ProEx Energy increases reserves by 68% in 2007



    Production replaced 787% on a proved plus probable basis

    CALGARY, Feb. 26 /CNW/ - ProEx Energy Ltd. ("ProEx" or the "Company")
announces today the operational and financial results for the year ended
December 31, 2007.

    
    2007 ACCOMPLISHMENTS

    Reserves

    -   Total proved plus probable reserves at December 31, 2007 increased
        68 percent to 52.9 million boe compared to 31.5 million boe in 2006.

    -   Total proved reserves at December 31, 2007 increased 65 percent to
        35.7 million boe compared to 21.7 million boe in 2006.

    -   Proved plus probable reserves per thousand basic shares increased
        26 percent over the prior year while proved plus probable reserves
        per one thousand diluted shares increased 32 percent during the same
        period.

    -   Reserve growth in 2007 was achieved through the exploration and
        development program as well as two strategic acquisitions during the
        year. The 2007 capital investment of $302.7 million was divided
        approximately 50 percent each between exploration and development
        activities and acquisitions.

    -   The 2007 activity replaced 787 percent of production on a proved plus
        probable basis and 553 percent on a proved basis.

    -   Since July 2004, when the Company commenced operations, ProEx has
        booked approximately 340 bcf equivalent of proved plus probable
        reserves primarily in the Foothills project area.

    -   ProEx's net asset value per share at December 31, 2007 was $14.35 per
        basic share and $13.25 per diluted share ($11.90 and $10.49
        respectively per share in 2006) using GLJ forecasted prices
        discounted at eight percent.

    Capital Efficiency

    -   Finding and development costs ("F&D"), which represents the
        efficiency of the Company's ongoing exploration and development
        program, related to the total 2007 capital program (including
        technical revisions and the change in future development capital)
        were $16.60 per boe proved and $12.33 per boe proved plus probable.
        This translates into a recycle ratio of 2.14 times on a proved plus
        probable basis.

    -   Finding, development and net acquisition costs ("FD&A") related to
        the total 2007 capital program which includes the asset acquisitions
        (including technical revisions and the change in future development
        capital) were $19.70 per boe proved and $14.29 per boe proved plus
        probable.

    -   The cumulative F&D costs since inception of the Company (including
        technical revisions and the change in future development capital) for
        the period July 1, 2004 to December 31, 2007 are $14.69 per boe
        proved and $11.00 per boe proved plus probable. The cumulative FD&A
        costs since inception of the Company (including change in future
        development capital) for the period July 1, 2004 to December 31, 2007
        are $16.31 per boe proved and $12.06 per boe proved plus probable.

    Operations

    -   Average 2007 production was 8,509 boe per day compared to 5,285 boe
        per day during the same period in 2006, an increase of 61 percent
        while production per diluted share increased 28 percent during the
        same period.

    -   2007 fourth quarter production averaged 9,680 boe per day compared to
        6,080 boe per day in the fourth quarter of 2006, an increase of
        59 percent while production per diluted share increased 25 percent
        during the same period.

    -   Natural gas production was 52,917 mcf per day during the fourth
        quarter of 2007 compared to 33,505 mcf per day in the fourth quarter
        of 2006.

    -   Crude oil and natural gas liquids production averaged 860 bbls per
        day during the fourth quarter of 2007 compared to 495 bbls per day in
        the fourth quarter of 2006.

    -   The Company drilled 70 gross wells (45.5 net) during the year with a
        93 percent net success rate, resulting in 64 natural gas wells
        (42.3 net).

    -   During the year, the Company increased net undeveloped land to
        433,000 net acres from 271,000 net acres at December 31, 2006. At
        December 31, 2007 undeveloped lands under the control of ProEx,
        including option acreage, is approximately 465,000 acres.

    Financial

    -   Petroleum and natural gas revenue increased 57 percent to
        $132.2 million for the year compared to $84.0 million during the
        prior year.

    -   Average natural gas prices for 2007 were $6.64 per mcf down from
        $6.84 per mcf in 2006.

    -   Funds generated from operations increased 70 percent to $73.8 million
        ($1.40 per diluted share) for the year compared to $43.5 million
        ($1.04 per diluted share) during the prior year resulting in a
        35 percent increase to funds generated from operations per diluted
        share.

    -   Net earnings for the year was $20.1 million ($0.38 per diluted share)
        a 32 percent increase over the $15.2 million ($0.36 per diluted
        share) recorded in the prior year.

    -   Capital investment for 2007, excluding net property acquisitions
        (dispositions), was $150.2 million, slightly lower than the prior
        year at $151.5 million. Total capital investment, including the two
        strategic Foothills acquisitions during the year was $302.7 million
        compared to $152.2 million in 2006.

    -   Bank debt and working capital deficiency was $111.0 million at
        December 31, 2007 on a $185 million demand revolving operating credit
        facility available at year end.

    2008 Activity Update

    -   The Company commenced operations in January with six rigs operating
        in the foothills and currently has four rigs operating. Drilling
        operations are scheduled to be completed in mid March with the
        balance of the activity until break up to consist of well completions
        and well tie-ins.

    -   Current production is approximately 11,300 boe per day and program
        results are on track for production to reach approximately 13,000 boe
        per day by early April.
    

    Exploration and Development Activity

    Activity was concentrated almost entirely in the foothills areas during
2007 primarily at Sasquatch, Bernadet, Julienne, Buckinghorse/Caribou, Bubbles
and Altares project properties. The Company drilled 70 gross wells (45.5 net
wells) during the year resulting in 64 gas wells (42.3 net gas wells) and 6
dry holes (3.2 net dry holes) for an overall success rate of 91 percent (93
percent net).
    The Company continued to build its undeveloped land position through
crown sales, strategic asset acquisitions and farm in activity. At
December 31, 2007 the Company had access to approximately 465,000 acres of
undeveloped lands and had identified approximately 300 locations on these
lands that at the current pace of capital investment amount to over three
years of forward inventory. The Company also has an extensive seismic
inventory with over 2,000 square kilometers of contiguous seismic over its
foothills lands. During the first quarter of 2008 the shooting of a new
200 square kilometer program in the Caribou/Buckinghorse area will be
completed which will provide drilling opportunities for 2009 and beyond. In
January 2008 the Company acquired the remaining 50 percent working interest in
11,520 acres of undeveloped land at Caribou by swapping its 50 percent working
interest in 5,120 acres of undeveloped land at Green. At the February 2008
British Columbia land sale the Company acquired 6,400 acres of Debolt mineral
rights at Caribou/Buckinghorse further adding to the potential inventory of
opportunities.
    The Caribou/Bubbles acquisition in the second quarter of 2007 added
approximately 2,000 boe per day of production and 80,000 net acres of
undeveloped land but more importantly expanded our footprint northward in the
British Columbia foothills. The Bubbles area is predominantly a development
and optimization project while the Caribou block has provided the Company with
numerous Halfway and Debolt opportunities. The Caribou lands included one
producing Debolt well, three non-producing Halfway wells and one non-producing
Slave Point well. To date the Company has drilled six Halfway and three Debolt
discovery wells on the Caribou block. Facility infrastructure will be
developed during 2008 to tie-in some of the stranded Halfway wells in addition
to the new discoveries.
    Effective November 30, 2007 the Company acquired an area competitor's
position at Blair and Cameron. This acquisition added approximately 250 boe
per day of production and approximately 32,000 net acres of undeveloped land.
This area is highly prospective for Cretaceous sweet gas accumulations and
includes well developed infrastructure. We have identified a significant
number of drilling locations after reprocessing existing 3D data and
integrating this data into our knowledge of the morphology of the reservoirs
throughout the region.
    During the first quarter of 2008 the Company expects to drill
approximately 20 to 25 wells primarily at Julienne, Caribou, Sasquatch,
Bubbles and Bernadet. The first quarter will see two horizontal wells drilled,
the first into the Gething sandstones at Julienne and secondly at Bernadet
into the Coplin dolomites. A further 2 to 3 more horizontal wells will be
drilled during 2008.
    During the first quarter of 2008, the Company also undertook a number of
facility projects which are either being completed or are underway including:

