 gj/d)           Production
    -------------------------------------------------------------------------
    First quarter of 2008                            -                     -
    Second quarter of 2008                          80                    50
    Third quarter 2008                              80                    50
    Fourth quarter 2008                             27                    17
    -------------------------------------------------------------------------

    Sensitivities

    The Trust's risk management program will reduce, but not eliminate, the
effects of changing commodity prices and interest rates and as a result cash
flow remains sensitive to these changes as demonstrated by the following
table:

                                                  Estimated Effect on 2008(1)
    ($ thousands)                                   Cash Flow per Trust Unit
    -------------------------------------------------------------------------
    Change of $0.25 per mcf in the price of natural gas                8,300
    Change of $5.00 per barrel in the price of crude oil               3,500
    Change of 5,000 mcf/d in natural gas production                    9,500
    Change of 500 bbls/d in crude oil production                      10,900
    Change of 1% in prime interest rates                               3,250
    -------------------------------------------------------------------------
    (1) These sensitivities reflect all commodity contracts as described in
        Note 11 of the consolidated financial statements. They apply to
        prices, production, and interest rates within the context of current
        market rates. The sensitivities above will no longer apply above the
        ceiling or below the floor price limits set by existing natural gas
        financial contracts.

    Revenue

    Petroleum and natural gas revenue increased 23 percent to $382.1 million
in 2007 from $310.5 million in 2006 mainly due to higher natural gas
production as a result of the Corporate Acquisition and successful drilling.
Production averaged 23,031 boe per day in 2007 compared to 17,853 boe per day
in 2006 while realized commodity prices decreased five percent to $45.45 per
boe in 2007 from $47.66 per boe in 2006. Petroleum and natural gas revenue in
2007 consisted of $291.3 million from natural gas sales, $57.1 million from
crude oil sales and $33.1 million from the sale of natural gas liquids.

    ($ thousands)                               2007        2006      Change
    -------------------------------------------------------------------------
    Natural gas sales                        291,830     224,892         30%
    Crude oil sales                           57,096      54,402          5%
    Natural gas liquids sales                 33,126      31,224          6%
    -------------------------------------------------------------------------
    Petroleum and natural gas revenue        382,052     310,518         23%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

                                                       Crude Oil
    ($ thousands)                        Natural Gas      & NGLs       Total
    -------------------------------------------------------------------------
    2006 Petroleum and natural gas revenue   224,892      85,626     310,518
    Price variance                           (14,053)      3,851     (10,202)
    Production variance                       80,991         745      81,736
    -------------------------------------------------------------------------
    2007 Petroleum and natural gas revenue   291,830      90,222     382,052
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Royalties

    Royalty expense consists of royalties paid to provincial governments,
freehold landowners and overriding royalty owners. Effective for 2007, the
Alberta government eliminated the Alberta royalty tax credit program. The
impact to Progress was an increase to royalty expense for the year ended
December 31, 2007 of $0.5 million.
    Royalties increased seven percent to $84.4 million in 2007 from
$78.8 million in 2006 due to higher revenues, as a result of higher
production. The Trust's average royalty rate in 2007 was 22.1 percent compared
to 25.4 percent in 2006. The decrease in the royalty rate is due to lower
royalty rates on the properties acquired in the Corporate Acquisition, as well
as, the acquired properties included wells in which Progress paid gross over
riding royalties.
    On October 25, 2007 the Alberta government announced the New Royalty
Framework ("framework"), which is proposed to take effect on January 1, 2009.
Progress has reviewed the information currently provided by the government and
believes that the changes to Alberta royalties may increase Progress' Alberta
royalty rate from 27 percent to 31.5 percent based on current production and a
realized natural gas price of $7.00 per gj. Using the same production and
price assumptions, Progress' royalty rate is estimated to increase marginally
from 25 percent to 27.5 percent, on a corporate basis, resulting in an
approximate five percent reduction in 2009 cash flow.
    The framework proposes a new simplified royalty formula for natural gas
that will operate on a sliding scale determined by commodity prices, well
productivity and drilling depth. Progress' Deep Basin well depths range
between 2,300 to 2,700 meters which will be eligible for the new measured
depth drilling formula. Progress is attracted to the Deep Basin region because
of the quality and pedigree of the region with its higher than average well
productivity and multi zone drilling targets. The new royalty formula will
increase Progress' royalties payable but is not expected to materially impact
the economics of drilling in the Deep Basin. However, Progress does have the
opportunity to shift its capital investment program into British Columbia. In
2007 61 percent of Progress' revenue was from the province of Alberta, down
from 64 percent in 2006 due to Progress' growing British Columbia Foothills
production.

    
    ($ thousands)                                           2007        2006
    -------------------------------------------------------------------------
    Crown                                                 72,880      64,544
    Freehold and overriding                               11,554      14,218
    -------------------------------------------------------------------------
    Total royalty expense                                 84,434      78,762
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Royalties ($/boe)                                      10.04       12.09
    Average royalty rate (%)                                22.1        25.4
    -------------------------------------------------------------------------



    The following table provides a
     break down of royalties by product:
    ($ thousands)                                           2007        2006
    -------------------------------------------------------------------------
    Natural gas royalties                                 63,944      56,945
    $/boe                                                   9.02       10.92
    Average natural gas royalty rate (%)                    21.9        25.4

    Crude oil royalties                                   10,733      12,856
    $/boe                                                  13.70       16.04
    Average crude oil royalty rate (%)                      18.8        23.6

    Natural gas liquids royalties                          9,757       8,961
    $/boe                                                  18.49       17.97
    Average natural gas liquids royalty rate (%)            29.5        28.7
    -------------------------------------------------------------------------
    

    Management anticipates, based on current commodity prices that the
average royalty rate for 2008 will be approximately 23 to 24 percent of
petroleum and natural gas revenue.

    Operating Expenses

    Operating expenses increased 33 percent to $53.7 million in 2007 compared
to $40.4 million in 2006. The increase is the result of higher production in
2007 compared to 2006, reflecting the impact of the Corporate Acquisition and
successful drilling. On a boe basis, operating expenses for 2007 increased
three percent to $6.38 from $6.19 in 2006. The operating expense per boe
trended downwards in late 2007 as a result of benefits realized from
optimizing the acquired assets. Progress has experienced increased costs for
well servicing, insurance, workovers and well maintenance. Through increased
operating efficiencies and the addition of low operating cost per boe
production, the Trust has been able to offset a large portion of these
increases and keep operating costs per boe low. Management anticipates
continuing this trend and forecasts operating expenses for 2008 to be between
$6.50 to $6.75 per boe.

    
    ($ thousands)                               2007        2006      Change
    -------------------------------------------------------------------------
    Operating expenses - total                53,661      40,353
    $/boe                                       6.38        6.19          3%

    Operating expenses - natural gas
     properties                               43,524      31,381
    $/boe                                       5.79        5.62          3%

    Operating expenses - crude oil
     properties                               10,137       8,972
    $/boe                                      11.37        9.61         18%
    -------------------------------------------------------------------------

    Transportation Expenses

    Transportation expenses increased 40 percent to $15.4 million in 2007
compared to $11.0 million in 2006. The increase is due to higher production in
2007 compared to 2006. On a boe basis, transportation expenses in 2007
increased eight percent to $1.83 compared to $1.69 in 2006. The increase is
due to higher transportation and treatment tolls associated with the Corporate
Acquisition including higher treatment tolls associated with the Slave Point
production at the Bubbles property in the Foothills region. In British
Columbia, there is an infrastructure owned by Spectra Energy that enables gas
producers to avoid facility construction in exchange for gathering, processing
and transmission fees. This all-in charge is included in transportation
expenses.

    Operating Netbacks

    Although many wells produce both crude oil and natural gas, a well is
categorized as a natural gas well or an oil well based upon the higher
proportion of natural gas or crude oil production. The following table
summarizes the operating netbacks for natural gas properties, oil properties
and all properties combined:

                                                            2007        2006
    -------------------------------------------------------------------------
    Natural Gas Properties ($/mcf)
    -------------------------------------------------------------------------
    Sales Price                                             7.16        7.53
    Realized gain on financial instruments                  0.37        0.89
    Royalties                                              (1.61)      (1.94)
    Operating expenses                                     (0.95)      (0.94)
    Transportation expenses                                (0.30)      (0.28)
    -------------------------------------------------------------------------
    Operating netback - natural gas properties              4.67        5.26
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Oil Properties ($/bbl)
    -------------------------------------------------------------------------
    Sales Price                                            66.40       62.62
    Royalties                                             (13.48)     (14.74)
    Operating expenses                                    (11.37)      (9.61)
    Transportation expenses                                (1.93)      (1.89)
    -------------------------------------------------------------------------
    Operating netback - oil properties                     39.62       36.38
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    All Properties ($/boe)
    -------------------------------------------------------------------------
    Sales Price                                            45.45       47.66
    Realized gain on financial instruments                  1.91        4.59
    Royalties                                             (10.04)     (12.09)
    Operating expenses                                     (6.38)      (6.19)
    Transportation expenses                                (1.83)      (1.69)
    -------------------------------------------------------------------------
    Operating netback - all properties                     29.11       32.28
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    General and Administrative Expenses

    General and administrative expenses net of overhead recoveries on operated
properties, ("G&A") increased 39 percent to $8.8 million ($1.04 per boe) in
2007 compared to $6.3 million ($0.97 per boe) in 2006. The increase in G&A for
the year over 2006 is due to the increased size of the Trust, as well as
higher costs incurred to retain employees.

    ($ thousands)                                           2007        2006
    -------------------------------------------------------------------------
    Gross G&A                                             20,934      16,171
    Technical Services Fees from ProEx                    (6,248)     (4,484)
    Operator recoveries                                   (4,418)     (4,132)
    Capitalized expenses                                  (1,512)     (1,234)
    -------------------------------------------------------------------------
    Total G&A expense                                      8,756       6,321
    -------------------------------------------------------------------------
    G&A ($/boe)                                             1.04        0.97
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    In accordance with the Technical Services Agreement with ProEx, the Trust
provides personnel and certain administrative and technical services in
connection with the management, development, exploitation and operation of the
assets of ProEx and the marketing of its production. The Trust provides these
services to ProEx on an expense reimbursement basis, based on ProEx's monthly
capital activity and production levels relative to the combined capital
activity and production levels of both the Trust and ProEx. Total expenses
reimbursed by ProEx in 2007 were $6.2 million compared to $4.5 million in
2006.
    The magnitude of operator recoveries is a function of activity levels and
the degree to which operations are operated by the Trust. Progress operates
79 percent of its production and operates the majority of the drilling and
construction activity. Operator recoveries were $4.4 million for 2007 compared
to $4.1 million in 2006, the increase being a result of operated wells
acquired during 2007.
    The Trust capitalized approximately $1.5 million of G&A in 2007 and
$1.2 million in 2006. The majority of these costs represent geological and
geophysical employee compensation.
    Management anticipates G&A expense to remain consistent with 2007 and
average in the range of $1.00 to $1.10 per boe in 2008.

    Unit Based Compensation Expenses

    The Trust's Performance Unit Incentive Plan (the "Plan") provides for
employees and directors to be granted performance units by the Board of
Directors of Progress Energy Ltd. from time to time at its sole discretion.
The Plan was modified in 2007 to include a new long term incentive component
("LTI component") for non-executive employees.

    Performance Units

    The performance units will vest on the third anniversary of the date of
grant and actual payment will be determined based on the performance of the
Trust relative to its peers. Performance factors range from 0.5 to 1.5 times
the initial performance units granted except for performance units granted to
the Trust's executives in 2007 which can range from 0 to 3 times. Over the
three year term the performance units will attract distributions. The Trust
expects to pay out the distribution portion in cash while the units earned
will be issued from treasury.

    Long Term Incentive Component

    Awards granted under the LTI component of the Plan will vest over three
years with 40 percent vesting on the second anniversary of the date of grant
and 60 percent vesting on the third anniversary of the date of grant. An
additional 15 percent grant will be paid if the holder holds the units
received on the second anniversary date for one additional year. As at
December 31, 2007, 189,485 units are outstanding under the LTI component at an
average value of $14.00 per unit, resulting in a total compensation cost of
$2.7 million of which $2.3 million will be recognized through unit based
compensation expense and $0.4 million will be capitalized over the vesting
period.
    On June 28, 2007 381,367 units were issued to settle the performance
units that vested on July 2, 2007, resulting in $5.1 million being transferred
from contributed surplus to unitholders' capital.
    As at December 31, 2007 there are 481,800 performance units outstanding
that were granted in 2005. During 2007 the estimated performance factor for
this grant was increased from 1.0 to 1.5 based on the Trust's operating
performance. The fair value of the performance units using a performance
factor of 1.5 is approximately $10.9 million of which $9.6 million will be
amortized through unit based compensation expense and $1.3 million will be
capitalized over the vesting period with a corresponding increase to
contributed surplus. Actual performance factors will not be determined until
the end of the performance period.
    As at December 31, 2007 there are 401,850 performance units outstanding
that were granted in 2006. During 2007 the estimated performance factor for
this grant was increased from 1.0 to 1.5 based on the Trust's operating
performance. The fair value of the performance units using a performance
factor of 1.5 is approximately $9.1 million of which $8.0 million will be
amortized through unit based compensation expense and $1.1 million will be
capitalized over the vesting period with a corresponding increase to
contributed surplus. Actual performance factors will not be determined until
the end of the performance period.
    As at December 31, 2007 there are 504,550 performance units outstanding
that were granted in 2007. The fair value of the performance units using a
performance factor of 1.0 is approximately $6.5 million of which $5.8 million
will be amortized through unit based compensation expense and $0.7 million
will be capitalized over the vesting period with a corresponding increase to
contributed surplus.
    For the year ended December 31, 2007 unit based compensation expense
increased 85 percent to $9.0 million ($1.08 per boe) compared to $4.9 million
($0.75 per boe) in 2006. In 2007, $1.9 million of unit based compensation was
capitalized compared to $0.8 million in 2006. The increase is due to the
performance units and LTI component units granted in 2007, as well as an
increase in the performance factor during 2007 from 1.0 to 1.5 on the
performance units vesting in 2008 and 2009 due to the Trust's strong operating
performance relative to its peers. Actual performance factors will not be
determined until the end of the three year performance periods.
    Management anticipates unit based compensation expenses will average
approximately $1.10 per boe in 2008.

    
                                                            2007        2006
    -------------------------------------------------------------------------
    Performance Units
    Balance, beginning of year                         1,300,717     899,567
    Granted                                              521,450     424,950
    Settled                                             (381,367)          -
    Forfeited                                            (52,600)    (23,800)
    -------------------------------------------------------------------------
    Balance, end of year                               1,388,200   1,300,717
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Vesting Date
    2007                                                       -     380,567
    2008(1)                                              481,800     512,300
    2009(1)                                              401,850     407,850
    2010                                                 504,550           -
    -------------------------------------------------------------------------
    Total                                              1,388,200   1,300,717
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Using the current anticipated performance factor of 1.5 times,
        722,700 units and 602,775 units, respectively, will be issued on the
        vesting of the 2005 and 2006 performance units in 2008 and 2009.



                                                            2007        2006
    -------------------------------------------------------------------------
    Units under LTI Component
    Balance, beginning of year                                 -           -
    Granted                                              198,629           -
    Forfeited                                             (9,144)          -
    -------------------------------------------------------------------------
    Balance, end of year                                 189,485           -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Vesting Date
    2009                                                  75,794           -
    2010                                                 113,691           -
    -------------------------------------------------------------------------
    Total(1)                                             189,485           -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) If the units vesting in 2009 are held by the LTI holder until 2010,
        one year past the date of vesting, an additional 28,423 units will be
        issued by the Trust.