    
    (1) Following the drilling success at Sasquatch during the fourth quarter
        of 2007 and the first quarter of 2008, the Company expanded its
        Dogrib facility adding a compressor which has increased the capacity
        of the plant to 18 mmcf per day.
    (2) A 7.2 kilometer pipeline at Caribou that requires two river crossings
        with each requiring over a one kilometer bore under the two rivers
        will be completed in the first quarter. The first phase of the
        Caribou pipeline was completed in the fourth quarter and consisted of
        a 10 kilometer section from the Keyera-Caribou gas plant.
    (3) Building a line loop at Julienne to ease back pressure from increased
        volumes. This project will be completed late in the first quarter. A
        compressor expansion is also planned for the second quarter at the
        Julienne facility.
    (4) At Julienne, in partnership with the government of British
        Columbia, the Company completed construction of a pipeline to tie-in
        stranded gas at North Julienne.
    (5) Also in partnership with the government of British Columbia, the
        Company will be building a pipeline to tie-in stranded gas in the
        recently acquired Blair property. This project is expected to be
        completed at the end of the first quarter and will see this gas tied-
        in to the Company's Gundy facility.
    

    The balance of the year will see drilling activity concentrated at
Caribou/Buckinghorse, Julienne and Bubbles with 2008 realizing a total of
approximately 50 net wells being drilled.

    OUTLOOK

    2007 was another year of significant accomplishments for ProEx; our
undeveloped land position increased 63 percent to approximately 465,000 acres;
fourth quarter 2007 production rose 59 percent from the fourth quarter of
2006; and, proved plus probable reserves grew 68 percent year over year. We
continue to grow our underlying value on a per share basis with production per
diluted share growing 25 percent in the fourth quarter of 2007 over the same
period of 2006, proved plus probable reserves per one thousand diluted shares
growing by 32 percent during 2007 and funds generated from operations per
diluted share growing by 35 percent in 2007.
    Of significance in 2007 was the introduction of stratigraphic diversity
into our future drilling opportunity base. The traditional Halfway regional
tight gas play continues to be the bulk of our inventory and has now been
complemented by the shallower Cretaceous aged Bluesky and Gething gas sands as
well as the deeper Mississippian aged Debolt, which has the potential to add
substantially larger production and reserves per well. This evolution may
assist ProEx in continuing its rapid growth profile for the next several
years.
    The Company has built nine separate natural gas compression facilities in
the Foothills since July 2004. We have standardized the design and
construction template to maximize efficiency and provide flexibility and ease
of future expansion. Throughout this same timeframe ProEx has constructed 300
kilometers of gathering and sales lines to bring discovered natural gas to
market. This infrastructure now provides many alternatives in the direction
and allocation of our exploration and development capital. Although the
capital invested to date has been significant, there continues to be many
opportunities to expand the operating footprint over the coming years. As the
expansion continues to the west and north significant topographical challenges
will be faced. Each of these challenges represents opportunity to discover and
bring to market resources which have not yet been accessed either due to
technology or commodity pricing.
    During 2007 we continued to aggressively build our Foothills land
position through crown land sales, strategic acquisitions and area farm-ins
leveraging off of our historical success and regional knowledge. The Company
completed two acquisitions, the Caribou/Bubbles acquisition in April and the
Blair acquisition in November. The Caribou/Bubbles acquisition provides us
with many years of development opportunities in the Halfway with continuation
of the trend north from our existing land position while also bringing the
potential for several other natural gas targets. The Blair acquisition
includes land contiguous with our existing lands and Cretaceous exploitation
opportunities. Both of these acquisitions were accomplished by leveraging our
Foothills knowledge, experience and track record during a period of weaker
commodity prices.
    The capital efficiency of the ongoing exploration and development program
continued to be very strong in 2007. Finding and development costs inclusive
of revisions and future development costs were $12.33 per proved plus probable
boe for the year, generating a recycle ratio of 2.14 times. All-in finding,
development and acquisition costs on a total investment of $302.7 million for
2007 were $14.29 per proven plus probable boe. Since inception in July 2004
all-in cumulative finding, development and acquisition costs are $12.06 per
proved plus probable boe.
    We have planned capital investment of $150 million in 2008 for
exploration and development activities which is expected to generate
production growth of 40 to 50 percent over average 2007 volumes. The Company
expects to drill approximately 50 net wells during 2008 and invest
approximately $25 million in land and seismic, $25 million in facility
construction and $100 million in drilling and completions activities. ProEx is
well positioned to internally fund its 2008 program from cash flow and
available bank lines of which $75 million of unutilized credit capacity was
available at December 31, 2007.
    Going forward ProEx expects to continue doing the same as it has done
during the past four years, focus in the area we know best and continue to
grow our asset base and undeveloped land at an aggressive pace. We continue to
believe in long term natural gas fundamentals and will continue to pursue
repeatable natural gas exploration targets where we have expertise and an
advantage.

    On behalf of the Board of Directors,


    (signed) "David D. Johnson"
    David D. Johnson
    President and Chief Executive Officer
    February 26, 2008


    ANNUAL AND SPECIAL MEETING

    The Company's Annual and Special Meeting is scheduled for 3:30 PM on
Tuesday April 29, 2008 at the Petroleum Club, 319 - 5th Avenue S.W. Calgary,
Alberta.

    Forward Looking Statements - Certain information regarding ProEx Energy
Ltd. set forth in this document, including management's assessment of ProEx
Energy Ltd.'s 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 ProEx Energy Ltd.'s 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.  ProEx Energy Ltd.'s
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 ProEx Energy Ltd. will derive therefrom.

    RESERVES & CAPITAL EFFICIENCIES

    Summary Reserve Information

    ProEx's reserves were prepared by the independent engineering firm of GLJ
Petroleum Consultants ("GLJ"). Reserves included herein are stated on a total
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.

    
    Summary of Reserves (forecast prices)
                                                              2007      2006
    -------------------------------------------------------------------------
    Proved
      Light and medium oil (mbbls)                             578       508
      Gas (mmcf)                                           198,279   119,969
      NGL (mbbls)                                            2,109     1,165
      BOE (mboe)                                            35,733    21,668

    Proved plus probable
      Light and medium oil (mbbls)                             787       759
      Gas (mmcf)                                           294,194   173,737
      NGL (mbbls)                                            3,037     1,798
      BOE (mboe)                                            52,856    31,513
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    The Company'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 Company's natural gas
and petroleum reserves does not represent the fair market value of the
Company's reserves. In addition to the summary reserve information disclosed
in this annual report, more detailed reserve disclosure in accordance with
NI 51-101 is included in the Company's Annual Information Form ("AIF"). A copy
of the Company's AIF can be obtained by contacting the Company or visiting its
website www.proexenergy.com or through SEDAR at www.sedar.com.

    
    2007 Summary of Oil and Gas Reserves
    Forecast Prices and Costs, Total Company Interest

                           Light and   Natural   Natural     Total     Total
                              Medium       Gas       Gas      2007      2006
                           Crude Oil   Liquids
    -------------------------------------------------------------------------
                              (mbbls)   (mbbls)     (bcf)    (mboe)    (mboe)
    Proved
      Developed producing        437     1,521   129,061    23,468    15,767
      Developed non-producing    132       216    22,649     4,122     1,808
      Undeveloped                  9       372    46,570     8,142     4,093
    -------------------------------------------------------------------------
    Total proved                 578     2,109   198,279    35,733    21,668
    Probable                     210       928    95,914    17,123     9,845
    -------------------------------------------------------------------------
    Total proved plus probable   787     3,037   294,194    52,856    31,513
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Note: May not add due to rounding


    Net Present Value of Reserves, Forecasted Prices and Costs (before tax)

    ($ thousands)           Undiscounted  Discounted  Discounted  Discounted
                                               at 5%       at 8%      at 10%
    -------------------------------------------------------------------------
    Proved
      Developed producing        624,321     455,312     394,315     363,029
      Developed non-producing    104,676      74,815      63,686      57,897
      Undeveloped                163,844     109,310      88,903      78,335
    -------------------------------------------------------------------------
    Total proved                 892,842     639,437     546,904     499,261
    Probable                     530,849     270,203     201,063     170,353
    -------------------------------------------------------------------------
    Total proved plus
     probable                  1,423,692     909,640     747,968     669,614
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Note: May not add due to rounding


    Reconciliation of Total Company Interest Reserves by Principal Product
    Type

    Forecast Prices and Costs
                                                           Natural
                                     Light and   Natural       Gas
                                  Medium Crude       Gas   Liquids       BOE
    -------------------------------------------------------------------------
                                         (mbbl)     (bcf)    (mbbl)    (mboe)
    Total Proved
      Opening balance                    507.7     120.0   1,165.6  21,668.1
      Exploration discoveries                -         -         -         -
      Drilling extensions, infill
       drilling and improved recovery     66.5      76.0   1,085.5  13,820.6
      Technical revisions                 85.7     (14.5)   (300.6) (2,633.2)
      Economic factors                       -         -         -         -
      Acquisitions                        84.8      33.9     247.9   5,983.5
      Dispositions                           -         -         -         -
      Production                        (166.9)    (17.1)    (89.5) (3,105.7)
    -------------------------------------------------------------------------
    Closing balance                      577.8     198.3   2,108.9  35,733.2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                                                           Natural
                                     Light and   Natural       Gas
                                  Medium Crude       Gas   Liquids       BOE
    -------------------------------------------------------------------------
                                         (mbbl)     (bcf)    (mbbl)    (mboe)
    Proved Plus Probable
      Opening balance                    758.7     173.7   1,797.9  31,512.7
      Exploration discoveries                -         -         -         -
      Drilling extensions, infill
       drilling and improved recovery        -     116.6   1,123.6  20,561.9
      Technical revisions                 92.5     (27.2)   (156.3) (4,598.0)
      Economic factors                       -         -         -
      Acquisitions                       103.0      48.1     360.9   8,485.3
      Dispositions                           -         -         -         -
      Production                        (166.9)    (17.1)    (89.5) (3,105.7)
    -------------------------------------------------------------------------
    Closing balance                      787.3     294.2   3,036.6  52,856.2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Reserve Additions and Revisions

    Reserve additions were booked generally in line with Company activity in
the operating areas during 2007. Exploration and development drilling resulted
in the largest property gains at Buckinghorse and Julienne followed by
acquisition adds at Bubbles and Buckinghorse. Material drilling additions at
Sasquatch, Bubbles and Bernadet were also recognized at year end.
    Downward revisions to prior year bookings were made this year to West Beg
 where Halfway natural gas production trends, which were believed to be
stabilizing, continued to decline to the regional average decline curve. The
West Beg 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. Other
revisions were experienced due to the cancellation of the portion of the
undeveloped future drilling locations due to drilling results at Dogrib and
the matching of hydrocarbon liquid ratios to 2007 performance on producing and
future wells across the Foothills assets.
    Additions net of revisions totaled 24.4 million boe for 2007 on a proven
plus probable basis. The year end closing balance of 52.9 million boe is
distributed approximately 60 percent Halfway, 30 percent Cretaceous aged
Bluesky/Gething and 10 percent Mississippian aged Debolt.


    
                                      Oil                  Natural Gas
    -------------------------------------------------------------------------
                                          Edmonton
                                         Par Price                     Sumas
                          WTI Cushing   40 degrees         AECO     Spot gas
                             Oklahoma          API    Gas Price        Price
    Year                     (US$/bbl)   (Cdn$/bbl) (SCdn/MMBtu)  ($US/MMBtu)
    -------------------------------------------------------------------------
    Historical
      2003                      31.07        43.66         6.66         4.66
      2004                      41.38        52.96         6.88         5.26
      2005                      56.58        69.02         8.58         7.13
      2006                      66.22        73.21         7.16         6.27
      2007                      72.24        77.02         6.65         6.52
    Forecast
      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                      82.00        81.10         7.60         7.70
      2014                      82.00        81.10         7.80         7.90
      2015                      82.00        81.10         7.97         8.07
      2016                      82.02        81.12         8.14         8.24
      2017                      83.66        82.76         8.31         8.41
      2018                      85.33        84.42         8.48         8.58

      Thereafter             +2.0%/yr     +2.0%/yr     +2.0%/yr     +2.0%/yr
    -------------------------------------------------------------------------
    

    Finding & Development Costs

    Advisory
    The aggregate of the exploration and development costs incurred in the
most recent financial year and the change during the year in estimated future
development capital generally will not reflect total finding and development
costs related to reserve additions for that year.

    During 2007, the exploration and development program resulted in total
reserve additions (after revisions) of 11.2 million boe on a proved basis, and
16.0 million boe on a proved plus probable basis. After incorporating the
change in future development capital, the exploration and development program
generated finding and development costs of $16.60 per boe proved and $12.33
per boe proved plus probable. During 2007, the Company made two strategic
acquisitions which resulted in reserve additions of 6.0 million boe on a
proved basis, and 8.5 million boe on a proved plus probable basis and addition
cost of $25.49 per boe on a proved basis, and $17.97 per boe on a proved plus
probable basis. Over the next few years, the Company expects to average the
acquisition costs down to historic levels through drilling initiatives on the
acquired lands. The net acquisition activity resulted in the total exploration
and development program finding, development and acquisition costs ("FD&A") of
$19.70 per boe proved and $14.29 per boe proved plus probable. The cumulative
FD&A costs since inception of the Company (including the change in future
development capital) for the period July 1, 2004 to December 31, 2007 are
$16.31 per boe proved and $12.06 per boe proved plus probable.