    Interest and Financing Expenses

    Interest and financing expenses in 2007 increased 95 percent to
$23.0 million compared to $11.8 million in 2006. The increase is due to the
increase in bank debt to fund a portion of the Corporate Acquisition and
capital expenditures during 2007, as well as the issuance of the 6.25 percent
convertible unsecured subordinated debentures in August of 2006.
    Debenture interest, accretion and amortized issue costs relate to two
debenture issues; the 6.75 percent debentures issued on February 2, 2005 and
the 6.25 percent debentures issued on August 22, 2006 (the "Debentures"). For
more information regarding the Debentures, see the "Liquidity and Capital
Resources" section below.

    ($ thousands)                                           2007        2006
    -------------------------------------------------------------------------
    Interest on bank debt                                 11,997       4,406
    Interest on Debentures                                 8,449       5,803
    Amortization of Debenture issue costs                  1,116         717
    Accretion on debt portion of Debentures(1)             1,453         872
    -------------------------------------------------------------------------
    Total interest and financing expense                  23,015      11,798
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Interest and financing expense ($/boe)                  2.74        1.81
    Average bank debt outstanding                        219,562      86,622
    Average bank debt interest rate (%)                      5.5         5.1
    Average bank prime lending rate (%)                      6.1         5.8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Under Canadian GAAP, the fair value of the conversion feature of the
        Debentures is classified as equity and the remainder is classified as
        debt. Over the term of the Debentures, the debt portion will accrete
        up to the principal balance at maturity with the charge going to
        interest and financing expenses.

    Depletion, Depreciation and Accretion

    Depletion and depreciation of property, plant and equipment and the
accretion of the asset retirement obligations ("DD&A") increased 46 percent to
$138.6 million in 2007 compared to $94.7 million in 2006. This resulted in
DD&A per boe in 2007 of $16.49 compared to $14.53 recognized in 2006. The
increase is due to the Corporate Acquisition.

    ($ thousands)                                           2007        2006
    -------------------------------------------------------------------------
    Depletion                                            135,498      92,287
    Depreciation                                             722         671
    Accretion of asset retirement obligations              2,416       1,750
    -------------------------------------------------------------------------
    Total DD&A expense                                   138,636      94,708
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    DD&A ($/boe)                                           16.49       14.53
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Income and Capital Taxes

    In June, 2007 the federal government's bill regarding the taxation of
distributions from trusts beginning January 1, 2011 was enacted. As a result,
a recovery of $6.6 million was recognized in the future income tax provision
on the recognition of a $6.6 million future income tax asset in the Trust.
Previously, the future income tax liability on the consolidated balance sheet
represented only the future income tax liability of the Trust's subsidiary.
    As part of the government's bill, a growth limit was established for
existing trusts by limiting new equity issues to 40 percent of that trust's
October 31, 2006 market capitalization ("benchmark") for 2007, and an
additional 20 percent of the benchmark for each of 2008, 2009 and 2010. For
Progress, the growth limits are $476.8 million for 2007 (less $252.0 million
as a result of the equity offering in regards to the Corporate Acquisition)
and $238.4 million for each of 2008, 2009 and 2010 with any unused amount
rolling forward to the next year.
    The provision for future income taxes for 2007 was a recovery of
$14.9 million compared to a recovery of $14.7 million for 2006. The recovery
in 2007 was the result of lower earnings as well as the recognition of the
future income tax asset of the Trust of $6.6 million noted above. These were
partially offset by a charge of $2.3 million due to a reduction in future
federal and provincial tax rates that reduced the value of Progress' future
tax asset. The substantial recovery in 2006 is due to a reduction in future
federal and provincial income tax rates enacted during that year.
    As a result of the Corporate Acquisition, Progress recognized a
$137.2 million future income tax asset for the difference between the
$720.9 million in tax pools acquired over the value assigned to the assets.
Progress' estimated tax pool balances as at December 31, 2007 total
approximately $1.2 billion.

    Non-Controlling Interest - Exchangeable Shares

    The exchangeable shares of the Trust's subsidiary trade on the TSX,
thereby allowing holders of the exchangeable shares to dispose of them without
having to exchange them for trust units and consequently, they must be
classified as non-controlling interest outside of unitholders' equity. The net
earnings attributable to the exchangeable shares is charged to the
consolidated statements of earnings as non-controlling interest expense with a
corresponding increase to non-controlling interest on the consolidated balance
sheet.
    The following details the non-controlling interest activity for the years
ended December 31, 2007 and 2006:

    
                                         2007                    2006
                              ----------------------- -----------------------
    Exchangeable shares
     ($ thousands, except
     unit amounts)                Number      Amount      Number      Amount
    -------------------------------------------------------------------------
    Balance, beginning
     of year                   9,642,540     122,592  11,388,751     127,205
    Exchanged for trust
     units                      (469,457)     (6,132) (1,746,211)    (20,130)
    Non-controlling
     interest expense                          9,924                  15,517
    -------------------------------------------------------------------------
    Balance, end of year       9,173,083     126,384   9,642,540     122,592
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    The charge to net earnings of $9.9 million for 2007 and $15.5 million for
2006 represents the net earnings attributable to the exchangeable shares.

    Net Earnings and Cash Flow

    Net earnings decreased 23 percent to $70.2 million in 2007 compared to
$91.6 million in 2006. Lower natural gas prices and higher DD&A expense in
2007 exceeded the impact of higher production as a result of the Corporate
Acquisition. Basic net earnings in 2007 were $0.76 per trust unit compared to
$1.23 per trust unit in 2006. Diluted net earnings in 2007 were $0.76 per
trust unit compared to $1.21 per trust unit in 2006.
    Other comprehensive income for 2007 includes a charge of $10.5 million
compared to nil for 2006 relating to the amortization of the amount recognized
in accumulated other comprehensive income on January 1, 2007 for the fair
value of financial instruments on adoption of the new accounting standards for
financial instruments (refer to Risk Management above). This resulted in total
comprehensive income for 2007 of $59.7 million compared to $91.6 million in
2006.
    Cash flow increased 13 percent to $214.3 million in 2007 compared to
$190.3 million in 2006 due to higher revenues as a result of the Corporate
Acquisition. Diluted cash flow in 2007 was $2.02 per trust unit compared to
$2.16 per trust unit in 2006.

    
    Quarterly Financial Summary(1),(2)

                                        Three Months Ended
                  -----------------------------------------------------------
    ($ thousands,     Dec   Sept    June    Mar    Dec   Sept   June     Mar
     except per        31     30      30     31     31     30     30      31
     unit amounts)   2007   2007    2007   2007   2006   2006   2006    2006
    -------------------------------------------------------------------------
    Petroleum and
     natural gas
     revenue       99,592 88,480 108,503 85,477 75,182 72,328 71,439  91,568
    -------------------------------------------------------------------------
    Cash flow      54,727 48,085  58,398 53,080 49,603 47,218 45,871  47,637
     Per unit
     diluted         0.49   0.43    0.53   0.60   0.56   0.54   0.52    0.55
    -------------------------------------------------------------------------
    Net earnings    9,922 11,909  31,947 16,425 21,538 20,252 28,425  21,383
      Per unit
       basic         0.10   0.12    0.33   0.22   0.29   0.27   0.38    0.29
      Per unit
       diluted       0.10   0.12    0.33   0.22   0.28   0.27   0.38    0.29
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Certain amounts above have been adjusted to conform to the
        presentation adopted in 2007 as a result of the adoption of the new
        accounting standards for financial instruments.
    (2) Petroleum and natural gas revenue and cash flow for second and third
        quarters of 2006 decreased as a result of lower natural gas prices.
        Petroleum and natural gas revenue and cash flow for the fourth
        quarter of 2006 and the first quarter of 2007 increased slightly due
        to strengthening natural gas prices. Net earnings for the first
        quarter of 2007 decreased due to an $8.2 million unrealized loss on
        financial instruments as a result of adopting the new accounting
        standards for financial instruments and electing not to use hedge
        accounting. Petroleum and natural gas revenue and cash flow increased
        in the second quarter of 2007 due to the Corporate Acquisition. For
        the third quarter of 2007, revenue, cash flow and net earnings
        decreased as a result of lower natural gas prices but increased for
        the fourth quarter of 2007 due to strengthening natural gas prices.
        Net earnings for the fourth quarter of 2007 includes a future income
        tax charge of $2.1 million due to a reduction in federal income tax
        rates.



    SELECTED ANNUAL INFORMATION

    ($ thousands, except per unit amounts)      2007        2006        2005
    -------------------------------------------------------------------------
    Petroleum and natural gas revenue        382,052     310,518     375,427
    Net earnings                              70,203      91,598      88,924
      Per unit basic                            0.76        1.23        1.29
      Per unit diluted                          0.76        1.21        1.27
    Cash flow                                214,290     190,329     205,977
      Per unit diluted                          2.02        2.16        2.45
    Total assets                           1,563,078   1,210,704   1,152,985
    Distributions declared                   114,142     125,563     116,460

    Working capital deficiency                25,459      14,835      22,873
    Bank debt                                296,590      75,000      71,326
    Convertible debentures                   122,174     119,605      79,381
    -------------------------------------------------------------------------
    Total debt                               444,223     209,440     173,580
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Distributions

    Management monitors the Trust's distribution payout policy with respect
to forecasted net cash flow, debt levels and capital expenditures. As a crude
oil and natural gas trust, Progress has a declining asset base and therefore
relies on ongoing development activities and acquisitions to replace
production and add additional reserves. Progress' future crude oil and natural
gas production and reserves are highly dependent on its success in exploiting
its asset base and acquiring additional reserves. The success of these
activities, along with natural gas prices are the main factors influencing the
sustainability of the Trust's distributions.
    Starting in January 2007, the Trust reduced its monthly distributions
from $0.14 per trust unit to $0.10 per trust unit due to a reduction in
forecasted 2007 cash flow as a result of the then current weakness in natural
gas prices. The distribution reduction reinforces Progress' commitment to
sustainability. Progress defines sustainability as maintaining production and
reserves per trust unit over an extended period of time. Progress'
sustainability objective is to annually retain sufficient cash flow to replace
reserves produced. As a result, $114.1 million was distributed in 2007
compared to $125.6 million in 2006. The distributions for 2007 include
$1.8 million relating to the performance units that vested on July 2, 2007.
    For the year ended December 31, 2007, cash flow from operating activities
(after changes in non-cash working capital) of $220.4 million exceeded cash
distributions of $114.1 million. This was consistent with 2006 in which cash
flow from operating activities (after changes in non-cash working capital) of
$190.2 million exceeded cash distributions of $125.6 million.
    For the year ended December 31, 2007, cash distributions of
$114.1 million exceeded net earnings of $70.2 million. This is consistent with
2006 in which cash distributions of $125.6 million exceeded net earnings of
$91.6 million. Net earnings includes significant non-cash charges which in
2007 were $144.8 million that do not impact cash flow. Net earnings also
include fluctuations in future income taxes due to changes in tax rates and
tax rules. In addition, other non-cash charges such as DD&A are not a good
proxy for the cost of maintaining our productive capacity given the natural
declines associated with crude oil and natural gas assets. In these instances,
where distributions exceed net earnings, a portion of the cash distribution
paid to unitholders may represent an economic return of the unitholders'
capital.
    For 2007, cash distributions and capital spending (excluding the
Corporate Acquisition and Wapiti asset purchase described below) combined
totaled $251.1 million, which was $30.7 million higher than the cash flow from
operating activities (after changes in non-cash working capital) of
$220.4 million. For 2006 cash distributions and capital spending exceeded the
cash flow from operating activities (after changes in non-cash working
capital) by $70.1 million in which monthly distributions were at the $0.14 per
unit level. Progress relies on access to capital markets to the extent cash
distributions and net capital expenditures exceed cash flow from operations
(after changes in non-cash working capital). Over the long term Progress
expects to fund distributions and capital expenditures with its cash flow,
however, it will continue to fund acquisitions and growth through additional
debt and equity. In the crude oil and natural gas sector, because of the
nature of reserve reporting, the natural reservoir declines and the risks
involved in capital investment, it is not possible to distinguish between
capital spent on maintaining productive capacity and capital spent on growth
opportunities. Therefore, maintenance capital is not disclosed separately from
development capital spending.
    On October 25, 2007 the Alberta government announced the New Royalty
Framework ("framework"), which is proposed to take effect on January 1, 2009.
Progress has reviewed the information currently provided by the government and
believes that the changes to the Alberta royalties may increase Progress'
Alberta royalty rate from 27 percent to 31.5 percent based on current
production and a realized natural gas price of $7.00 per gj. Using the same
production and price assumptions, Progress' royalty rate is estimated to
increase marginally from 25 percent to 27.5 percent, on a corporate basis,
resulting in an approximate five percent reduction in 2009 cash flow.
    Although Progress intends to continue to make cash distributions to
unitholders, these distributions are not guaranteed.

    Capital Expenditures

    The Trust invested approximately $173.4 million in total capital
expenditures in 2007 compared to $134.7 million in 2006. Exploration and
development capital amounted to $137.0 million in 2007, consistent with 2006
of $133.9 million.

    
    ($ thousands)                                           2007        2006
    -------------------------------------------------------------------------
    Land acquisitions and retention                        6,186      11,936
    Geological and geophysical                             5,039       5,892
    Drilling and completions                              94,422      82,611
    Equipping and facilities                              30,979      31,926
    Corporate assets                                         371       1,521
    -------------------------------------------------------------------------
    Exploration and development capital                  136,997     133,886
    Net property acquisitions (dispositions)              36,375         766
    -------------------------------------------------------------------------
    Total capital expenditures                           173,372     134,652
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Progress drilled 92 gross wells (47.5 net) with a 95 percent success rate
in 2007. Included in this drilling activity was 31 gross wells (22.4 net)
drilled in the Deep Basin region of northwest Alberta, 50 gross wells
(16.9 net) in the Foothills region of northeast British Columbia, two gross
wells (1.2 net) in the Fort St. John Plains region of northeast British
Columbia and 9 gross wells (7.0 net) in central Alberta. Progress began 2007
with an exploration and development capital budget for the year of
$110.0 million and increased it to $140.0 million following the Corporate
Acquisition. Exploration and development capital expenditures for 2007 of
$137.0 million was consistent with the revised $140.0 million budget. The
successful 2007 capital program resulted in a proved plus probable finding and
development cost of $14.64 per boe before acquisitions and $16.67 per boe
including acquisitions.
    On May 31, 2007 Progress acquired certain petroleum and natural gas
assets from a major producer in the Wapiti area for $41.3 million, net of
final closing adjustments. The acquisition added approximately 800 boe per day
of production, 1.54 million boe of proved plus probable reserves and
31,000 net undeveloped acres of land with varying working interests which will
create further opportunities to consolidate working interests within the
region. Progress believes there are substantial upside opportunities on the
acquired lands which are contiguous with the Trust's properties in the Gold
Creek region. The acquisition also added ownership in infrastructure which is
strategic to Progress' area of expansion plans.
    In July 2007, Progress sold its gross overriding interest and certain
land in the Copton and Cutpick areas of northwest Alberta for $8.0 million.
    On November 30, 2007 Progress acquired assets in the Blair and Cameron
areas of the Foothills region of British Columbia for $3.6 million.
    In June 2006, the Trust disposed of its petroleum and natural gas assets
in the Unity, Saskatchewan area to a private company for 2,860,000 common
shares valued at $1.20 per share for a total consideration of $3.4 million. As
this was a non-cash transaction, it is excluded from the table above.
    The 2008 capital investment program will be mainly directed to the
Trust's growing positions in the Deep Basin in northwest Alberta and the
Foothills regions of northeast British Columbia. Progress expects to drill
approximately 50 net wells on an exploration and development capital program
totaling between $110 million to $125 million. The Trust's capital investment
program is expected to be split approximately 65 percent to drilling and
completions, 25 percent to major facilities and 10 percent to land and seismic
expenditures. The Trust does not set a budget for property acquisitions.