    
    2007 Finding &
     Development Costs                                      Proved
     and Finding,                                             Plus    Proved
     Development &                      Proved            Probable      Plus
     Net Acquisition         Capital   Reserve    Proved   Reserve  Probable
     Costs              Expenditures Additions     Costs Additions     Costs
    -------------------------------------------------------------------------
                        ($ thousands)    (mboe)   ($/boe)    (mboe)   ($/boe)

    F&D exploration and
     development program
     before revisions        150,167    13,821     10.87    20,562      7.30
    -------------------------------------------------------------------------
    F&D exploration and
     development program
     after revisions(a)      150,167    11,187     13.42    15,964      9.41
    -------------------------------------------------------------------------
    Change in proved
     future development
     capital(b)(1)            35,577       n/a       n/a       n/a       n/a
    -------------------------------------------------------------------------
    Change in proved plus
     probable future
     development
     capital(c)(1)            46,694       n/a       n/a       n/a       n/a
    -------------------------------------------------------------------------
    Proved F&D including
     change in future
     development capital
     (d) equals (a+b)        185,744    11,187     16.60       n/a       n/a
    -------------------------------------------------------------------------
    Proved plus probable F&D
     including change in
     future development
     capital(e) equals (a+c) 196,861       n/a       n/a    15,964     12.33
    -------------------------------------------------------------------------
    Net acquisition/
     disposition activity(f) 152,523     5,984     25.49     8,485     17.97
    -------------------------------------------------------------------------
    Total 2007 proved
     FD&A costs including
     future development
     capital(d+f)            338,267    17,171     19.70       n/a       n/a
    -------------------------------------------------------------------------
    Total 2007 proved plus
     probable FD&A costs
     including future
     development
     capital(e+f)            349,384       n/a       n/a    24,449     14.29
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    2006 Finding &
     Development Costs                                      Proved
     and Finding,                                             Plus    Proved
     Development &                      Proved            Probable      Plus
     Net Acquisition         Capital   Reserve    Proved   Reserve  Probable
     Costs              Expenditures Additions     Costs Additions     Costs
    -------------------------------------------------------------------------
                        ($ thousands)    (mboe)   ($/boe)    (mboe)   ($/boe)

    F&D exploration and
     development program
     before revisions        151,468    12,434     12.18    19,348      7.83
    -------------------------------------------------------------------------
    F&D exploration and
     development program
     after revisions(a)      151,468    11,823     12.81    18,403      8.23
    -------------------------------------------------------------------------
    Change in proved
     future development
     capital(b)(1)            33,418       n/a       n/a       n/a       n/a
    -------------------------------------------------------------------------
    Change in proved plus
     probable future
     development
     capital(c)(1)            49,167       n/a       n/a       n/a       n/a
    -------------------------------------------------------------------------
    Proved F&D including
     change in future
     development capital
     (d) equals (a+b)        184,886    11,823     15.64       n/a       n/a
    -------------------------------------------------------------------------
    Proved plus probable F&D
     including change in
     future development
     capital(e) equals (a+c) 200,635       n/a       n/a    18,403     10.90
    -------------------------------------------------------------------------
    Net acquisition/
     disposition activity(f)     684         -     n/c(2)       12     57.00
    -------------------------------------------------------------------------
    Total 2006 proved
     FD&A costs including
     future development
     capital(d+f)            185,570    11,823     15.70       n/a       n/a
    -------------------------------------------------------------------------
    Total 2006 proved plus
     probable FD&A costs
     including future
     development
     capital(e+f)            201,319       n/a       n/a    18,414     10.93
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (2) The acquisition activity during the year consisted of undeveloped
        land with no associated reserves.


    2005 to 2007 Finding &
     Development Costs                                      Proved
     and Finding,                                             Plus    Proved
     Development &                      Proved            Probable      Plus
     Net Acquisition         Capital   Reserve    Proved   Reserve  Probable
     Costs              Expenditures Additions     Costs Additions     Costs
    -------------------------------------------------------------------------
                        ($ thousands)    (mboe)   ($/boe)    (mboe)   ($/boe)

    F&D exploration and
     development program
     before revisions        395,749    34,138     11.59    49,755      7.95
    -------------------------------------------------------------------------
    F&D exploration and
     development program
     after revisions(a)      395,749    31,130     12.71    44,110      8.97
    -------------------------------------------------------------------------
    Change in proved
     future development
     capital(b)(1)            77,184       n/a       n/a       n/a       n/a
    -------------------------------------------------------------------------
    Change in proved plus
     probable future
     development
     capital(c)(1)           102,414       n/a       n/a       n/a       n/a
    -------------------------------------------------------------------------
    Proved F&D including
     change in future
     development capital
     (d) equals (a+b)        472,933    31,130     15.19       n/a       n/a
    -------------------------------------------------------------------------
    Proved plus probable
     F&D including change
     in future development
     capital(e) equals (a+c) 498,163       n/a       n/a    44,110     11.29
    -------------------------------------------------------------------------
    Net acquisition/
     disposition activity(f) 144,547     5,686     25.42     8,092     17.86
    -------------------------------------------------------------------------
    Total 2005 to 2007
     proved FD&A costs
     including future
     development
     capital(d+f)            617,480    36,816     16.77       n/a       n/a
    -------------------------------------------------------------------------
    Total 2005 to 2007
     proved plus probable
     FD&A costs including
     future development
     capital(e+f)            642,710       n/a       n/a    52,201     12.31
    -------------------------------------------------------------------------


    2004 to 2007 Finding &
     Development Costs                                      Proved
     and Finding,                                             Plus    Proved
     Development &                      Proved            Probable      Plus
     Net Acquisition         Capital   Reserve    Proved   Reserve  Probable
     Costs              Expenditures Additions     Costs Additions     Costs
    -------------------------------------------------------------------------
                        ($ thousands)    (mboe)   ($/boe)    (mboe)   ($/boe)

    F&D exploration and
     development program
     before revisions        427,609    37,690     11.35    54,563      7.84
    -------------------------------------------------------------------------
    F&D exploration and
     development program
     after revisions(a)      427,609    34,630     12.35    48,764      8.77
    -------------------------------------------------------------------------
    Change in proved
     future development
     capital(b)(1)            80,948       n/a       n/a       n/a       n/a
    -------------------------------------------------------------------------
    Change in proved plus
     probable future
     development
     capital(c)(1)           108,792       n/a       n/a       n/a       n/a
    -------------------------------------------------------------------------
    Proved F&D including
     change in future
     development capital
     (d) equals (a+b)        508,557    34,630     14.69       n/a       n/a
    -------------------------------------------------------------------------
    Proved plus probable
     F&D including change
     in future development
     capital(e) equals (a+c) 536,401       n/a       n/a    48,764     11.00
    -------------------------------------------------------------------------
    Net acquisition/
     disposition activity(f) 149,053     5,686     26.21     8,092     18.42
    -------------------------------------------------------------------------
    Total 2004 to 2007
     proved FD&A costs
     including future
     development
     capital(d+f)            657,610    40,316     16.31       n/a       n/a
    -------------------------------------------------------------------------
    Total 2004 to 2007
     proved plus probable
     FD&A costs including
     future development
     capital (e+f)           685,454       n/a       n/a    56,855     12.06
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Reserve additions in the Finding & Development Costs and the Finding,
    Development and Acquisition costs are on a total company interest basis
    (before royalty burdens and including royalty interests) as has been our
    practice in the past. The difference between total company interest and
    working interest is not material.

    (1) Reconciliation of Changes in Future Development Capital

                                                            Proved
                                                              Plus
        ($ thousands)                   Proved    Change  Probable    Change
        ---------------------------------------------------------------------
        January 1, 2005                  4,882               8,107
                                                   8,189               6,553
        January 1, 2006                 13,071              14,660
                                                  33,418              49,167
        January 1, 2007                 46,489              63,827
                                                  35,577              46,694
        January 1, 2008                 82,066             110,521
        ---------------------------------------------------------------------


    Production Replacement

    The Company's capital investment program during the year replaced
production by a factor of 5.5 times on a proved basis and 7.9 times on a
proved plus probable basis.

                                                              2007      2006
    -------------------------------------------------------------------------
    Production (mboe)                                        3,106     1,929

    Proved reserve additions after revisions of
     prior periods and net acquisitions (mboe)              17,171    11,823
    Proved replacement ratio                                   5.5       6.1
    Proved plus probable reserve additions after
     revision of prior periods and net acquisitions
     (mboe)                                                 24,449    18,414
    Proved plus probable replacement ratio                     7.9       9.5
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Cost of Production Additions

    During 2007, the Company added 7,229 boe per day of new production from
its capital program and asset acquisitions. Exploration and development
program capital was $150.2 million and asset acquisitions totaled
$152.5 million resulting in total capital investment during 2007 of
$302.7 million. The exploration and development program added production at a
cost of $29,153 per boe per day and the total program being added at a cost of
$41,872 per boe per day. This calculation is highly sensitive to the timing of
production additions in the fourth quarter, which was later than originally
forecasted in 2007.

    (boe/d)                                                       Production
    -------------------------------------------------------------------------
    Production Reconciliation
    Production fourth quarter 2006                                     6,080
    Decline on base production                                        (1,763)
    Exploration program production additions during 2007               5,151
    Decline on new 2007 production                                    (1,803)
    Production additions from 2007 acquisitions                        2,078
    Decline on 2007 acquisitions                                         (63)
    -------------------------------------------------------------------------
    Production fourth quarter 2007                                     9,680
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Recycle Ratio

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

                                                              2007      2006
    -------------------------------------------------------------------------
    Operating netbacks ($/boe)                               26.43     24.35
    Proved FD&A costs after revisions of prior
     periods and including the change in future
     development capital ($/boe)                             19.70     15.70
    Proved reinvestment efficiency ratio                      1.34      1.55
    Proved plus probable FD&A costs after revisions
     of prior periods and including the change in
     future development capital ($/boe)                      14.29     10.93
    Proved plus probable reinvestment efficiency ratio        1.85      2.23
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Reserve Life Index

    The Company's reserve life index ("RLI") using annualized fourth quarter
production is 10.1 years proved (2006 - 9.8 years) and 15.0 years proved plus
probable (2006 - 14.2 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)          3.533        4.314        2.219        2.678
    Proved reserves (mmboe)    35.733       35.733       21.668       21.668
    Proved RLI (years)           10.1          8.3          9.8          8.1
    Production (mmboe)          3.533        4.718        2.219        3.009
    Proved plus probable
     reserves (mmboe)          52.856       52.856       31.513       31.513
    Proved plus
     probable RLI (years)        15.0         11.2         14.2         10.5
    -------------------------------------------------------------------------


    Reserves Per Share

                                                              2007      2006
    -------------------------------------------------------------------------
    Proved plus probable reserves (mboe)                    52,856    31,513
    Proved plus probable reserves per
     thousand shares (boe)
      - Basic(1)                                             1,002       794
      - Diluted(2)                                             892       676
    -------------------------------------------------------------------------
    Average Production (boe/d)                               8,509     5,285
    Average Production per million shares (boe/d)
      - Basic(3)                                             179.8     149.6
      - Diluted(4)                                           161.5     126.6

    Fourth quarter production (boe/d)                        9,680     6,080
    Fourth quarter production per million shares (boe)
      - Basic(1)                                             184.3     153.2
      - Diluted(2)                                           163.4     130.4
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Calculated using outstanding common shares at the end of the year.
    (2) Calculated using outstanding common shares, options and warrants at
        the end of the year.
    (3) Calculated using the weighted average outstanding common shares at
        the end of the year.
    (4) Calculated using the weighted average outstanding common shares,
        options and warrants at the end of the year.
    

    Average production per million basic shares increased 20 percent during
the year while average production per one million diluted shares increased
28 percent during the same period. Proved plus probable reserves per thousand
basic shares increased 27 percent over the prior year while proved plus
probable reserves per one thousand diluted shares increased 32 percent during
the same period.

    Net Asset Value Per Share Before Tax

    ProEx's net asset value per share at December 31, 2007 was $12.88 per
basic share ($10.60 per basic share in 2006) and on a diluted basis $11.94 per
share ($9.38 per diluted share in 2006) using GLJ Petroleum Consultants Ltd.
("GLJ") forecasted prices discounted at 10 percent, and $14.35 per basic share
and $13.25 per diluted share ($11.90 and $10.49 respectively per share in
2006) using GLJ forecasted prices discounted at eight percent. The GLJ Report
has been prepared in accordance with the standards contained in the COGE
Handbook and the reserve definitions contained in NI 51-101.

    
                                              2007                2006
    -------------------------------------------------------------------------
    ($ thousands)                        PV 8%    PV 10%     PV 8%    PV 10%
    -------------------------------------------------------------------------
    Proved plus probable reserve
     value (2)                         747,968   669,614   420,517   369,355
    Undeveloped acreage(3)              91,000    91,000    63,000    63,000
    Seismic(4)                          30,000    30,000    17,000    17,000
    Bank debt                          (96,881)  (96,881)  (25,803)  (25,803)
    Working capital deficiency         (14,354)  (14,354)   (2,035)   (2,035)
    Asset retirement obligations(5)     (3,893)   (3,070)     (478)     (925)
    -------------------------------------------------------------------------
    Net asset value - Basic            753,840   676,309   472,201   420,592
    Exercise of stock options
     and warrants                       31,044    31,044    16,813    16,813
    -------------------------------------------------------------------------
    Net asset value - Diluted          784,884   707,353   489,014   437,405
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Common shares outstanding
      - Basic                           52,528    52,528    39,691    39,691
      - Diluted                         59,227    59,227    46,613    46,613
    Net asset value per common share ($)
      - Basic                            14.35     12.88     11.90     10.60
      - Diluted(6)                       13.25     11.94     10.49      9.38
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) The Company's net asset value before tax is measured with reference
        to the present value of future estimated net cash flows from reserves
        estimated by GLJ, the independent reserve engineers, and including
        land, seismic data, adjustments for working capital deficiency, asset
        retirement obligations and bank debt 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.
    (2) Reserve values are based on before tax estimates of future cash flows
        as evaluated by our independent qualified reserve evaluators, GLJ
        using their future commodity price forecast as presented in the
        pricing assumptions (see 2007 Annual Information Form).
    (3) Undeveloped land values are based on internal estimates of market
        value considering recent sales of similar properties in the same
        general area.
    (4) Seismic inventory values are an internal estimate of replacement
        value.
    (5) Proved plus probable reserve value includes $1.8 million (2006 -
        $1.3 million) at PV eight percent, and $1.6 million (2006 -
        $0.9 million) at PV ten percent forecast pricing, of asset retirement
        obligations on wells with assigned reserves.
    (6) Calculated using outstanding common shares, options and warrants at
        year-end.
    

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

    ProEx Energy Ltd.

    The following discussion and analysis as provided by the Management of
ProEx Energy Ltd. ("ProEx" or "Company") as of February 26, 2008, is to be
read in conjunction with the accompanying audited 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.