    Undeveloped Land

    Undeveloped land at December 31, 2007 increased 50 percent compared to
December 31, 2006 due to the Corporate Acquisition, as well as other asset
acquisitions and acreage purchased at Crown land sales during 2007. The Trust
acquired approximately 240,000 net acres of undeveloped land through the
Corporate Acquisition, 31,000 net acres as part of the Wapiti asset
acquisition completed May 31, 2007, 8,000 net acres through an asset
acquisition completed November 30, 2007 in the Blair and Cameron areas of the
Foothills region, and purchased approximately 34,000 net acres at Crown land
sales during 2007 in Progress' core regions.

    
                                    2007        2007        2006        2006
    (acres)                        Gross         Net       Gross         Net
    -------------------------------------------------------------------------
    Alberta                      394,000     293,000     248,000     203,000
    British Columbia             689,000     249,000     410,000     157,000
    Saskatchewan                   4,000       3,000       4,000       3,000
    -------------------------------------------------------------------------
    Total undeveloped land     1,087,000     545,000     662,000     363,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Over the next 12 months 156,000 net acres or 29 percent of Progress'
undeveloped land will be subject to expiry. The Trust has an active capital
program and farmout strategy to minimize undeveloped land expires.

    Goodwill

    The goodwill balance of $414.7 million is primarily the result of the
acquisition of Cequel in 2004. In accordance with Canadian GAAP, goodwill is
not amortized but is subject to an impairment test. Progress conducts a
goodwill impairment test on an annual basis at its fiscal year end. Goodwill
may be tested for impairment between annual tests in certain situations. There
was no impairment of goodwill as a result of the tests conducted at
December 31, 2007 and 2006.

    Liquidity and Capital Resources

    ($ thousands except per unit amounts)                   2007        2006
    -------------------------------------------------------------------------
    Working capital deficiency                            25,459      14,835
    Bank debt                                            296,590      75,000
    Convertible debentures                               122,174     119,605
    -------------------------------------------------------------------------
    Total debt                                           444,223     209,440
    -------------------------------------------------------------------------
    Units outstanding and issuable
     for exchangeable shares (thousands)                 110,781      88,114
    Market price per unit at end of year                   10.85       12.57
    -------------------------------------------------------------------------
    Market value of trust units and
     exchangeable shares                               1,201,974   1,107,593
    -------------------------------------------------------------------------
    Cash flow                                            214,290     190,329
    Total debt to cash flow ratio                           2.07        1.10
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    At December 31, 2007 the Trust had $296.6 million outstanding on its
credit facility of $375.0 million, as well as $122.2 million for the debt
portion of the Debentures and a working capital deficiency of $25.5 million,
resulting in $444.2 million of total debt. The Trust currently has a
$340 million extendible revolving term credit facility and a $35 million
working capital credit facility with a syndicate of banks. The facilities are
available on a revolving basis for a period of at least 364 days until May
27, 2008, and such initial term out date may be extended for further 364 day
periods at the request of the Trust, subject to approval by the banks.
Following the term out date, the facilities will be available on a non-
revolving basis for a one year term, at which time the facilities would be due
and payable. The credit facilities are secured by a $1 billion fixed and
floating charge debenture on the assets of the Trust and by a guarantee and
subordination provided by Progress Energy Ltd. in respect of the Trust's
obligations. The $375 million borrowing base is subject to semi-annual review
by the banks.
    Bank debt of $296.6 million as at December 31, 2007 was higher than the
December 31, 2006 bank debt of $75.0 million due to the Corporate Acquisition,
as well as the capital program and asset acquisitions completed in 2007.
Working capital deficiency increased from $14.0 million as at December
31, 2006 to $25.5 million as at December 31, 2007 as a result of an increase
in accounts payable and accrued liabilities due to the timing of invoice
payments and less cash on hand.
    On April 2, 2007 Progress purchased all of the issued and outstanding
shares of a private company (refer to Corporate Acquisition above) and in
conjunction with the purchase, sold certain assets of the private company to
ProEx. The net cash consideration of $393.0 million, was financed by the
issuance of 21,000,000 trust units at a price of $12.00 per trust unit for
proceeds of $252.0 million ($238.7 million net of issue costs) and through
increased bank debt.
    On August 22, 2006 the Trust issued $75.0 million principal amount of
6.25 percent convertible unsecured subordinated debentures for net proceeds of
$71.7 million. The 6.25 percent debentures pay interest semi-annually and are
convertible at the option of the holder at any time into fully paid trust
units at a conversion price of $19.50 per trust unit. The 6.25 percent
debentures mature on September 30, 2011 at which time they become due and
payable. Interest and principal repayments may be made by way of cash or trust
units. The net proceeds were used to reduce outstanding bank indebtedness.
    The 6.75 percent convertible unsecured subordinated debentures pay
interest semi-annually and are convertible at the option of the holder at any
time into fully paid trust units at a conversion price of $15.00 per trust
unit. The 6.75 percent debentures mature on June 30, 2010 at which time they
are due and payable. The Trust may elect to satisfy the interest and principal
obligations by the issuance of trust units. The net proceeds were used to
reduce outstanding bank indebtedness.
    The Debentures have been classified as debt net of the fair value of the
conversion feature which has been classified as part of unitholders' equity
and net of issue costs. For the 6.25 percent debentures, this resulted in
$66.7 million being classified as debt and $4.9 million being classified as
equity. For the 6.75 percent debentures, $90.5 million was originally
classified as debt and $4.9 million was classified as equity. Issue costs are
amortized over the term of the Debentures, and the debt portion will accrete
up to the principal balance at maturity. The accretion, amortization of issue
costs and the interest paid are expensed within interest and financing expense
on the consolidated statements of earnings.
    The following table outlines the Debenture activity for the years ended
December 31, 2007 and 2006:

    
                                   2007                       2006
    -------------------------------------------------------------------------
    ($ thousands)         6.75%    6.25%    Total    6.75%    6.25%    Total
    -------------------------------------------------------------------------
    Principal,
     beginning of
     year(1)             55,727   75,000  130,727   86,182   75,000  161,182
    Converted to trust
     units                    -        -        -  (30,455)       -  (30,455)
    -------------------------------------------------------------------------
    Principal, end of
     year                55,727   75,000  130,727   55,727   75,000  130,727
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Debt portion,
     beginning of
     year(1)             52,300   67,305  119,605   79,381   66,748  146,129
    Accretion               508      945    1,453      535      337      872
    Amortization of
     issue costs            466      650    1,116      497      220      717
    Conversions to
     trust units(2)           -        -        -  (28,113)       -  (28,113)
    -------------------------------------------------------------------------
    Debt portion, end
     of year             53,274   68,900  122,174   52,300   67,305  119,605
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Equity portion,
     beginning of
     year(1)              2,756    4,946    7,702    4,261    4,946    9,207
    Conversions to
     trust units              -        -        -   (1,505)       -   (1,505)
    -------------------------------------------------------------------------
    Equity portion,
     end of year          2,756    4,946    7,702    2,756    4,946    7,702
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) The 6.75 percent debentures were issued February 2, 2005 and the 6.25
        percent debentures were issued August 22, 2006.
    (2) Net of unamortized issue costs.
    

    The Trust's investing activities for 2007 consisted of the Corporate
Acquisition as well as expenditures on the capital program and asset
acquisitions. Management anticipates that the Trust will continue to have
adequate liquidity to fund future working capital and forecasted capital
expenditures during 2008 through a combination of cash flow and debt. Cash
flow used to finance these commitments may reduce the amount of cash
distributions paid to unitholders.
    Outstanding as at February 27, 2008 were 97,817,443 trust units,
8,941,859 exchangeable shares and $130.7 million of Debentures convertible
into 7,561,287 trust units.

    Off Balance Sheet Arrangements

    The Trust has no guarantees or off-balance sheet arrangements except for
certain lease agreements, and letters of credit. 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 G&A expenses depending on the nature of the lease. No
asset or liability value has been assigned to these leases on the balance
sheet as at December 31, 2007. The total future obligation from these
operating leases is described below in the section "Contractual Obligations
and Commitments".
    Letters of credit of approximately $1.7 million as at December 31, 2007
(2006 - $1.4 million) have been issued in the normal course of business mainly
for contract firm transportation.

    Unitholders' Equity

    At December 31, 2007, there were 97.5 million trust units outstanding, a
29 percent increase from the 75.5 million trust units outstanding at
December 31, 2006. The increase in the number of trust units is the result of
21.0 million trust units issued to finance a portion of the Corporate
Acquisition (gross proceeds of $252.0 million, $238.7 million net of issue
costs), 0.6 million units issued ($7.1 million) on the conversion of
exchangeable shares during 2007 and 0.4 million trust units issued
($5.1 million) to settle the performance units that vested on July 2, 2007.

    Contractual Obligations and Commitments

    The Trust contracts for firm transportation on the TransCanada and Atco
systems in Alberta and the Spectra Energy system in British Columbia. The
Trust has an office lease commitment that extends to 2009. Annual costs of
this lease commitment, which include rent and operating expenses, amount to
approximately $1.5 million.
    The Trust must pay crown royalty, surface rentals, mineral taxes and
abandonment and reclamation costs with respect to its ongoing ownership of
hydrocarbon production rights. The amounts paid with respect to these burdens
will depend on the future ownership, production, prices and legislative
environment at the time.
    Production of 4,100 mcf per day is dedicated to certain aggregator sales
arrangements. Under these arrangements, Progress receives a price based on the
average netback price of the pool, net of transportation expenses incurred by
the aggregator.

    
                                     Minimum Annual Commitment
    ($ thousands)         Total     2008     2009     2010     2011     2012
    -------------------------------------------------------------------------
    Bank debt(1)        296,590        -  296,590        -        -        -
    Convertible
     debentures         130,727        -        -   55,727   75,000        -
    Pipeline
     commitments         48,284   14,623   13,578   11,006    7,757    1,320
    Drilling rig
     commitments          1,779    1,779        -        -        -        -
    Operating leases        272      272        -        -        -        -
    Financial
     instrument
     premiums             4,622    4,622        -        -        -        -
    Farm-in                 820      820        -        -        -        -
    Office lease          2,712    1,479    1,233        -        -        -
    -------------------------------------------------------------------------
    Total               485,806   23,595  311,401   66,733   82,757    1,320
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Based on the existing terms of the revolving credit facilities which
        are subject to renewal on or before May 27, 2008. If not extended,
        the facilities would be available on a non-revolving basis for a one-
        year term at which time the facilities would be due and payable.



    FOURTH QUARTER ANALYSIS

                                                  Q4          Q3          Q4
                                                2007        2007        2006
    -------------------------------------------------------------------------
    OPERATIONAL HIGHLIGHTS

    Daily Production
    Natural gas (mcf/d)                      123,740     120,804      88,568
    Crude oil (bbls/d)                         2,068       2,268       2,030
    Natural gas liquids (bbls/d)               1,548       1,370       1,269
    Total daily production (boe/d)            24,240      23,772      18,060

    Average Benchmark Prices
    Natural gas - AECO (daily) ($/gj)           5.82        4.88        6.54
    Natural gas - AECO (monthly) ($/gj)         5.69        5.32        6.03
    Natural gas - Station No.2 (daily) ($/gj)   5.95        4.94        6.37
    Crude oil - WTI (US$/bbl)                  90.69       75.38       60.21
    Crude oil - Edmonton par price (Cdn$/bbl)  85.35       79.84       64.53
    Exchange rate (US$/Cdn$)                  0.9818      1.0446      1.1393
    Average Realized Prices
    Natural gas - ($/mcf)                       6.49        5.77        7.05
    Crude oil ($/bbl)                          81.67       78.77       59.26
    Natural gas liquids ($/bbl)                71.51       62.91       55.71

    FINANCIAL HIGHLIGHTS ($ thousands,
     except per unit amounts)
    Petroleum and natural gas revenue         99,592      88,480      75,183
    Royalties                                (21,267)    (19,242)    (17,089)
    Realized gain on financial instruments     2,551       6,324      10,451
    Operating expenses                       (13,184)    (14,596)    (11,013)
    Transportation expenses                   (4,152)     (4,295)     (2,593)
    General and administrative expenses       (2,022)     (2,454)     (1,548)
    Unit based compensation expense           (2,594)     (2,394)     (1,496)
    Cash flow                                 54,727      48,085      49,603
    Depletion, depreciation and accretion    (37,235)    (37,345)    (24,542)
    Net earnings                               9,922      11,909      21,538
    Per unit basic                              0.10        0.12        0.29
    Per unit diluted                            0.10        0.12        0.28

    Exploration and development capital       47,210      31,726      35,475
    Net property acquisitions (dispositions)   3,295      (8,293)       (171)
    -------------------------------------------------------------------------
    Total capital expenditures                50,505      23,433      35,304
    -------------------------------------------------------------------------
    

    Production

    Production during the fourth quarter (the "Quarter") of 2007 of 24,240
boe per day was slightly higher than the third quarter of 2007 of 23,772 boe
per day and was 34 percent higher than the fourth quarter of 2006 at 18,060
boe per day. The production increase from the third quarter to the fourth
quarter in 2007 was primarily the result of new wells brought on production
during the Quarter. The increase in production for the Quarter over the fourth
quarter of 2006 was due to the Corporate Acquisition completed on April 2,
2007 as well as new wells brought on production.

    Revenue

    Petroleum and natural gas revenue for the Quarter of $99.6 million was
13 percent higher than the third quarter of 2007 of $88.5 million and was
32 percent higher than the $75.2 million recognized for the fourth quarter of
2006. The increase from the third quarter of 2007 was primarily the result of
higher natural gas prices, while the increase from the fourth quarter of 2006
was due to increased production, primarily from the Corporate Acquisition.

    Royalties

    Royalties for the Quarter of $21.3 million was 11 percent higher than the
third quarter of 2007 of $19.2 million and was 24 percent higher than the
fourth quarter of 2006 of $17.1 million due to higher revenues. The average
royalty rate for the Quarter of 21.4 percent was consistent with the third
quarter of 2007 and the fourth quarter of 2006 of 21.7 percent and
22.7 percent, respectively.

    Operating Expenses

    Operating expenses for the Quarter of $13.2 million were 10 percent lower
than the third quarter of 2007 of $14.6 million and 20 percent higher than the
fourth quarter of 2006 of $11.0 million. The decrease from the third quarter
of 2007 was due to operating efficiencies realized on the assets acquired in
the Corporate Acquisition. The increase from the fourth quarter of 2006 was
due to increased production as a result of the Corporate Acquisition.
Operating expenses during the Quarter averaged $5.91 per boe compared to $6.67
per boe during the third quarter of 2007 and $6.63 per boe during the fourth
quarter of 2006. The lower operating expenses per boe are the result of
efficiencies obtained on the assets acquired in the Corporate Acquisition.

    Transportation Expenses

    Transportation expenses for the Quarter of $4.2 million were consistent
with the third quarter of 2007 of $4.3 million and 60 percent higher than the
fourth quarter of 2006 of $2.6 million. The increase from the fourth quarter
of 2006 was due to the increased production as a result of the Corporate
Acquisition. Transportation expenses during the Quarter averaged $1.86 per boe
compared to $1.96 per boe during the third quarter of 2007 and $1.56 per boe
during the fourth quarter of 2006. The increase from the fourth quarter of
2006 was due to higher transportation and treatment tolls associated with the
Corporate Acquisition including higher treatment tolls associated with the
Slave Point production at the Bubbles property. Approximately 40 percent of
the Trust's production was in British Columbia where there is an
infrastructure owned by Spectra Energy that enables gas producers to avoid
facility construction in exchange for gathering, processing and transmission
fees. This all-in charge is included in transportation expenses.

    General and Administrative Expenses

    G&A expenses for the Quarter of $2.0 million were 18 percent lower than
the third quarter of 2007 of $2.5 million and were 31 percent higher than the
fourth quarter of 2006 of $1.5 million. The decrease from the third quarter of
2007 was due to higher recoveries during the Quarter as a result of higher
capital spending. The increase from the fourth quarter of 2006 was due to the
increased size of the Trust as well as higher costs incurred to retain
employees. G&A expenses averaged $0.91 per boe during the Quarter compared to
$1.12 in the third quarter of 2007 and $0.93 during the fourth quarter of
2006.