    Description of Company - ProEx Energy Ltd. is a Calgary based, natural
gas focused, exploration and development company, established on July 2, 2004.
Primary operating areas include the northeast British Columbia Foothills and
Fort St. John Plains regions. Common shares of ProEx trade on the Toronto
Stock Exchange ("TSX") under the symbol PXE.

    Non-GAAP Measures - The MD&A contains the term "funds generated from
operations" and "funds generated from operations per share" which do not have
any standardized meaning prescribed by Canadian GAAP. Management uses funds
generated from operations and funds generated from operations per share to
analyze operating performance and leverage and considers funds generated from
operations to be a key measure as it demonstrates the Company's ability to
generate the cash necessary to fund future capital investments and to repay
debt. Funds generated from operations should not be considered an alternative
to, or more meaningful than cash flow from operating activities as determined
in accordance with Canadian GAAP as an indicator of the Company's performance.
Therefore references to funds generated from operations or funds generated
from operations per share (basic and diluted) may not be comparable with the
calculation of similar measures for other entities. Funds generated from
operations per share is calculated using the basic and diluted weighted
average number of shares for the period. The reconciliation between funds
generated from operations and cash flow from operations after changes in
working capital for the years ended December 31, 2007 and 2006 is as follows:

    
    ($ thousands)                                             2007      2006
    -------------------------------------------------------------------------
    Funds generated from operations                         73,808    43,531
    Changes in non-cash working capital                      1,592    (6,134)
    -------------------------------------------------------------------------
    Cash flow from operations after changes
     in working capital                                     75,400    37,397
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Management uses certain industry benchmarks such as operating netback to
analyze financial and operating performance. This benchmark as presented does
not have any standardized meaning prescribed by Canadian GAAP and therefore
may not be comparable with the calculation of similar measures for other
entities. Management considers netbacks an important measure as it
demonstrates its profitability relative to current commodity prices. The
Company uses these measures to help evaluate its performance.

    Boe Presentation - Barrels of oil equivalent ("boe") may be misleading,
particularly if used in isolation. A boe conversion ratio of six thousand
cubic feet ("mcf") to one barrel ("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. All boe conversions in this
report are derived by converting natural gas to oil in the ratio of six mcf of
gas to one barrel of oil.

    Forward-Looking Information - Certain information regarding the Company
set forth in this document, including Management's assessment of the Company's
future plans and operations, may constitute forward-looking statements under
applicable securities law and necessarily involve risks associated with oil
and gas exploration, production, marketing, and transportation such as loss of
market, volatility of commodity prices, currency fluctuations, imprecision of
reserve estimates, environmental risks, competition from other producers and
ability to access sufficient capital from internal and external sources; as a
consequence, actual results may differ materially from those anticipated in
the forward-looking statements.

    Relationship with Progress Energy Trust

    The Company receives personnel and certain administrative and technical
services from Progress Energy Trust ("Progress") in connection with the
management, development, exploitation and operation of the assets of ProEx and
the marketing of its production. Progress provides these services in
accordance with the Technical Services Agreement entered into with ProEx as
described below. ProEx has granted performance shares and stock options to
Progress executives and employees and common shares under Progress' long term
incentive compensation plan ("LTI") to non-executive employees of Progress in
their capacity as service providers.
    Under the terms of the LTI, non-executive Progress employees in their
capacity as service providers, may be granted LTI awards to be paid in common
shares of the Company. ProEx agreed to contribute to the LTI to ensure that
service providers retain incentives related to the success of ProEx. Awards
granted under the LTI will vest on the second anniversary date of the date of
grant. ProEx has agreed to reimburse Progress for this expense.
    ProEx and Progress 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 Company has entered into a protocol
arrangement ("Protocol Arrangement") with Progress that specifies how each
company will manage the joint lands in specifically identified areas of
interest. To ensure good governance practices, both ProEx and Progress have
each created independent committees of their Board of Directors to monitor
compliance with the Technical Services Agreement and the Protocol Arrangement.

    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 Company receives services including management,
development, exploitation, operations, administrative, and marketing, as well
as information technology systems from Progress on an expense reimbursement
basis, based on the Company's monthly capital activity and production levels
relative to the combined capital activity and production levels of both ProEx
and Progress.

    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.

    Independent Committee of the Board of Directors
    Both ProEx and Progress have created independent committees of the Board
of Directors to deal with technical services issues. The Committees' mandate
includes the following:

    
    -   To consider any issues related to the Technical Services Agreement
        between Progress and ProEx that they consider appropriate or that are
        directed to the Committee by Management.

    -   To meet with the Technical Services Committee or similar committee of
        Progress when appropriate.

    -   To advise the Board of Directors of decisions by the Technical
        Services Committee of interpretations, amendments or issues in
        dispute.
    

    On April 2, 2007, ProEx acquired certain interests in northeast British
Columbia Foothills assets previously acquired by Progress. ProEx's total
consideration, including transaction costs of $0.9 million was $136.4 million.
When considering the bid process for this 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 service 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, ProEx and Progress 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, ProEx acquired an 80 percent interest
($14.3 million) and Progress acquired a 20 percent interest in the assets
($3.6 million).

    
    2007 HIGHLIGHTS AND SELECTED FINANCIAL INFORMATION

    ($ thousands, except per share amounts)                   2007      2006
    -------------------------------------------------------------------------
    Production
      - Natural gas (mcf/d)                                 46,838    28,836
      - Crude oil (bbls/d)                                     457       335
      - Natural gas liquids (bbls/d)                           245       144
      - Total production (boe/d)                             8,509     5,285

    Pricing
      - Natural gas ($/mcf)                                   6.64      6.84
      - Crude oil ($/bbl)                                    74.80     69.26
      - Natural gas liquids ($/bbl)                          68.49     67.03

    Petroleum and natural gas revenue                      132,160    84,000
    Funds generated from operations                         73,808    43,531
      - Basic per share                                       1.56      1.23
      - Diluted per share                                     1.40      1.04
    Net earnings                                            20,072    15,163
      - Basic per share                                       0.42      0.43
      - Diluted per share                                     0.38      0.36

    Net property acquisitions (dispositions)               152,523       683
    Capital expenditures                                   150,167   151,478
    Total assets                                           549,343   290,307
    Bank debt and working capital deficiency               110,986    27,838
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Operations

    -   Average 2007 production was 8,509 boe per day compared to 5,285 boe
        per day during the same period in 2006, an increase of 61 percent
        while production per diluted share increased 28 percent during the
        same period.

    -   2007 fourth quarter production averaged 9,680 boe per day compared to
        6,080 boe per day in the fourth quarter of 2006, an increase of
        59 percent while production per diluted share increased 25 percent
        during the same period.

    -   Natural gas production was 52,917 mcf per day during the fourth
        quarter of 2007 compared to 48,082 mcf per day during the third
        quarter of 2007 and 33,505 mcf per day in the fourth quarter of 2006.

    -   Crude oil and natural gas liquids production averaged 860 bbls per
        day during the fourth quarter of 2007 compared to 495 bbls per day in
        the fourth quarter of 2006.

    -   Drilled 70 gross wells (45.5 net) during the year with a 93 net
        percent success rate, resulting in 64 natural gas wells (42.3 net).

    -   During the year, the Company increased net undeveloped land to
        433,000 net acres from 271,000 net acres at December 31, 2006. At
        December 31, 2007 undeveloped lands under the control of ProEx,
        including option acreage, is approximately 465,000 acres.