    Depletion, Depreciation and Accretion

    DD&A expense for the Quarter of $37.2 million was consistent with the
third quarter of 2007 of $37.3 million and 52 percent higher than the fourth
quarter of 2006 of $24.5 million. The increase over the fourth quarter of 2006
was due to the Corporate Acquisition. This resulted in DD&A of $16.70 per boe
for the Quarter compared to $17.08 per boe for the third quarter of 2007 and
$14.77 for the fourth quarter of 2006.

    Future Income Taxes

    The provision for future income taxes in the Quarter resulted in a charge
of $1.7 million compared to a recovery for the third quarter of 2007 of
$5.9 million and a recovery for the fourth quarter of 2006 of $1.4 million.
The provision for the Quarter includes a charge of $2.1 million as a result of
lower federal income tax rates enacted during the Quarter which reduced the
value of the Trust's future income tax asset.

    Net Earnings and Cash Flow

    Net earnings for the Quarter were $9.9 million compared to $11.9 million
for the third quarter of 2007 and $21.5 million for the fourth quarter of
2006. The decrease in net earnings from the fourth quarter of 2006 was due to
a higher DD&A expense, as well as, increases to operating, transportation and
interest expenses as a result of the Corporate Acquisition.
    Cash flow for the Quarter of $54.7 million was 14 percent higher than the
third quarter of 2007 of $48.1 million and 10 percent higher than the fourth
quarter of 2006 of $49.6 million. The increase over the third quarter of 2007
was due higher commodity prices and the increase over the fourth quarter of
2006 was due to increased production as a result of the Corporate Acquisition
and successful drilling.

    Capital Expenditures

    During the Quarter, the Trust incurred $50.5 million of capital
expenditures comprised of $1.8 million in land acquisition and retention, $1.7
million in geological and geophysical, $36.0 million in drilling and
completions, $7.7 million in facility construction, and $3.3 million on
property acquisitions (dispositions). During the Quarter the Trust drilled 39
gross wells (20.1 net) with 26 gross wells (9.9 net) drilled in the northeast
British Columbia Foothills, seven gross wells (5.5 net) drilled in the Deep
Basin of northwest Alberta and six gross wells (4.7 net) drilled in central
Alberta. The $3.3 million in net property acquisitions (dispositions) includes
an asset acquisition completed on November 30, 2007 in the Blair and Cameron
areas of the Foothills region for $3.6 million. In the third quarter of 2007,
Progress sold its gross overriding interest and certain land in the Copton and
Cutpick areas of northwest Alberta for $8.0 million.
    Total capital investment during the Quarter was $50.5 million compared to
$23.4 million in the third quarter of 2007 and $35.3 million in the fourth
quarter of 2006.

    ENVIRONMENT, HEALTH AND SAFETY

    Progress places a high priority on preserving the quality of its
environment and protecting the health and safety of its employees, contractors
and the public in communities in which it lives and works. Progress actively
participates in industry-recognized programs at the highest possible levels in
an effort to support continuous improvement.
    Progress is committed to meeting its responsibilities to protect the
environment through a variety of programs and actively monitoring its
compliance with all regulators. Progress strives to employ capital and energy
efficient methods to minimize its footprint and maximize the recovery of its
resources. Progress has progressed from a "Bronze" level upon the formation of
the Trust in 2004 to in 2007 achieving the Canadian Association of Petroleum
Producers ("CAAP") highest level, "Platinum". Platinum stewardship means that
Progress has demonstrated by audit and by statistics that its safety &
environment management system has good sound effective leadership and
performance in the areas of health, safety, environment and social
responsibility.
    Progress participates in the Environment, Health and Safety Stewardship
Program developed by CAAP. Progress' participation requires its commitment to
continuous improvement in its environment, health and safety ("EHS")
management practices including sound planning and implementation, open
communication and demonstrated performance and a thorough external audit of
its activities at least once every 3 years. Progress also conducted a company
wide EH&S Management System audit in 2007. An action plan was spawned that
included Safety Leadership Training for Supervisors; Hazard Assessment
Training for Operators and Supervisors; the development of site specific work
procedures and the development of policies outlining Social Responsibility.
    Progress continually works to improve its health and safety performance
through increased awareness in the field by frequently communicating safety
responsibilities to our employees and contractors and by issuing and sharing
safety information. Health and safety is increasingly more visible in the
field and Progress is becoming more active with contractor safety management
through industry committee participation and the promotion of industry
recognized best practices.
    In 2007, Progress' overall health and safety performance was consistent
in 2007 compared to 2006. There was no employee lost time incidents in 2007 or
2006. There were a total of 34 recorded contractor injury incidents in 2007
compared to 37 contractor incidents in 2006. Progress' contractors had 9
lost-time incidents in 2007 compared to 8 in 2006.
    Progress is committed to environmental stewardship and the health and
safety of its employees, contractors and the general public in the communities
in which it operates.

    CRITICAL ACCOUNTING ESTIMATES

    The preparation of the consolidated financial statements in accordance
with Canadian GAAP requires Management to make judgments and estimates that
affect the financial results of the Trust. Progress' Management reviews its
estimates regularly, but new information and changed circumstances may result
in actual results or changes to estimated amounts that differ materially from
current estimates. A summary of significant accounting policies are presented
in Note 1 to the consolidated financial statements. The critical estimates are
discussed below:

    Petroleum and Natural Gas Reserves

    All of Progress' petroleum and natural gas reserves are evaluated and
reported on by independent petroleum engineering consultants in accordance
with Canadian Securities Administrators' National Instrument 51-101 ("NI 51-
101"). The evaluation of reserves is a subjective process. Forecasts are based
on engineering data, projected future rates of production, commodity prices
and the timing of future expenditures, all of which are subject to numerous
uncertainties and various interpretations. The Trust expects that its
estimates of reserves will change to reflect updated information. Reserve
estimates can be revised upward or downward based on the results of future
drilling, testing, production levels and changes in costs and commodity
prices.
    On October 25, 2007 the Alberta government announced the New Royalty
Framework ("framework"), which is proposed to take effect on January 1, 2009.
As the new framework has yet to become law, and all of the details have not
been readily available, the reserves as at December 31, 2007 do not include
the impact of this proposed framework. Progress has reviewed the information
currently provided by the government and believes that the changes to the
Alberta royalties may increase Progress' Alberta royalty rate from 27 percent
to 31.5 percent based on current production and a realized natural gas price
of $7.00 per gj. Using the same production and price assumptions, Progress'
royalty rate is estimated to increase marginally from 25 percent to 27.5
percent, on a corporate basis. The impact of the royalty increase is a
decrease to the net present value of the Trust's reserves by approximately one
to two percent when using a 10 percent discount rate and using GLJ forecast
prices as at January 1, 2008.

    Depletion Expense

    The Trust uses the full cost method of accounting for exploration and
development activities whereby all costs associated with these activities are
capitalized, whether successful or not. The aggregate of capitalized costs,
net of certain costs related to unproved properties, and estimated future
development costs is amortized using the unit-of-production method based on
estimated proved reserves. Changes in estimated proved reserves or future
development costs have a direct impact on depletion expense.
    Certain costs related to unproved properties and major development
projects may be excluded from costs subject to depletion until proved reserves
have been determined or their value is impaired. These properties are reviewed
quarterly to determine if proved reserves should be assigned, at which point
they would be included in the depletion calculation, or for impairment, for
which any write-down would be charged to depletion and depreciation expense.

    Full Cost Accounting Ceiling Test

    The carrying value of property, plant and equipment is reviewed at least
annually for impairment. Impairment occurs when the carrying value of the
assets is not recoverable by the future undiscounted cash flows. The cost
recovery ceiling test is based on estimates of proved reserves, production
rates, petroleum 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 financial statements could be material. Any
impairment would be charged as additional depletion expense.

    Asset Retirement Obligations

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

    Income Taxes

    The determination of the Trust's income and other tax liabilities
requires interpretation of complex laws and regulations often involving
multiple jurisdictions. All tax filings are subject to audit and potential
reassessment after the lapse of considerable time. Accordingly, the actual
income tax liability may differ significantly from that estimated and
recorded.
    New legislation passed in June 2007, effective January 1, 2011, will
apply a tax at the trust level on distributions of certain income from
publicly traded mutual fund trusts at rates of tax comparable to the combined
federal and provincial corporate tax and will treat such distributions as
dividends to the unitholders.

    CHANGE IN ACCOUNTING POLICIES AND RECENT ACCOUNTING PRONOUNCEMENTS

    Internal Control Reporting

    In March 2006 Canadian Securities Administrators decided to not proceed
with proposed multilateral instrument 52-111 Reporting on Internal Control
over Financial Reporting and instead proposed to expand multilateral
instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim
Filings. The major changes resulting from this is the CEO and CFO will be
required to certify in the annual certificates that they have evaluated the
effectiveness of internal controls over financial reporting ("ICOFR") as of
the end of the financial year and disclose in the annual MD&A their
conclusions about the effectiveness of ICOFR. There will be no requirement to
obtain an internal control audit opinion from the issuer's auditors concerning
management's assessment of the effectiveness of ICOFR. There is also no
requirement to design and evaluate internal controls against an external
control framework. This proposed amendment is expected to apply for the year
ended December 31, 2008. Progress is continuing with its evaluation of ICOFR
to ensure it meets the criteria for the proposed certification for
December 31, 2008.

    Financial Instruments

    On January 1, 2007 the Trust adopted the new accounting standards
regarding the accounting for financial instruments. In addition to the
adoption of the new standards, Management elected not to use hedge accounting
and therefore, records the fair value of its natural gas financial contracts
at each reporting period with the change in the fair value being classified as
unrealized gains or losses on the statement of earnings. The accounting for
hedging relationships for prior fiscal periods are not retroactively changed,
therefore, there was no restatement of the financial position or results of
operation as at and for the year ended December 31, 2006.
    On January 1, 2007 the fair value of the commodity price contracts was an
asset of $15.6 million and resulted in an increase to accumulated other
comprehensive income and the future income tax liability of $10.5 million and
$5.1 million, respectively. The $10.5 million recognized in accumulated other
comprehensive income was amortized over the term of the contracts through
other comprehensive income with a corresponding unrealized gain on financial
instruments on the statement of earnings. As a result, for the year ended
December 31, 2007 $10.5 million, net of tax, was charged to other
comprehensive income with a corresponding unrealized gain on financial
instruments of $15.6 million and a charge to future income tax expense of
$5.1 million. The unrealized gain of $15.6 million was offset by the change in
fair value from January 1, 2007 of $15.6 million resulting in an unrealized
gain of nil for 2007.
    Effective December 31, 2007 Progress early adopted the disclosures
required under section 3862 Financial Instruments - Disclosures which applies
to both recognized and unrecognized financial instruments. These disclosures,
which include the nature and extent of risks arising from financial
instruments, are included in note 11 of the consolidated financial statements.

    Capital Disclosures

    Effective December 31, 2007 Progress early adopted the new
recommendations of the CICA for disclosure of the Company's objectives,
policies and processes for managing capital (Section 1535) as discussed in
note 8 of the consolidated financial statements.

    Convergence with International Reporting Standards

    On February 13, 2008, Canada's Accounting Standards Board confirmed
January 1, 2011 as the effective date for the convergence of Canadian GAAP to
International Financial Reporting Standards. The Canadian Securities
Administrators are in the process of examining changes to securities rules as
a result of this initiative. As this change initiative is in its infancy,
Progress has not determined its impact on its financial position or results of
operations.

    DISCLOSURE CONTROLS AND PROCEDURES

    Disclosure controls and procedures have been designed to ensure that
information required to be disclosed by the Trust is accumulated and
communicated to the Trust's Management, as appropriate, to allow timely
decisions regarding required disclosures. The Trust's Chief Executive Officer
and Chief Financial Officer have concluded, based on their evaluation as of
the end of the period covered by the annual filings that the Trust's
disclosure controls and procedures are effective to provide reasonable
assurance that material information related to the issuer, is made known to
them by others within the Trust. It should be noted that while the Trust's
Chief Executive Officer and Chief Financial Officer believe that the Trust's
disclosure controls and procedures provide a reasonable level of assurance
that they are effective, they do not expect that the disclosure controls and
procedures or internal control over financial reporting will prevent all
errors and fraud. A control system, no matter how well conceived or operated,
can provide only reasonable, not absolute, assurance that the objective of the
control system is met.

    OUTLOOK AND 2008 FORECAST

    Progress will continue to pursue a disciplined approach to long term
sustainability on a per unit basis. Our technical approach and cost control
will be primary contributors to sustained value creation for unitholders.
Internally generated opportunities will be drilled at a more modest pace than
when we were an aggressive growth company. At our current capital investment
pace, our inventory of drilling locations currently supports more than three
years of activity, while our over 540,000 net acres of undeveloped land
provides the opportunity for our technical team to create incremental value.
    In creating our Trust, we ensured that we would have access to strong
technical and financial staff by having all employees invest in Progress. This
creates strong alignment with our unitholders and ensures that we have the
professionals to execute our business plan. Employees, Management and
Directors hold an 11 percent direct ownership interest in our Trust.
    The following table summarizes the Trust's 2008 forecast provided
throughout the MD&A. Progress does not forecast commodity prices and as a
result, the Trust does not provide a forecast of future cash distributions to
unitholders.

    
    2008 Forecast                                                     Target
    -------------------------------------------------------------------------
    Average annual production                                   23,500 boe/d
    Royalty rate                                            23 to 24 percent
    Operating expenses                                $6.50 to $6.75 per boe
    G&A expenses                                      $1.00 to $1.10 per boe
    Unit based compensation expenses                           $1.10 per boe
    Capital expenditures                                $110 to $125 million
    Drilling activity                                           50 net wells
    ------------------------------------------------------------------------

    ADDITIONAL INFORMATION

    Additional information regarding the Trust and its business and
operations, including the annual information form ("AIF") is available on the
Trust's company profiles at www.sedar.com. Copies of the AIF can also be
obtained by contacting the Trust at Progress Energy Trust 1200, 205 - 5th
Avenue S.W., Calgary, Alberta, Canada T2P 2V7 or by e-mail at
ir@progressenergy.com. This information is also accessible on the Trust's web
site at www.progressenergy.com



    PROGRESS ENERGY TRUST
    CONSOLIDATED BALANCE SHEETS

    As at December 31 ($ thousands)                         2007        2006
    -------------------------------------------------------------------------
    ASSETS

    Current
      Cash and short-term investments                          -       8,265
      Accounts receivable                                 47,505      35,555
      Prepaid expenses and deposits                        9,148       7,798
    -------------------------------------------------------------------------
                                                          56,653      51,618
    Property, plant and equipment (Note 3)             1,055,054     744,431
    Future income taxes (Notes 2 and 9)                   36,716           -
    Goodwill                                             414,655     414,655
    -------------------------------------------------------------------------
                                                       1,563,078   1,210,704
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    LIABILITIES

    Current
      Accounts payable and accrued liabilities            67,127      50,696
      Cash distributions payable                           9,748      10,564
      Current income taxes payable                         5,237       5,193
    -------------------------------------------------------------------------
                                                          82,112      66,453
    Bank debt (Note 4)                                   296,590      75,000
    Convertible debentures (Note 5)                      122,174     119,605
    Asset retirement obligations (Note 6)                 35,012      24,148
    Future income taxes (Note 9)                               -     114,367
    -------------------------------------------------------------------------
                                                         535,888     399,573

    NON-CONTROLLING INTEREST
    Exchangeable shares (Note 7)                         126,384     122,592

    UNITHOLDERS' EQUITY

    Unitholders' capital (Note 8)                        990,946     739,998
    Convertible debentures (Note 5)                        7,702       7,702
    Contributed surplus (Note 8)                          14,468       9,210
    Deficit                                             (112,310)    (68,371)
    -------------------------------------------------------------------------
                                                         900,806     688,539
    Commitments (Note 12)
    -------------------------------------------------------------------------
                                                       1,563,078   1,210,704
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See accompanying notes to the consolidated financial statements


    Approved on behalf of the Board of Directors of Progress Energy Ltd.