    Financial

    -   Petroleum and natural gas revenue increased 57 percent to
        $132.2 million for the year compared to $84.0 million during the
        prior year.

    -   Average natural gas prices for 2007 were $6.64 per mcf consistent
        with the $6.84 per mcf in 2006.

    -   Funds generated from operations increased 70 percent to $73.8 million
        ($1.40 per diluted share) for the year compared to $43.5 million
        ($1.04 per diluted share) during the prior year resulting in a
        35 percent increase to funds generated from operations per diluted
        share.

    -   Net earnings for the year was $20.1 million ($0.38 per diluted share)
        a 32 percent increase over the $15.2 million ($0.36 per diluted
        share) recorded in the prior year.

    -   Capital investment for 2007, excluding net property acquisitions
        (dispositions), was $150.2 million, slightly lower than the prior
        year at $151.5 million. Total capital investment, including the two
        strategic Foothills acquisitions during the year was $302.7 million
        compared to $152.2 million in 2006.

    -   Bank debt and working capital deficiency was $111.0 million at
        December 31, 2007 on a $185 million credit facility available at year
        end.
    

    RESULTS OF OPERATIONS

    Asset Acquisition

    On April 2, 2007, ProEx acquired certain interests in northeast British
Columbia Foothills assets previously acquired by Progress (the "Asset
Acquisition"). ProEx's total consideration, including transaction costs of
$0.9 million was $136.4 million. The Asset Acquisition was financed through an
equity offering of 8,050,000 common shares of the Company at a price of $12.45
per share for aggregate gross proceeds of $100.2 million ($95.6 million net of
issue costs). The remainder of the purchase price was financed through
increased bank debt.
    The Asset Acquisition included approximately 2,000 boe per day of
production, 95 percent natural gas and approximately 80,000 net acres of
undeveloped land.

    Production

    The following is a summary of daily production for the quarterly and
annual periods indicated:

    
                                                  2007
    -------------------------------------------------------------------------
                              Annual        Q4        Q3        Q2        Q1
    -------------------------------------------------------------------------
    Natural gas (mcf/d)       46,838    52,917    48,082    49,530    36,631
    Crude oil (bbls/d)           457       590       438       414       384
    Natural gas liquids
     (bbls/d)                    245       270       225       239       246
    -------------------------------------------------------------------------
    Total production (boe/d)   8,509     9,680     8,677     8,909     6,735
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

                                                  2006
    -------------------------------------------------------------------------
                              Annual        Q4        Q3        Q2        Q1
    -------------------------------------------------------------------------
    Natural gas (mcf/d)       28,836    33,505    28,348    29,931    23,454
    Crude oil (bbls/d)           335       343       331       352       314
    Natural gas liquids
     (bbls/d)                    144       152       148       163       112
    -------------------------------------------------------------------------
    Total production (boe/d)   5,285     6,080     5,204     5,503     4,335
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    ProEx's production for the year ended December 31, 2007 averaged 8,509 boe
per day. The production was comprised of 457 bbls per day of crude oil, 245
bbls per day of natural gas liquids and 46,838 mcf per day of natural gas.
Production increased 61 percent over the 5,285 boe per day recorded in the
prior year due to the Asset Acquisition and the successful drilling.

    Producing Areas

    The following table summarizes the Company's average production by
producing areas for the years ended December 31, 2007 and 2006.

    (boe/d)                                                   2007      2006
    -------------------------------------------------------------------------
    West Beg                                                 2,211     2,391
    Gundy and Town                                           1,403     1,384
    Julienne                                                 1,140        59
    Altares/Bernadet                                           901       611
    Buckinghorse/Caribou                                       805         -
    Bubbles                                                    835         -
    Fort St. John Plains                                       626       729
    Dogrib/Sasquatch                                           562       111
    Blair                                                       26         -
    -------------------------------------------------------------------------
    Total daily production                                   8,509     5,285
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Commodity Pricing

    Average Benchmark Prices                                  2007      2006
    -------------------------------------------------------------------------
    Natural gas - Station No. 2 (Cdn $/mcf daily index)       6.44      6.28
    Natural gas - AECO (Cdn $/mcf daily index)                6.51      6.59
    Natural gas - AECO (Cdn $/mcf monthly index)              6.67      7.05
    Exchange rate (US$/Cdn$)                                1.0740    1.1343
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    ProEx Realized Prices
    -------------------------------------------------------------------------
    Natural gas ($/mcf)                                       6.64      6.84
    Crude oil ($/bbl)                                        74.80     69.26
    Natural gas liquids ($/bbl)                              68.49     67.03
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    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 ("U.S.").
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
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
U.S. 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 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
U.S.$6.91 per million btu for the New York Mercantile Exchange ("NYMEX") and
Cdn$6.11 per gigajoule ("gj") at the Canadian Alberta Energy Company
interconnect with the TransCanada Alberta system ("AECO").
    Looking toward 2008, we anticipate WTI oil prices will average within the
US$75.00 to US$85.00 per barrel range and AECO natural gas to average between
Cdn$6.50 to Cdn$7.00 per gj. ProEx produces predominantly light oil and high
heat content, liquids rich, natural gas that attract premium market prices.

    Natural Gas Pricing

    The U.S. 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 ProEx's natural gas is sold at pricing based at one
of the Alberta or British Columbia hubs. ProEx 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
    -------------------------------------------------------------------------
    British Columbia                    46,838      6.64    28,836      6.84
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    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)                                  (1.00)    (1.78)
    -------------------------------------------------------------------------
    Station No. 2 (US $/mmbtu)                                5.91      5.48
    Average exchange rate                                   1.0740    1.1343
    -------------------------------------------------------------------------
    Station No. 2 price (Cdn $/mcf daily index)(1)            6.44      6.28
    Premium: ProEx realized price vs spot                     0.20      0.56
    -------------------------------------------------------------------------
    ProEx average British Columbia field price (Cdn $/mcf)    6.64      6.84
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Converted from $/mmbtu to $/mcf using the Energy and Utilities Board
        conversion factor.
    

    Risk Management

    During 2007, the Company entered into natural gas financial contracts for
the purpose of protecting its funds generated from operations from the
volatility of natural gas prices. For the year ended December 31, 2007 the
Company's natural gas price risk management program had a net realized gain of
$7.9 million (2006 - $2.5 million).
    On January 1, 2007 the Company 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 consequently 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 and losses in 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 adoption, the Company recognized a current asset of $7.4 million for
the fair value of its natural gas derivative contracts with a corresponding
increase to accumulated other comprehensive income of $4.9 million (net of tax
of $2.5 million). The $4.9 million in accumulated other comprehensive income
was amortized through other comprehensive income and unrealized gain or loss
on the statement of earnings over the term of the contracts. As a result, for
the year ended December 31, 2007, $4.9 million, net of tax, was charged to
other comprehensive income with a corresponding unrealized gain on financial
instruments of $7.4 million, and a charge to future income tax expense of
$2.5 million. The unrealized gain of $7.4 million was offset by the change in
fair value on the natural gas derivative contracts from January 1, 2007 of
$7.4 million resulting in an unrealized gain of nil for 2007.
    The Company's financial derivative trading activities are conducted
pursuant to the Company's Risk Management Policy approved by the Board of
Directors. The Risk Management Policy has the objectives of reducing risk
exposure to budgeted annual funds generated from operations projections
resulting from uncertainty or changes in commodity prices, interest rates or
foreign exchange; limiting financial contract volumes up to a maximum of
50 percent of forecasted production, net of royalties (or higher subject to
Board of Directors approval); and limiting financial derivative trading
activity to counter-parties that provide sufficient collateral in support of
payment or have investment grade credit ratings.
    ProEx's commodity risk management positions are described in Note 9 in
the audited financial statements. There were no natural gas derivative
contracts outstanding as at December 31, 2007. Subsequent to year end the
Company entered into natural gas derivative contracts for the period
April 2008 to October 2008 for a total of 40,000 gj's per day using call
spreads with a net floor price (net of premiums to be paid) of $6.93 per gj
and a net ceiling price of $7.93 per gj.