    (signed) "David D. Johnson"             (signed) "Donald F. Archibald"
    Director                                Director



    PROGRESS ENERGY TRUST
    CONSOLIDATED STATEMENTS OF EARNINGS, COMPREHENSIVE INCOME AND DEFICIT

    Year ended December 31 ($ thousands,
     except per unit amounts)                               2007        2006
    -------------------------------------------------------------------------

    REVENUE
      Petroleum and natural gas                          382,052     310,518
      Royalties                                          (84,434)    (78,762)
    -------------------------------------------------------------------------
                                                         297,618     231,756
      Realized gain on financial instruments (Note 11)    16,055      29,937
      Other income                                           219           -
    -------------------------------------------------------------------------
                                                         313,892     261,693
    -------------------------------------------------------------------------

    EXPENSES
      Operating                                           53,661      40,353
      Transportation                                      15,395      11,017
      General and administrative                           8,756       6,321
      Unit based compensation (Note 8)                     9,037       4,874
      Interest and financing                              23,015      11,798
      Depletion, depreciation and accretion              138,636      94,708
    -------------------------------------------------------------------------
                                                         248,500     169,071
    -------------------------------------------------------------------------
    Earnings before taxes and non-controlling interest    65,392      92,622
    -------------------------------------------------------------------------

    TAXES
      Capital taxes                                          126         180
      Future income taxes (Note 9)                       (14,861)    (14,673)
    -------------------------------------------------------------------------
                                                         (14,735)    (14,493)
    -------------------------------------------------------------------------
    Net earnings before non-controlling interest          80,127     107,115
    Non-controlling interest - exchangeable
     shares (Note 7)                                      (9,924)    (15,517)
    -------------------------------------------------------------------------
    NET EARNINGS                                          70,203      91,598

    OTHER COMPREHENSIVE INCOME
    Amortization of fair value of financial
     instruments (Notes 1 and 8)                         (10,543)          -
    -------------------------------------------------------------------------
    COMPREHENSIVE INCOME                                  59,660      91,598
    -------------------------------------------------------------------------

    Deficit, beginning of year                           (68,371)    (34,406)
    Distributions                                       (114,142)   (125,563)
    -------------------------------------------------------------------------
    Deficit, end of year                                (112,310)    (68,371)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    NET EARNINGS PER UNIT (Note 8)
      Basic                                                $0.76       $1.23
      Diluted                                              $0.76       $1.21
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See accompanying notes to the consolidated financial statements



    PROGRESS ENERGY TRUST
    CONSOLIDATED STATEMENTS OF CASH FLOWS

    Year ended December 31 ($ thousands)                    2007        2006
    -------------------------------------------------------------------------

    Operating Activities

      Net earnings                                        70,203      91,598
      Depletion, depreciation and accretion              138,636      94,708
      Non-controlling interest - exchangeable
       shares (Note 7)                                     9,924      15,517
      Convertible debentures accretion (Note 5)            1,453         872
      Amortization of convertible debenture issue
       costs (Note 5)                                      1,116         717
      Amortization of commodity sales contract              (505)       (570)
      Unit based compensation (Note 8)                     9,037       4,874
      Asset retirement expenditures (Note 6)                (713)     (2,714)
      Future income taxes                                (14,861)    (14,673)
    -------------------------------------------------------------------------
                                                         214,290     190,329
      Changes in non-cash working capital (Note 10)        6,139        (170)
    -------------------------------------------------------------------------
                                                         220,429     190,159
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Financing Activities

      Increase in bank debt                              212,467       3,674
      Issue of units (Notes 2 and 8)                     252,000           -
      Unit issue costs (Notes 2 and 8)                   (13,304)          -
      Issue of convertible debentures (Note 5)                 -      75,000
      Convertible debenture issue costs (Note 5)               -      (3,306)
      Cash distributions                                (114,958)   (124,981)
    -------------------------------------------------------------------------
                                                         336,205     (49,613)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Investing Activities

      Corporate Acquisition (Note 2)                    (527,432)          -
      Disposition (Note 2)                               134,400           -
      Capital expenditures                              (173,373)   (134,652)
      Change in non-cash working capital (Note 10)         1,506       2,371
    -------------------------------------------------------------------------
                                                        (564,899)   (132,281)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Change in cash and short-term investments             (8,265)      8,265
    Cash and short-term investments, beginning of year     8,265           -
    -------------------------------------------------------------------------
    Cash and short-term investments, end of year               -       8,265
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See accompanying notes to the consolidated financial statements



    PROGRESS ENERGY TRUST
    NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
    (tabular amounts are in $ thousands except for trust units and per trust
    unit amounts)

    Progress Energy Trust ("Progress" or the "Trust") is an open-ended,
    unincorporated investment trust governed by the laws of the province of
    Alberta. The principal undertaking of the Trust is to indirectly explore
    for, develop and hold interests in petroleum and natural gas properties
    through investments in securities of subsidiaries and royalty interests
    in petroleum and natural gas properties. Progress Energy Ltd. carries on
    the business of the Trust and directly owns the petroleum and natural gas
    properties and assets related thereto. The Trust owns, directly and
    indirectly, 100 percent of the common shares (excluding the exchangeable
    shares - see note 7) of Progress Energy Ltd. The activities of Progress
    Energy Ltd. are financed through interest bearing notes from the Trust
    and third party debt. The convertible debentures are direct obligations
    of the Trust. Under the Trust Indenture, the Trust may declare payable to
    unitholders all or any part of the income of the Trust, which is
    primarily comprised of interest earned on debt notes issued to Progress
    Energy Ltd., as well as, amounts attributed to a net profits interest
    ("NPI") agreement entered into with Progress Energy Ltd. The aggregate
    amounts received by the Trust each period are based on the consolidated
    cash flow from operations before changes in non-cash working capital each
    period, as adjusted on a discretionary basis, for cash withheld to fund
    capital expenditures.

    Pursuant to the terms of the NPI agreement, the Trust is entitled to a
    payment from Progress Energy Ltd. each month equal to the amount by which
    99% of the gross proceeds from the sale of production exceed 99% of
    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 Progress Energy Ltd.

    Relationship with ProEx

    A technical services agreement ("Technical Services Agreement") is
    currently in place between the Trust and ProEx Energy Ltd. ("ProEx")
    whereby the Trust provides personnel and certain administrative and
    technical services in connection with the management, development,
    exploitation and operation of the assets of ProEx and the marketing of
    its production. The Technical Services Agreement has no set termination
    date and will continue until terminated by either party with one year
    prior written notice to the other party or some other date as mutually
    agreed. The Trust provides these services to ProEx on an expense
    reimbursement basis, based on ProEx's monthly capital activity and
    production levels relative to the combined capital activity and
    production levels of both the Trust and ProEx. Total expense reimbursed
    by ProEx for the year ended December 31, 2007 was $6.2 million (2006 -
    $4.5 million).

    ProEx has granted stock options and shares to employees and executives of
    Progress as service providers and has also participated in a new long
    term incentive plan by granting ProEx common shares to employees of
    Progress, excluding the executives. To facilitate this plan, during 2007,
    Progress purchased 173,789 ProEx common shares and has been reimbursed by
    ProEx for the cost incurred. The ProEx common shares will be held until
    the vesting date, two years from date of grant. Any forfeited shares will
    revert back to ProEx.

    The Trust and ProEx have joint interest in certain properties and
    undeveloped land. These joint interest properties are governed by
    standard industry agreements and in addition, the Trust has entered into
    a Protocol Arrangement with ProEx that specifies how each company will
    manage the joint lands in specifically identified areas of interest. The
    Protocol Arrangement identifies methods and processes to be followed on
    both existing and new lands, joint facilities, marketing, seismic and
    surface rights. To ensure good governance practices, both the Trust and
    ProEx have each created independent committees of their Board of
    Directors to monitor compliance with the Technical Services Agreement and
    the Protocol Arrangement.

    On April 2, 2007, Progress acquired all of the issued and outstanding
    shares of a private company for $527.4 million net of certain assets
    retained by the vendor. In conjunction with the acquisition, on April 2,
    2007, Progress disposed of certain assets of the private company to ProEx
    for $134.4 million. When considering the bid process for the acquisition,
    each of Progress and ProEx identified assets that they were interested in
    acquiring and values that they were willing to pay to acquire such
    assets. Progress made a single bid on behalf of ProEx and Progress and
    the ultimate purchase price was based on the prices that each of Progress
    and ProEx were willing to pay for the assets that they had selected to
    acquire. The resale of assets from Progress to ProEx was based on these
    allocations. The technical services committee reviewed the details of the
    transaction prior to the purchase and sale agreement being signed. All
    lands are managed in accordance with the Protocol Arrangement.

    On November 30, 2007, Progress and ProEx jointly acquired certain assets
    in the Foothills region of British Columbia. The total cost of the
    acquisition of $17.9 million was split in accordance with working
    interests currently held in the surrounding area. As a result, Progress
    acquired a 20 percent interest in the assets ($3.6 million) and ProEx an
    80 percent interest ($14.3 million).

    As at December 31, 2007, accounts payable included $0.6 million (2006 -
    $4.6 million) payable to ProEx which includes standard joint venture
    amounts including revenue. These amounts were paid subsequent to year
    end.

    1.  SIGNIFICANT ACCOUNTING POLICIES

    Nature of Business and Basis of Presentation

    The Trust is involved in the exploration, development and production of
    petroleum and natural gas in British Columbia, Alberta and Saskatchewan.
    The consolidated financial statements are stated in Canadian dollars and
    have been prepared in accordance with Canadian generally accepted
    accounting principles ("GAAP").

    The preparation of financial statements in conformity with GAAP requires
    management to make estimates and assumptions that affect the reported
    amounts of assets and liabilities and disclosure of contingent assets and
    liabilities at the date of the financial statements and the reported
    amounts of revenues and expenses during the year. Actual results could
    differ from those estimates.

    Principles of Consolidation

    The consolidated financial statements include the accounts of the Trust
    and its wholly owned subsidiary.

    Joint Operations

    Substantially all of the exploration, development and production
    activities are conducted jointly with others and accordingly, the Trust
    only reflects its proportionate interest in such activities.

    Measurement Uncertainty

    The amounts recorded for depletion and depreciation of petroleum and
    natural gas property, plant and equipment and the asset retirement
    obligations and related accretion are based on estimates. The cost
    recovery ceiling test is based on estimates of proved reserves,
    production rates, petroleum and natural gas prices, future costs and
    other relevant assumptions. By their nature, these estimates are subject
    to measurement uncertainty and the effect on the financial statements of
    changes in such estimates in future periods could be material.

    Cash and Short-Term Investments

    Cash and short-term investments consist of cash in the bank, less
    outstanding cheques, and short-term deposits with a maturity of less than
    three months.

    Petroleum and Natural Gas Properties

    The Trust uses the full cost method of accounting for petroleum and
    natural gas properties under which all costs related to the acquisition,
    exploration and development of petroleum and natural gas reserves are
    capitalized. Such costs include lease acquisition costs, geological and
    geophysical costs, carrying charges of non-producing properties, costs of
    drilling both productive and non-productive wells, the cost of petroleum
    and natural gas production equipment and overhead charges related to
    exploration and development activities.

    In accordance with the full cost accounting guideline, the Trust
    evaluates its oil and gas assets to determine that the costs are
    recoverable and do not exceed the fair value of the properties. The costs
    are assessed to be recoverable if the sum of the undiscounted cash flows
    expected from the production of proved reserves and the lower of cost and
    market of unproved properties exceed the carrying value of the oil and
    gas assets. If the carrying value of the oil and gas assets is not
    assessed to be recoverable, an impairment loss is recognized to the
    extent that the carrying value exceeds the sum of the discounted cash
    flows expected from the production of proved plus probable reserves and
    the lower of cost and market of unproved properties. The cash flows are
    estimated using the future product prices and costs and are discounted
    using the risk-free rate.

    Proceeds from the disposition of petroleum and natural gas properties are
    applied against capitalized costs except for dispositions that would
    change the rate of depletion and depreciation by 20 percent or more, in
    which case a gain or loss would be recorded.

    Depletion and Depreciation

    Capitalized costs, together with estimated future capital costs
    associated with proved reserves, are depleted and depreciated using the
    unit-of-production method based on estimated proven reserves of petroleum
    and natural gas on a Trust interest basis (working interest plus royalty
    interest) before the deduction of crown and other royalties as determined
    by independent engineers. For purposes of this calculation, reserves and
    production are converted to equivalent units of oil based on a relative
    energy content of six thousand cubic feet of gas to one barrel of oil.
    Costs of significant unproved properties, net of impairments, are
    excluded from the depletion and depreciation calculation.

    Other assets, which are comprised of office equipment and furniture and
    fixtures, are recorded at cost and are depreciated over their useful life
    on a declining balance basis at 20 percent.

    Asset Retirement Obligations

    The Trust records a liability for the fair value of future asset
    retirement obligations in the period in which they are incurred, normally
    when the asset is purchased or developed. On recognition of the liability
    there is a corresponding increase in the carrying amount of the related
    asset within property, plant and equipment, which is depleted on a unit-
    of-production basis over the life of the reserves. Estimates used are
    evaluated on a periodic basis and any adjustments are applied
    prospectively. The liability is adjusted each reporting period to reflect
    the passage of time, with the accretion charged to earnings. Actual costs
    incurred upon settlement of the obligations are charged against the
    liability. No gains or losses on retirement activities were realized due
    to settlements approximating the estimates.

    Goodwill

    Goodwill is recognized on corporate acquisitions when the total purchase
    price exceeds the fair value of the net identifiable assets of the
    acquired company. Goodwill is tested for impairment on an annual basis in
    the fourth quarter. If indications of impairment are present, a loss
    would be charged to earnings for the amount that the carrying value of
    goodwill exceeds its fair value.

    Financial Instruments

    The Trust uses derivative financial instruments from time to time to
    hedge its exposure to commodity price and foreign exchange fluctuations.
    The Trust may enter into crude oil and natural gas swap contracts,
    options or collars to hedge its exposure to petroleum and natural gas
    commodity prices and may enter into foreign exchange forward contracts to
    hedge anticipated US dollar denominated petroleum and natural gas sales.
    The derivative financial instruments are initiated within the guidelines
    of the Trust's risk management policy and the Trust does not enter into
    derivative financial instruments for trading or speculative purposes.

    On January 1, 2007 Progress adopted the new accounting standards
    regarding the recognition, measurement, disclosure and presentation of
    financial instruments. In conjunction with the adoption of these new
    standards, the Trust elected not to use hedge accounting for its natural
    gas derivative contracts under its risk management program. The fair
    value of the commodity contracts is recognized at each reporting period
    with the change in the fair value being classified as an unrealized gain
    or loss on the statement of earnings. In accordance with the transitional
    provisions of the standards, the accounting for hedging relationships for
    prior periods is not retroactively adjusted, therefore, there has been no
    restatement of the prior periods. On adoption, the Trust recognized a
    current asset of $15.6 million for the fair value of its natural gas
    derivative contracts and an increase to the future income tax liability
    and accumulated other comprehensive income of $5.1 million and
    $10.5 million, respectively. The $10.5 million in accumulated other
    comprehensive income was amortized through other comprehensive income and
    unrealized gain or loss on financial instruments on the statement of
    earnings over the term of the contracts. The commodity contracts expired
    in 2007 which resulted in the change in the fair value from January 1,
    2007 of $15.6 million being offset by the amortization of other
    comprehensive income. Contracts entered into by Progress subsequent to
    December 31, 2007 are disclosed in note 11. Certain comparative amounts
    have been reclassified to conform to the presentation adopted in 2007.

    For the year ended December 31, 2007 the Company has early adopted the
    disclosures required under section 3862 Financial Instruments -
    Disclosures which applies to both recognized and unrecognized financial
    instruments. These disclosures, which include the nature and extent of
    risks arising from financial instruments, are included in note 11.

    Revenue Recognition

    Revenues from the sale of petroleum and natural gas are recorded when
    title passes to an external party.

    Income Taxes

    The Trust follows the liability method of accounting for income taxes.
    Temporary differences arising from the differences between the tax basis
    of an asset or liability and its carrying amount on the balance sheet are
    used to calculate future income tax assets or liabilities. Future income
    tax assets or liabilities are calculated using tax rates anticipated to
    apply in the periods that the temporary differences are expected to
    reverse. The benefit of any uncertain tax benefits, if any, are only
    recognized if it is probable that they would be realized.

    The Trust is a taxable entity under the Income Tax Act (Canada) and, for
    periods prior to January 1, 2011, is taxable only on income that is not
    distributed or distributable to the unitholders. On June 12, 2007 the
    federal government's bill regarding the taxation of distributions from
    trusts beginning January 1, 2011 was enacted. Under this new law,
    distributions after January 1, 2011 will not be deductible by the Trust
    for tax purposes. As a result, a $6.6 million future income tax asset was
    recorded in June 2007 to recognize the future tax value for the amount
    the Trust's tax pools exceeded the carrying value of its assets. This
    resulted in a $6.6 million recovery which is included in the future
    income tax provision in the statement of earnings.

    Unit Based Compensation

    The Trust has established a Performance Unit Incentive Plan (the "Plan")
    for employees and directors of the Trust or its subsidiary. The Plan was
    modified in 2007 to include a new long term incentive component ("LTI
    component") for non-executive employees. The Trust uses the fair value
    method for valuing unit based compensation and unit option grants. Under
    this method, compensation cost attributed to performance units granted is
    measured at the fair value at the grant date and expensed over the
    vesting period with a corresponding increase to contributed surplus. Upon
    the settlement of the Plan, the previously recognized value in
    contributed surplus will be recorded as an increase to unitholders'
    capital.

    The Trust has not incorporated an estimated forfeiture rate for
    performance units that will not vest, rather, the Trust accounts for
    actual forfeitures as they occur.

    Per Unit Information

    Per unit information is calculated on the basis of the weighted average
    number of trust units outstanding during the fiscal year. Diluted per
    unit information includes the impact of the issuable exchangeable shares,
    as well as, the potential dilution that could occur if securities or
    other contracts to issue units were exercised or converted to units.
    Diluted per unit information is calculated using the treasury stock
    method that assumes any proceeds received by the Trust upon the exercise
    of in-the-money unit options plus the unamortized unit compensation cost
    would be used to buy back trust units at the average market price for the
    period.

    Exchangeable Securities - Non-Controlling Interest

    The Trust accounts for outstanding exchangeable shares as non-controlling
    interest given exchangeable shareholders can dispose of their shares
    without having to exchange them for trust units. The exchangeable shares
    of the Trust's subsidiary trade on the Toronto Stock Exchange. As a
    result, the exchangeable shares have been classified as non-controlling
    interest on the consolidated balance sheet outside of unitholders'
    equity. Net earnings attributable to the exchangeable shares is charged
    to the consolidated statement of earnings as non-controlling interest
    expense with a corresponding increase to non-controlling interest on the
    consolidated balance sheet.

    Each redemption of exchangeable shares held by previous Progress Energy
    Ltd. shareholders is accounted for as a step-purchase resulting in an
    increase to property, plant and equipment, an increase to unitholders'
    capital and an decrease in the Trust's future income tax asset. The non-
    controlling interest activity for the years ended December 31, 2007 and
    2006 is disclosed in note 7.

    2.  CORPORATE ACQUISITION

    On April 2, 2007 Progress acquired all of the issued and outstanding
    shares of a private company for $527.4 million, net of certain assets
    retained by the vendor. In conjunction with the acquisition, on April 2,
    2007, Progress disposed of certain assets of the private company to ProEx
    for $134.4 million. The resulting net cash consideration of
    $393.0 million was financed by the issuance of 21,000,000 trust units at
    a price of $12.00 per trust unit for proceeds of $252.0 million
    ($238.7 million net of issue costs) and through increased bank debt.
    Included in the acquisition was approximately $720.9 million of tax pools
    which are available to Progress to shelter future taxable income. As a
    result a $137.2 million future income tax asset was recognized on the
    acquisition. Using the purchase method of accounting, the net assets
    acquired and consideration paid were as follows:

    Net assets acquired
    -------------------------------------------------------------------------
    Working capital                                                    3,965
    Bank debt                                                         (9,123)
    Property, plant and equipment                                    266,625
    Future income taxes                                              137,203
    Asset retirement obligations                                      (5,638)
    -------------------------------------------------------------------------
    Total net assets acquired                                        393,032
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Consideration
    -------------------------------------------------------------------------
    Cash                                                             523,166
    Proceeds of asset disposition                                   (134,400)
    Acquisition costs                                                  4,266
    -------------------------------------------------------------------------
    Total purchase price                                             393,032
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    3.  PROPERTY, PLANT AND EQUIPMENT

                                                            2007        2006
    -------------------------------------------------------------------------
    Property, plant and equipment                      1,447,181   1,001,785
    Conversion of exchangeable shares                     47,461      46,014
    Accumulated depletion and depreciation              (439,588)   (303,368)
    -------------------------------------------------------------------------
    Property, plant and equipment, net                 1,055,054     744,431
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    On May 31, 2007 Progress acquired certain petroleum and natural gas
    assets in the Deep Basin region of northwest Alberta for $41.3 million,
    net of final closing adjustments.

    On November 30, 2007, Progress and ProEx jointly acquired certain assets
    in the Foothills region of British Columbia. Progress took a 20 percent
    portion of the assets acquired amounting to $3.6 million.

    In June 2006, the Trust disposed of its assets in the Unity, Saskatchewan
    area to a private company for 2,860,000 common shares valued at $1.20 per
    share for a total consideration of $3.4 million.

    As described in note 1, the redemption of exchangeable shares held by
    previous Progress Energy Ltd. shareholders are accounted for as a step-
    purchase. Consequently, a charge of $1.4 million was made to property,
    plant and equipment for the year ended December 31, 2007
    (2006 - $13.5 million).

    The calculation of 2007 depletion and depreciation included an estimated
    $78.9 million (2006 - $34.5 million) for future development costs
    associated with proved undeveloped reserves and excluded $26.7 million
    (2006 - $24.0 million) for the estimated future net realizable value of
    production equipment and facilities and $96.2 million
    (2006 - $58.2 million) for the estimated value of unproven properties.
    Depletion and depreciation expense for the year ended December 31, 2007
    was $136.2 million (2006 - $93.0 million).

    Included in the Trust's property, plant and equipment balance is
    $20.9 million (2006 - $14.8 million), net of accumulated depletion,
    related to asset retirement obligations ($31.9 million before accumulated
    depletion (2006 - $22.9 million)) (Refer to note 6).

    The Trust capitalized approximately $3.5 million of geological and
    geophysical expenses and compensation costs associated with the
    exploration and development of capital assets during the year ended
    December 31, 2007 (2006 - $2.4 million).

    The Trust performed a ceiling test calculation at December 31, 2007
    resulting in the undiscounted cash flows from proved reserves and the
    lower of cost and market of unproved properties exceeding the carrying
    value of oil and gas assets. The following table summarizes the future
    benchmark prices the Trust used in the ceiling test:

                                       Crude Oil              Natural Gas
    -------------------------------------------------------------------------
                               West Texas       Edmonton
                              Intermediate     Par Price     AECO Gas price
                              (Cdn$/bbl)(1)    (Cdn$/bbl)     (Cdn$/mmbtu)
    -------------------------------------------------------------------------
    2008                          92.00           91.10            6.75
    2009                          88.00           87.10            7.55
    2010                          84.00           83.10            7.60
    2011                          82.00           81.10            7.60
    2012                          82.00           81.10            7.60
    2013-2017(2)                  82.34           81.44            7.96
    Thereafter(3)                  2.0%            2.0%            2.0%
    -------------------------------------------------------------------------
    (1) Future prices incorporated a $1.00 US/Cdn exchange rate.
    (2) Prices shown are the average over the period.
    (3) Percentage change of 2.0% represents the change in future prices each
        year after 2017 to the end of the reserve life.

    4.  BANK DEBT
                                                            2007        2006
    -------------------------------------------------------------------------
    Direct advances                                        1,590           -
    Banker's acceptances                                 295,000      75,000
    -------------------------------------------------------------------------
    Total bank debt                                      296,590      75,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The Trust's credit facilities totaling $375 million are with a syndicate
    of banks consisting of a $340 million extendible revolving term credit
    facility and a $35 million working capital credit facility. The
    facilities are available on a revolving basis for a period of at least
    364 days until May 27, 2008, and such initial term out date may be
    extended for further 364 day periods at the request of the Trust, subject
    to approval by the banks. Following the term out date, the facilities
    will be available on a non-revolving basis for a one year term, at which
    time the facilities would be due and payable. Various borrowing options
    are available under the facilities including prime rate based advances
    and banker's acceptance loans. Average cost of borrowing under these
    facilities for the year ended December 31, 2007 was 5.5 percent
    (2006 - 5.1 percent). The credit facilities are secured by a $1 billion
    fixed and floating charge debenture on the assets of the Trust and by a
    guarantee and subordination provided by Progress Energy Ltd. in respect
    of the Trust's obligations. The $375 million borrowing base is subject to
    semi-annual review by the banks.

    5.  CONVERTIBLE DEBENTURES

    On August 22, 2006 the Trust issued $75.0 million principal amount of
    6.25 percent convertible unsecured subordinated debentures
    (the "6.25 percent debentures") for net proceeds of $71.7 million. The
    6.25 percent debentures pay interest semi-annually and are convertible at
    the option of the holder at any time into fully paid trust units at a
    conversion price of $19.50 per trust unit. The 6.25 percent debentures
    mature on September 30, 2011, at which time they are due and payable.
    The Trust may elect to satisfy the interest and principal obligations by
    the issuance of trust units. The net proceeds were used to reduce
    outstanding bank indebtedness.

    The 6.75 percent convertible unsecured subordinated debentures
    (the "6.75 percent debentures") pay interest semi-annually and are
    convertible at the option of the holder at any time into fully paid trust
    units at a conversion price of $15.00 per trust unit. The 6.75 percent
    debentures mature on June 30, 2010 at which time they are due and
    payable. The Trust may elect to satisfy the interest and principal
    obligations by the issuance of trust units. The net proceeds were used
    to reduce outstanding bank indebtedness.

    The 6.25 percent debentures and the 6.75 percent debentures (the
    "Debentures") have been classified as debt, net of issue costs and net of
    the fair value of the conversion feature at the date of issue which has
    been classified as part of unitholders' equity. The issue costs will be
    amortized over the term of the Debentures and the debt portion will
    accrete up to the principal balance at maturity. The accretion,
    amortization of issue costs and the interest paid are expensed within
    interest and financing expense on the consolidated statements of
    earnings. If the Debentures are converted to units, a portion of the
    value of the conversion feature under unitholders' equity will be
    reclassified to unitholders' capital along with the conversion price
    paid. The following table sets forth a reconciliation of the Debenture
    activity:

                                   2007                       2006
    -------------------------------------------------------------------------
                          6.75%    6.25%    Total    6.75%    6.25%    Total
    -------------------------------------------------------------------------
    Principal, beginning
     of year(1)          55,727   75,000  130,727   86,182   75,000  161,182
    Converted to trust
     units                    -        -        -  (30,455)       -  (30,455)
    -------------------------------------------------------------------------
    Principal, end
     of year             55,727   75,000  130,727   55,727   75,000  130,727
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Debt portion,
     beginning of
     year(1)             52,300   67,305  119,605   79,381   66,748  146,129
    Accretion               508      945    1,453      535      337      872
    Amortization of
     issue costs            466      650    1,116      497      220      717
    Conversions to
     trust units(2)           -        -        -  (28,113)       -  (28,113)
    -------------------------------------------------------------------------
    Debt portion,
     end of year         53,274   68,900  122,174   52,300   67,305  119,605
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Equity portion,
    beginning of
     year(1)              2,756    4,946    7,702    4,261    4,946    9,207
    Conversions to
     trust units              -        -        -   (1,505)       -   (1,505)
    -------------------------------------------------------------------------
    Equity portion,
     end of year          2,756    4,946    7,702    2,756    4,946    7,702
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) The 6.75 percent debentures were issued February 2, 2005 and the
        6.25 percent debentures were issued August 22, 2006.
    (2) Net of unamortized issue costs.

    Total interest charged to earnings for the year ended December 31, 2007
    was $11.0 million (2006 - $7.4 million) which includes $1.5 million of
    debenture accretion (2006 - $0.9 million) and $1.1 million of amortized
    issue costs (2006 - $0.7 million).

    6.  ASSET RETIREMENT OBLIGATIONS

    Asset retirement obligations were estimated based on the Trust's net
    ownership interest in all wells and facilities, the estimated costs to
    abandon and reclaim the wells and facilities and the estimated timing of
    the costs to be incurred in future periods. The total undiscounted
    amount of the estimated cash flows required to settle the asset
    retirement obligations is approximately $75.9 million which will be
    incurred over the next 40 years with the majority of costs incurred
    between 2009 and 2020. A credit adjusted risk-free rate of eight percent
    was used to calculate the fair value of the asset retirement obligations.

    The following reconciles the Trust's asset retirement obligations:

                                                            2007        2006
    -------------------------------------------------------------------------
    Balance, beginning of year                            24,148      20,906
    Liabilities incurred                                   3,523       4,580
    Liabilities settled                                     (713)     (2,714)
    Acquisition (Note 2)                                   5,638           -
    Dispositions                                               -        (374)
    Accretion expense                                      2,416       1,750
    -------------------------------------------------------------------------
    Balance, end of year                                  35,012      24,148
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    7. NON-CONTROLLING INTEREST - EXCHANGEABLE SHARES

    The non-controlling interest on the consolidated balance sheet consists
    of the book value of exchangeable shares issued to Progress Energy Ltd.
    shareholders and the fair value of exchangeable shares issued to Cequel
    Energy Inc. shareholders as part of a Plan of Arrangement that became
    effective on July 2, 2004, plus net earnings attributable to the
    exchangeable shares, less exchangeable shares (and related cumulative
    earnings) redeemed. The non-controlling interest charge on the
    consolidated statement of earnings represents the share of net earnings
    attributable to the exchangeable shares based on the trust units issuable
    for exchangeable shares in proportion to total trust units issued and
    issuable each period end. The activity for non-controlling interest for
    the year ended December 31, 2007 and 2006 is as follows:

                                         2007                    2006
                              ----------------------- -----------------------
    Exchangeable shares           Number      Amount      Number      Amount
    -------------------------------------------------------------------------
    Balance, beginning
     of year                   9,642,540     122,592  11,388,751     127,205
    Exchanged for trust
     units                      (469,457)     (6,132) (1,746,211)    (20,130)
    Non-controlling
     interest expense                          9,924                  15,517
    -------------------------------------------------------------------------
    Balance, end of year       9,173,083     126,384   9,642,540     122,592
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The exchangeable shares can be converted, at the option of the holder,
    into trust units at any time and are listed on the Toronto Stock Exchange
    under the symbol PGE. If the number of exchangeable shares outstanding
    is less than 1,600,000, the Trust can elect to redeem the exchangeable
    shares for trust units or an amount in cash equal to the amount
    determined by multiplying the exchange ratio on the last business day
    prior to the redemption date by the current market price of a trust unit
    on the last business day prior to such redemption date. The number of
    trust units issued upon conversion is based on the exchange ratio in
    effect on the date of conversion. The exchange ratio is calculated
    monthly based on the five day weighted average trust unit trading price
    preceding the monthly effective date. The exchangeable shares are not
    eligible for cash distributions.

    Retraction of Exchangeable Shares

    Shareholders of exchangeable shares may redeem their shares at any time
    by delivering their share certificates to the Trustee, together with a
    properly completed retraction request. The retraction price will be
    satisfied with trust units equal to the amount determined by multiplying
    the exchange ratio on the last business day prior to the retraction date
    by the number of exchangeable shares redeemed.

    Redemption of Exchangeable Shares

    On July 2, 2009 the exchangeable shares will be redeemed by the Trust
    unless the Board of Directors of Progress Energy Ltd. elect to extend the
    redemption period. The exchangeable shares will be redeemed by either
    issuing units or payment in cash for an amount equivalent to the value of
    the exchangeable shares at the current exchange ratio.

    8. UNITHOLDERS' CAPITAL

    The Trust Indenture provides that an unlimited number of trust units may
    be authorized and issued. Each trust unit is transferable, carries the
    right to one vote and represents an equal undivided beneficial interest
    in any distributions from the Trust and in the assets of the Trust in the
    event of termination or winding-up of the Trust. All trust units are of
    the same class with equal rights and privileges.

                                         2007                    2006
                              ----------------------- -----------------------
                                  Number      Amount      Number      Amount
    -------------------------------------------------------------------------
    Trust Units
      Balance, beginning
       of year                75,457,291     739,998  71,302,265     681,263
      Issued for cash(Note 2) 21,000,000     252,000           -           -
      Exchangeable shares
       converted                 640,150       7,150   2,124,705      29,117
      Unit based compensation    381,367       5,102           -           -
      Issued on conversion of
       Debentures                      -           -   2,030,321      29,618
      Unit issue costs(Note 2)               (13,304)                      -
    -------------------------------------------------------------------------
      Balance, end of year    97,478,808     990,946  75,457,291     739,998
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    On June 28, 2007 381,367 units were issued to settle the performance
    units vesting on July 2, 2007, resulting in $5.1 million being
    transferred from contributed surplus to unitholders' capital.

    Management of Capital Structure

    Progress' objectives when managing capital are: (i) to maintain a
    flexible capital structure which optimizes the cost of capital at
    acceptable risk; and (ii) to manage capital in a manner which balances
    the interests of equity and debt holders.

    In the management of capital, Progress includes bank debt, convertible
    unsecured debentures and working capital ("total debt"). Progress
    manages the capital structure and makes adjustments in light of changes
    in economic conditions and the risk characteristics of the underlying
    assets. In order to maintain or adjust the capital structure Progress
    may adjust the amount of distributions paid to unitholders, issue new
    units, issue new debt, issue new debt to replace existing debt with
    different characteristics, adjust exploration and development capital
    expenditures, and acquire or dispose of assets.

    Consistent with the practice of other trusts in the oil and gas sector,
    Progress monitors capital based on the non-GAAP ratio, "total debt-to-
    cash flow from operations (before changes in non-cash working capital)".
    As at December 31, 2007 Progress' ratio of total debt-to-cash flow from
    operations (before changes in non-cash working capital) was 2.1 times
    (2006 - 1.1 times). Total debt-to-cash-flow from operations (before
    changes in non-cash working capital is calculated by dividing total debt
    at the end of the period (comprising of the working capital deficit,
    outstanding bank debt and the debt portion of Progress' convertible
    unsecured debentures) by the 12 month trailing cash flow from operations
    (before changes in non-cash working capital). In 2006, Progress targeted
    a ratio of 1.0 times total debt-to-cash flow from operations (before
    changes in non-cash working capital) to position the Trust to take
    advantage of asset acquisitions.  In the second quarter of 2007, Progress
    completed two significant acquisitions which resulted in a higher ratio
    of total debt-to-cash flow from operations (before changes in non-cash
    working capital). Based on current natural gas prices Progress is
    targeting a total debt-to-cash flow from operations (before changes in
    non-cash working capital) ratio of 1.5 to 2.0 times, slightly below the
    ratio as at December 31, 2007.

    Redemption Right

    Unitholders may redeem their trust units for cash at any time, up to a
    maximum of $250,000 in any calendar month, by delivering their unit
    certificates to the Trustee, together with a properly completed notice
    requesting redemption. The redemption amount per trust unit will be the
    lesser of 90 percent of the simple average closing price of the trust
    units on the principal market on which they are traded for the 10 day
    trading period after the trust units have been validly tendered for the
    redemption and the closing market price of the trust units on the
    principal market on which they are traded on the date on which they were
    validly tendered for redemption, or if there was no trade of the trust
    units on that date, the average of the last bid and ask prices of the
    trust units on that date.

    Net Earnings Per Unit

    The following table summarizes the weighted average trust units used in
    calculating net earnings per unit:


                                                            2007        2006
    -------------------------------------------------------------------------
    Weighted average trust units - basic              91,823,317  74,536,584
    -------------------------------------------------------------------------
    Trust units issuable on conversion of
     exchangeable shares(1)                           13,542,906  13,267,333
    Performance units                                    676,151     477,461
    -------------------------------------------------------------------------
    Weighted average trust units - diluted           106,042,374  88,281,378
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Calculated based on the weighted average exchangeable shares
        outstanding during the year at the year end exchange ratio.

    An adjustment to the numerator of $9.9 million for the year ended
    December 31, 2007 (2006 - $15.5 million) is required in the diluted
    earnings per unit calculation to provide for earnings attributable to
    non-controlling interest. Units potentially issuable on the conversion
    of the Debentures are anti-dilutive and are not included in the
    calculation of diluted weighted average units for the years ended
    December 31, 2007 and 2006.

    Performance Unit Incentive Plan

    The Trust has established a Performance Unit Incentive Plan (the "Plan")
    for employees and directors of the Trust or its subsidiary that includes
    both performance units and units under a long term incentive component.
    The number of units reserved for issuance under the Plan shall not exceed
    5 percent of the aggregate number of issued and outstanding units of the
    Trust and including the number of units which may be issued on the
    exchange of the outstanding exchangeable shares, which may be converted
    into trust units.

    Performance Units

    Under the Plan, performance units shall be granted by the Board of
    Directors of Progress Energy Ltd. from time to time at its sole
    discretion. The performance units will vest on the third anniversary of
    the date of grant and actual payment will be determined based on the
    performance of the Trust relative to its peers. Performance factors
    range from 0.5 to 1.5 times the initial performance units granted except
    for performance units granted to the Trust's executives effective in
    2007 which can range from 0 to 3 times. Over the three year term the
    performance units will attract distributions. The Trust expects to pay
    out the distribution portion in cash while the units earned will be
    issued from treasury.

    Long Term Incentive Component

    During 2007, the Plan was modified to include a new long term incentive
    component ("LTI component") for non-executive employees. Awards granted
    under the LTI component of the Plan will vest over three years with
    40 percent vesting on the second anniversary of the date of grant and
    60 percent vesting on the third anniversary of the date of grant. An
    additional 15 percent grant will be paid if the holder holds the units
    received on the second anniversary date for one additional year. As at
    December 31, 2007, 189,485 units are outstanding under the LTI component
    at an average value of $14.00 per unit, resulting in a total compensation
    cost of $2.7 million of which $2.3 million will be recognized through
    unit based compensation expense and $0.4 million will be capitalized over
    the vesting period.

    On June 28, 2007 381,367 units were issued to settle the performance
    units that vested on July 2, 2007, resulting in $5.1 million being
    transferred from contributed surplus to unitholders' capital.

    As at December 31, 2007 there are 481,800 performance units outstanding
    that were granted in 2005. During 2007 the estimated performance factor
    for this grant was increased from 1.0 to 1.5 based on the Trust's
    operating performance. The fair value of the performance units using a
    performance factor of 1.5 is approximately $10.9 million of which
    $9.6 million will be amortized through unit based compensation expense
    and $1.3 million will be capitalized over the vesting period with a
    corresponding increase to contributed surplus. Actual performance
    factors will not be determined until the end of the performance period.

    As at December 31, 2007 there are 401,850 performance units outstanding
    that were granted in 2006. During 2007 the estimated performance factor
    for this grant was increased from 1.0 to 1.5 based on the Trust's
    operating performance. The fair value of the performance units using a
    performance factor of 1.5 is approximately $9.1 million of which
    $8.0 million will be amortized through unit based compensation expense
    and $1.1 million will be capitalized over the vesting period with a
    corresponding increase to contributed surplus. Actual performance
    factors will not be determined until the end of the performance period.

    As at December 31, 2007 there are 504,550 performance units outstanding
    that were granted in 2007. The fair value of the performance units using
    a performance factor of 1.0 is approximately $6.5 million of which
    $5.8 million will be amortized through unit based compensation expense
    and $0.7 million will be capitalized over the vesting period with a
    corresponding increase to contributed surplus.

    For the year ended December 31, 2007 $9.0 million (2006 - $4.9 million)
    was charged to unit based compensation expense and $1.9 million
    (2006 - $0.8 million) was capitalized relating to the total performance
    units and units under the LTI component outstanding.

                                                            2007        2006
    -------------------------------------------------------------------------
    Performance Units
    Balance, beginning of year                         1,300,717     899,567
    Granted                                              521,450     424,950
    Settled                                             (381,367)          -
    Forfeited                                            (52,600)    (23,800)
    -------------------------------------------------------------------------
    Balance, end of year                               1,388,200   1,300,717
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Vesting Date
    2007                                                       -     380,567
    2008(1)                                              481,800     512,300
    2009(1)                                              401,850     407,850
    2010                                                 504,550           -
    -------------------------------------------------------------------------
    Total                                              1,388,200   1,300,717
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Using the current anticipated performance factor of 1.5 times,
        722,700 units and 602,775 units, respectively, will be issued on the
        vesting of the 2008 and 2009 performance units.

                                                            2007        2006
    -------------------------------------------------------------------------
    Units under LTI Component
    Balance, beginning of year                                 -           -
    Granted                                              198,629           -
    Forfeited                                             (9,144)          -
    -------------------------------------------------------------------------
    Balance, end of year                                 189,485           -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Vesting Date
    2009                                                  75,794           -
    2010                                                 113,691           -
    -------------------------------------------------------------------------
    Total(1)                                             189,485           -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) If the units vesting in 2009 are held by the LTI holder until 2010,
        one year after date of vesting, an additional 28,423 units will be
        issued by the Trust.

    Contributed Surplus

    The following table reconciles the Trust's contributed surplus:

                                                            2007        2006
    -------------------------------------------------------------------------
    Balance, beginning of year                             9,210       3,530
    Unit based compensation expense                        9,037       4,874
    Unit based compensation capitalized                    1,323         806
    Settlements                                           (5,102)          -
    -------------------------------------------------------------------------
    Balance, end of year                                  14,468       9,210
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Accumulated other comprehensive income

    As described in note 1, the adoption of the new accounting policies
    regarding financial instruments resulted in an amount being recognized in
    accumulated other comprehensive income for the fair value of the Trust's
    natural gas derivative contracts at January 1, 2007. The amount
    recognized in accumulated other comprehensive income was $10.5 million,
    representing the value of the asset of $15.6 million net of future income
    taxes of $5.1 million. The amount was charged to the statement of
    earnings over the term of the contracts with a corresponding decrease to
    other comprehensive income.

                                                            2007        2006
    -------------------------------------------------------------------------
    Balance, beginning of year                                 -           -
    Change in accounting policy, net of
     tax of $5,072(Note 1)                                10,543           -
    Amortization of fair value of financial
     instruments, net of tax                             (10,543)          -
    -------------------------------------------------------------------------
    Balance, end of period                                     -           -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    9. FUTURE INCOME TAXES

    The Trust is a taxable entity under the Income Tax Act (Canada) and, for
    periods prior to January 1, 2011, is taxable only on income that is not
    distributed or distributable to the unitholders. On June 12, 2007 the
    federal government's bill regarding the taxation of distributions from
    trusts beginning January 1, 2011 was enacted. Under this new law,
    distributions after January 1, 2011 will not be deductible by the Trust
    for tax purposes. As a result, a $6.6 million future income tax asset
    was recorded in June 2007 to recognize the future tax value for the
    amount the Trust's tax pools exceeded the carrying value of its assets.
    This resulted in a $6.6 million recovery which is included in the future
    income tax provision in the statement of earnings. Cash distributions
    for the year ended December 31, 2007 totaled $114.1 million
    (2006 - $125.6 million), reducing the Trust's expected future income tax
    expense for the year.

    Included in the 2007 provision is a loss of $2.3 million relating to a
    reduction in future federal income tax rates, which reduces the value of
    Progress' future income tax asset. Included in the 2006 provision is a
    recovery of $9.2 million relating to a reduction in future federal and
    provincial tax rates enacted during the year, which reduced the value of
    Progress future income tax liability at that time, and the impact of
    certain tax balance adjustments.

    The provision for future income taxes in the consolidated statements of
    earnings reflect an effective tax rate which differs from the expected
    statutory tax rate. Differences were accounted for as follows:

                                                            2007        2006
    -------------------------------------------------------------------------
    Earnings before taxes                                 65,392      92,622
    Statutory income tax rate                               32.5%       34.8%
    -------------------------------------------------------------------------
    Expected income taxes                                 21,252      32,232
    Add (deduct)
      Net income of the Trust(1)                         (16,037)    (39,660)
      Taxable income designated to Unitholders(1)        (18,506)          -
      Change in tax law(1)                                (6,589)          -
      Non-deductible crown charges                             -       7,940
      Resource allowance                                       -      (7,470)
      Reduction in income tax rates and certain
       tax balance adjustments                             2,344      (9,212)
      Income tax audit adjustments                             -         129
      Attributed Canadian Royalty Income                       -        (216)
      Other                                                2,675       1,584
    -------------------------------------------------------------------------
                                                         (14,861)    (14,673)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Prior to June 2007, no future income taxes were recognized for the
        Trust (only future income taxes relating to the Trust's subsidiary
        were recognized). Consequently all income of the Trust had no future
        income tax implications and therefore was a reconciling item to the
        expense on the statement of earnings. As a result of the law enacted
        in June 2007, future income taxes are now recognized at the Trust
        level and therefore, after June 2007, only the taxable portion of
        distributions to unitholders is included in the reconciliation above.

    The future income taxes liability at December 31 is comprised of the tax
    effect of temporary differences as follows:

                                                            2007        2006
    -------------------------------------------------------------------------
    Property, plant and equipment                         16,190    (124,460)
    Asset retirement obligations                           8,897       7,268
    Non capital losses                                     6,047           -
    Commodity sales contracts                                111         260
    Share issue costs                                        641         138
    Attributed Canadian Royalty Income                     4,830       2,427
    -------------------------------------------------------------------------
                                                          36,716    (114,367)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    As at December 31, 2007, the Trust's corporate subsidiary, Progress
    Energy Ltd., has federal tax pools of $1.1 billion (2006 -
    $268.0 million) available for deduction against future taxable income.
    The Trust currently has tax pools available of $93.7 million.

    The following are the combined tax pools available for the Trust and its
    corporate subsidiary:

                                                                        2007
    -------------------------------------------------------------------------
    Canadian exploration expense                                     515,000
    Canadian development expense                                     222,000
    Canadian oil and gas property expense                            159,000
    Undepreciated capital cost                                       224,000
    Non-capital losses                                                17,000
    Share issue costs                                                 15,000
    Attributed Canadian Royalty Income                                61,000
    -------------------------------------------------------------------------

    10. SUPPLEMENTAL CASH FLOW INFORMATION

    Changes in non-cash working capital

                                                            2007        2006
    -------------------------------------------------------------------------
    Accounts receivable                                   14,696      10,315
    Prepaid expenses and deposits                         (1,349)        778
    Accounts payables                                     (5,746)     (9,084)
    Current income taxes payable                              44         192
    -------------------------------------------------------------------------
    Change in non-cash working capital                     7,645       2,201
    Relating to:
    Investing activities                                   1,506       2,371
    -------------------------------------------------------------------------
    Operating activities                                   6,139        (170)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Interest and taxes paid

                                                            2007        2006
    -------------------------------------------------------------------------
    Interest paid                                         21,564       8,641
    Income and other taxes paid                               82         182
    -------------------------------------------------------------------------

    11. FINANCIAL INSTRUMENTS

    Fair Value of Financial Instruments

    The Trust's financial instruments recognized on the balance sheet consist
    of accounts receivable, accounts payable and accrued liabilities, bank
    debt and convertible debentures. The fair value of these instruments,
    excluding the convertible debentures, approximate their carrying amounts
    due to their short terms to maturity or the indexed rate of interest on
    the bank debt. The fair value of the convertible debentures outstanding
    as at December 31, 2007, based on quoted market prices, was approximately
    $123.0 million (2006 - $130.2 million). From time to time Progress
    enters into derivative natural gas contracts ("financial instruments")
    however, at December 31, 2007 there were no natural gas contracts
    outstanding.

    Credit risk

    The Trust's accounts receivable are with customers and joint venture
    partners in the petroleum and natural gas business and are subject to
    normal credit risks. Concentration of credit risk is mitigated by
    marketing production to numerous purchasers under normal industry sale
    and payment terms. The Trust routinely assesses the financial strength
    of its customers.

    The Trust may be exposed to certain losses in the event of non-
    performance by counterparties to commodity price contracts. The Trust
    mitigates this risk by entering into transactions with highly rated major
    financial institutions.

    At December 31, 2007, financial assets on the balance sheet are comprised
    of accounts receivables and a $4.1 million equity investment in a private
    company within prepaid expenses and deposits. There were no natural gas
    derivative contracts outstanding at December 31, 2007. The investment in
    the private company is classified as an available for sale financial
    asset, however as there is no quoted market price in an active market,
    the investment is measured at cost.

    The maximum credit exposure at December 31, 2007 is the carrying amount
    of accounts receivable of $47.5 million. As is common in the petroleum
    and natural gas industry in western Canada, receivables relating to the
    sale of petroleum and natural gas are received on or about the 25th day
    of the following month. The Trust markets its production to customers
    with investment grade credit ratings, if available in the area of
    production, or seeks parental guarantees and letters of credit. Of the
    $47.5 million accounts receivable outstanding, $36.2 related to the sale
    of petroleum and natural gas and was received January 25, 2008. The
    accounts receivable balance includes $7.6 million from joint venture
    partners relating to the recovery of their interest in operating costs
    and capital spent. The largest amount owing from one partner was
    $1.4 million. As the operator of properties, Progress has the ability to
    not allocate production to joint venture partners who are in default of
    amounts owing. At December 31, 2007 there was no material allowance for
    the impairment of accounts receivable.

    Currency risk

    The Trust does not sell or transact in any foreign currency, however, the
    United States dollar influences the price of petroleum and natural gas
    sold in Canada. Price fluctuations, as a result, can affect the fair
    value and future cash flows of derivative natural gas contracts, however,
    given it is an indirect influence, the impact of changing exchange rates
    cannot be quantified. There were no derivative natural gas contracts
    outstanding at December 31, 2007. The Trust's other financial assets and
    liabilities are not directly affected by a change in currency rates.

    Interest rate risk

    The Trust is exposed to interest rate risk on its outstanding bank debt
    and Debentures. The bank debt has a floating interest rate and
    consequently changes to interest rates would impact the Trust's future
    cash flows. The Company had no interest rate swaps or hedges at
    December 31, 2007. Changes in market interest rates will result in
    fluctuations to the fair value of the Debenture's given their fixed
    interest rates.

    Liquidity risk

    Liquidity risk relates to the risk the Trust will encounter difficulty in
    meeting obligations associated with its financial liabilities. The
    financial liabilities on its balance sheet consist of accounts payable,
    bank debt and the Debentures. The credit facilities are available on a
    revolving basis for a period of at least 364 days until May 27, 2008, and
    such initial term out date may be extended for further 364 day periods at
    the request of the Trust, subject to approval by the banks. Following
    the term out date, the facilities will be available on a non-revolving
    basis for a one year term, at which time the facilities would be due and
    payable. The Debentures mature in June 2010 and September 2011. The
    Trust anticipates it will continue to have adequate liquidity to fund its
    financial liabilities through its future cash flows (see also "Management
    of Capital Structure" in note 8). The Trust had no defaults or breaches
    on its bank debt or any of its financial liabilities.

    Market risk

    Market risk is comprised of currency risk, interest rate risk and other
    price risks which consist primarily of fluctuations in petroleum and
    natural gas prices. The valuation of the financial assets and
    liabilities on the balance sheet at December 31, 2007 would not be
    directly impacted by changes in currency rates. Currency rates influence
    petroleum and natural gas prices, however this influence on commodity
    prices and the resulting impact on financial assets and liabilities
    cannot be accurately quantified. In regards to interest rate risk, an
    increase or decrease of one percent to the effective interest rate for
    the Trust would have impacted net earnings by $1.5 million for the year.
    In regards to commodity prices, a one dollar change in the price per
    barrel of crude oil would have impacted net earnings by $0.5 million and
    a $0.25 change to the price per thousand cubic feet of natural gas would
    have impacted net earnings by $7.2 million.

    Commodity Price Contracts

    There were no derivative natural gas financial instruments outstanding as
    at December 31, 2007. Subsequent to December 31, 2007 the Trust entered
    into several derivative financial instruments for the purpose of
    protecting its cash flow from operations before changes in non-cash
    working capital from the volatility of natural gas prices. For the year
    ended December 31, 2007, the Trust's natural gas price risk management
    program had a net gain of $16.1 million (2006 - $29.9 million).

    As described in note 1, the Trust recognizes the fair value of its
    commodity price contracts on the balance sheet each reporting period with
    the change in fair value being recognized as an unrealized gain or loss
    on the statement of earnings. On January 1, 2007 the fair value of the
    commodity price contracts was an asset of $15.6 million and resulted in
    an increase to accumulated other comprehensive income and the future
    income tax liability of $10.5 million and $5.1 million, respectively.
    The $10.5 million recognized in accumulated other comprehensive income
    was amortized over the term of the contracts through other comprehensive
    income with a corresponding unrealized gain on financial instruments on
    the statement of earnings. As a result, for the year ended December 31,
    2007 $10.5 million, net of tax, was charged to other comprehensive income
    with a corresponding unrealized gain on financial instruments of
    $15.6 million and a charge to future income tax expense of $5.1 million.
    The unrealized gain of $15.6 million was offset by the change in fair
    value from January 1, 2007 of $15.6 million resulting in an unrealized
    gain of nil for 2007.

    Contracts entered into subsequent to December 31, 2007 are as follows:

    Natural Gas               Pricing        Strike      Cost/
    Contracts(1)       Volume   Point  Price $/gj(1)   Premium          Term
    -------------------------------------------------------------------------
                                                                  April 1 to
    Fixed Price                                                   October 31,
     Swap         10,000 gj/d   AECO       6.70              -          2008
                                                                  April 1 to
    Fixed Price                                                   October 31,
     Swap         10,000 gj/d   AECO       6.78              -          2008
                                                                  April 1 to
    Swap -                                                        October 31,
     call spread  10,000 gj/d   AECO  $7.50 - $8.50  $0.365/gj          2008
                                                                  April 1 to
    Swap -                                                        October 31,
     call spread  10,000 gj/d   AECO  $7.39 - $8.39   $0.37/gj          2008
                                                                  April 1 to
    Swap -                                                        October 31,
     call spread  10,000 gj/d   AECO $7.095 - $8.095 $0.355/gj          2008
                                                                  April 1 to
    Swap -                                                        October 31,
     call spread  10,000 gj/d   AECO  $7.13 - $8.13  $0.355/gj          2008
                                                                  April 1 to
    Swap -                                                        October 31,
     call spread  10,000 gj/d   AECO  $7.23 - $8.23  $0.355/gj          2008
                                                                  April 1 to
    Swap -                                                        October 31,
     call spread   5,000 gj/d   AECO  $7.21 - $8.21  $0.360/gj          2008
                                                                  April 1 to
    Swap -                                                        October 31,
     call spread   5,000 gj/d   AECO  $7.24 - $8.24  $0.360/gj          2008
    -------------------------------------------------------------------------
    (1) Call spread strike prices indicate minimum floor and maximum ceiling

    12. COMMITMENTS

    The Trust is committed to future minimum payments for natural gas
    transportation contracts, drilling rig agreements, compressor rentals and
    office space. The Trust's extendible term credit facility is available
    on a revolving basis until May 27, 2008. This initial term out date may
    be extended for a further 364 day period at the request of the Company,
    subject to approval by the banks. Following the term out date, the
    facilities will be available on a non-revolving basis for a one year
    term. Without assuming the renewal of the credit facilities payments
    required under these commitments for each of the next five years are:
    2008 - $23.6 million; 2009 - $311.4 million; 2010 - $66.7 million; 2011 -
    $82.8 million; and 2012 - $1.3 million. Future commitments related to
    bank debt and the Debentures are disclosed in notes 4 and 5,
    respectively.



                     2007 SELECTED QUARTERLY INFORMATION

    FINANCIAL HIGHLIGHTS            Three Months Ended 2007           Annual
    ($ thousands except    --------------------------------------------------
     per unit amounts)      March 31   June 30  Sept. 30   Dec. 31      2007
    -------------------------------------------------------------------------

    Income Statement
    Petroleum and natural
     gas revenue              85,477   108,503    88,480    99,592   382,052
    Cash flow(1)              53,080    58,398    48,085    54,727   214,290
      Per unit - diluted        0.60      0.53      0.43      0.49      2.02
    Cash distributions
     declared                 24,831    29,092    30,987    29,232   114,142
      Per unit                  0.30      0.30      0.30      0.30      1.20
    Net earnings              16,425    31,947    11,909     9,922    70,203
      Per unit - basic          0.22      0.33      0.12      0.10      0.76
      Per unit - diluted        0.22      0.33      0.12      0.10      0.76

    Payout Ratio
    Excluding exchangeable
     shares                      47%       50%       64%       53%       53%
    Including exchangeable
     shares                      54%       56%       73%       61%       61%

    Balance Sheet
    Exploration and
     development capital      43,384    14,677    31,726    47,210   136,997
    Net property acquisitions
     (dispositions)              217    41,157    (8,293)    3,295    36,375
    -------------------------------------------------------------------------
    Total capital
     expenditures             43,601    55,834    23,433    50,505   173,372
    Corporation
     Acquisition(3)                -   389,363         -     3,669   393,032
    Total debt               252,000   410,696   417,678   444,223   444,223
    Unitholders' equity      689,909   933,606   916,357   900,806   900,806

    Trust Units (thousands
     except where otherwise
     stated)
    Units outstanding,
     end of period            75,799    97,262    97,344    97,479    97,479
    Units issuable for
     exchangeable shares      12,665    12,859    13,093    13,302    13,302
    -------------------------------------------------------------------------
    Total units outstanding
     and issuable for
     exchangeable shares,
     end of period            88,464   110,121   110,437   110,781   110,781
    Weighted average units -
     diluted(2)               89,039   109,965   110,936   111,413   106,042
    Exchange ratio,
     end of period           1.34944   1.37885   1.41278   1.45015   1.45015

    Trust Unit Trading
     Statistics ($)
    High                       13.29     15.79     13.44     12.25     15.79
    Low                        11.00     12.76     10.96      9.92      9.92
    Closing                    13.07     12.93     12.03     10.85     10.85
    Unit volume traded
     (thousands)              23,116    23,310    25,679    20,726    92,831

    Exchangeable Shares
     Trading Statistics ($)
    High                       17.50     20.50     18.15     17.00     20.50
    Low                        14.84     17.90     15.01     14.50     14.50
    Closing                    17.60     18.60     16.51     15.15     15.15
    Share volume traded
     (thousands)                  13        27        92       104       236

    (1) See discussion in the Management Discussion and Analysis
    (2) Includes exchangeable shares converted at the end of period exchange
        ratio.
    (3) Net of the disposition of assets to ProEx.



                     2007 SELECTED QUARTERLY INFORMATION

    Operational Highlights          Three Months Ended 2007           Annual
                           --------------------------------------------------
                            March 31   June 30  Sept. 30   Dec. 31      2007

    Daily Production
      Natural gas (mcf/d)     94,351   127,255   120,804   123,740   116,630
      Crude oil (bbls/d)       2,118     2,134     2,268     2,068     2,147
      Natural gas liquids
       (bbls/d)                1,379     1,485     1,370     1,548     1,446
      Total daily production
       (boe/d)                19,222    24,828    23,772    24,240    23,031

    Average Realized Prices
      Natural gas ($/mcf)       7.87      7.52      5.77      6.49      6.85
      Crude oil ($/bbl)        62.15     68.37     78.77     81.67     72.86
      Natural gas liquids
       ($/bbl)                 55.08     60.51     62.91     71.51     62.77

    Highlights ($/boe)
      Weighted average
       sales price             49.41     48.03     40.46     44.66     45.45
      Realized gain on
       financial instruments    4.04      0.08      2.89      1.14      1.91
      Royalties               (11.67)   (10.51)    (8.80)    (9.54)   (10.04)
      Operating expenses       (6.38)    (6.57)    (6.67)    (5.91)    (6.38)
      Transportation expenses  (1.60)    (1.85)    (1.96)    (1.86)    (1.83)
    -------------------------------------------------------------------------
      Operating Netbacks       33.80     29.18     25.92     28.49     29.11
      Other Income                 -      0.09      0.01         -      0.02
      General and
       administrative expense  (1.14)    (1.02)    (1.12)    (0.90)    (1.04)
      Unit based compensation  (0.86)    (1.13)    (1.09)    (1.16)    (1.08)
      Interest and financing
       expenses                (2.19)    (2.61)    (2.88)    (3.16)    (2.74)
      Unrealized gain/(loss)
       on financial
       instruments             (4.76)     4.65     (0.27)    (0.75)        -
      Depletion, depreciation
       and accretion          (14.91)   (16.94)   (17.08)   (16.70)   (16.49)
    -------------------------------------------------------------------------
      Net earnings before
       taxes                    9.94     12.22      3.49      5.82      7.78
      Capital taxes            (0.03)    (0.02)    (0.02)    (0.01)    (0.02)
      Future income taxes
       recovery/(expense)       1.16      3.82      2.71     (0.76)     1.77
      Non-controlling interest
       - exchangeable shares   (1.58)    (1.88)    (0.73)    (0.60)    (1.18)
    -------------------------------------------------------------------------
      Net Earnings              9.49     14.14      5.45      4.45      8.35
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Drilling Results
      Gross                       30         6        17        39        92
      Net - natural gas         11.7       4.7       9.3      19.3      45.0
      Net - crude oil              -         -         -         -         -

      Success Rate (percent)      87       100       100        96        95

    





For further information:

For further information: Mr. Michael Culbert, President & CEO; Mr. Greg
Kist, Vice President Investor Relations & Marketing; Progress Energy Trust,
1200, 205 - 5th Avenue S.W., Calgary, Alberta, T2P 2V7, Phone: (403) 539-1809,
Fax: (403) 216-2514, Email: ir@progressenergy.com, Web:
www.progressenergy.com

Organization Profile

Progress Energy Canada Ltd.

More on this organization


Custom Packages

Browse our custom packages or build your own to meet your unique communications needs.

Start today.

CNW Membership

Fill out a CNW membership form or contact us at 1 (877) 269-7890

Learn about CNW services

Request more information about CNW products and services or call us at 1 (877) 269-7890