    Petroleum and Natural Gas Revenues

    Petroleum and natural gas revenues for 2007 were $132.2 million, up
57 percent over the $84.0 million in revenues for 2006. Revenues consisted of
$113.6 million in natural gas sales (2006 - $72.0 million), $12.5 million in
crude oil sales (2006 - $8.5 million), and $6.1 million in natural gas liquid
sales (2006 - $3.5 million). Increased petroleum and natural gas revenues over
the prior year are the result of increased production on account of the Asset
Acquisition and successful drilling during 2007.

    
    ($ thousands)                                             2007      2006
    -------------------------------------------------------------------------
    Revenues by product
    Natural gas                                            113,551    72,007
    Crude oil                                               12,483     8,473
    Natural gas liquids                                      6,126     3,520
    -------------------------------------------------------------------------
    Total petroleum and natural gas revenues               132,160    84,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Royalties

    Royalty expense consists of royalties paid to provincial governments,
freehold landowners and overriding royalty owners. Royalties increased
26 percent to $29.5 million in 2007 from $23.4 million in 2006 due to higher
revenues, as a result of higher production. ProEx's average royalty rate in
2007 was 22.4 percent compared to 27.9 percent in 2006. The decrease in the
royalty rate is due to lower royalty rates on the properties acquired in the
Asset Acquisition, which also included wells in which ProEx paid gross
overriding royalties. Management anticipates that the average royalty rates
for 2008 will be between 23 and 26 percent.

    
    ($ thousands, except where otherwise indicated)           2007      2006
    -------------------------------------------------------------------------
    Crown                                                   25,250    17,931
    Freehold and overriding                                  4,296     5,510
    -------------------------------------------------------------------------
    Total royalty expense                                   29,546    23,441
    -------------------------------------------------------------------------
    Royalties ($/boe)                                         9.51     12.15
      Average royalty rate (%)                                22.4      27.9
    -------------------------------------------------------------------------


    ($ thousands, except where otherwise indicated)           2007      2006
    -------------------------------------------------------------------------
    Royalties by product
    Natural gas royalties                                   25,927    20,698
      $/boe                                                   9.10     11.80
      Average natural gas royalty rate (%)                    22.8      28.7
    -------------------------------------------------------------------------
    Natural gas liquids royalties                            1,328       885
      $/boe                                                  14.85     16.85
      Average natural gas liquids royalty rate (%)            21.7      25.1
    -------------------------------------------------------------------------
    Crude oil royalties                                      2,291     1,858
      $/boe                                                  13.73     15.19
      Average crude oil royalty rate (%)                      18.4      21.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Operating Expenses

    Operating expenses for 2007 were $15.8 million compared to $9.2 million
for 2006. The increase is due to higher production in 2007 as a result of the
Asset Acquisition and successful drilling. On a per boe basis, operating
expenses for 2007 increased seven percent to $5.09 from $4.75 in 2006.
Slightly higher operating costs on the properties acquired in the Asset
Acquisition increased the operating cost per boe. Operating costs per boe have
been trending downwards since the second quarter of 2007 as ProEx continues to
optimize the acquired assets. Management anticipates 2008 normalized operating
expenses to be in the $5.00 to $5.30 per boe range.

    
    ($ thousands, except where otherwise indicated)           2007      2006
    -------------------------------------------------------------------------
    Operating expenses - natural gas properties             14,578     8,230
      $/boe                                                   4.97      4.49
    Operating expenses - crude oil properties                1,241       942
      $/boe                                                   7.25      9.82
    Operating expenses - all properties                     15,819     9,172
      $/boe                                                   5.09      4.75
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Transportation Expenses

    Transportation expenses were $12.7 million for 2007 compared to
$7.0 million for 2006. The increase was due to increased production in 2007.
On a per boe basis, transportation expenses were $4.10 in 2007 compared to
$3.60 in 2006. Higher per boe costs in 2007 was due to higher transportation
and treatment tolls associated with the Asset Acquisition, including higher
treatment tolls associated with Slave Point production processed through the
Keyera-owned Caribou gas plant. Although Management favorably renegotiated the
terms of the Caribou gas plant, the benefit will only be recognized in 2008.
In British Columbia, there is an infrastructure owned by Spectra Energy that
enables gas producers to avoid facility construction in exchange for regulated
gathering, processing and transmission fees. This all-in charge is included in
transportation expenses. Management anticipates for 2008 that average
transportation costs will be in the $4.20 to $4.50 per boe range.

    Operating Netbacks by Product

    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, crude oil and all
properties combined for the year and for the prior year.

    
                                                              2007      2006
    -------------------------------------------------------------------------
    Natural gas properties ($/mcf)
    Sales price                                               6.88      6.84
    Realized gain on financial instruments                    0.45      0.23
    Royalties                                                (1.58)    (2.04)
    Transportation expenses                                  (0.70)    (0.61)
    Operating expenses                                       (0.83)    (0.75)
    -------------------------------------------------------------------------
    Operating netback - natural gas properties                4.22      3.67
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Crude oil properties ($/bbl)
    Sales price                                              64.37     63.91
    Royalties                                                (9.82)    (9.94)
    Transportation expenses                                  (1.87)    (2.47)
    Operating expenses                                       (7.25)    (9.82)
    -------------------------------------------------------------------------
    Operating netback - oil properties                       45.43     41.68
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    All properties ($/boe)
    Sales price                                              42.55     43.55
    Realized gain on financial instruments                    2.56      1.31
    Royalties                                                (9.51)   (12.15)
    Transportation expenses                                  (4.10)    (3.60)
    Operating expenses                                       (5.09)    (4.75)
    -------------------------------------------------------------------------
    Operating netback - all properties                       26.41     24.36
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    General and Administrative Expenses

    For 2007, general and administrative expenses ("G&A"), net of operator
recoveries and capitalized expenses were $2.9 million ($0.93 per boe) compared
to $1.7 million ($0.88 per boe) in the prior year. The Company incurred higher
technical service fees from Progress as compared to the prior year due to the
Company's increased activity levels and production volumes during the year.
Progress 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 Progress and ProEx
(computed in accordance to the Technical Services Agreement - see
"Relationship with Progress"). Higher gross G&A was partially offset by higher
operator recoveries due to an increase in wells operated by ProEx as a result
of the Asset Acquisition and drilling activity. Management forecasts G&A
expenses for 2007 to average in the $1.00 to $1.10 per boe range.

    
    ($ thousands)                                             2007      2006
    -------------------------------------------------------------------------
    Direct expenses                                          1,852       850
    Technical services fee from Progress                     5,368     4,521
    -------------------------------------------------------------------------
    Gross G&A                                                7,220     5,371
    Operator recoveries                                     (3,048)   (2,676)
    Capitalized expenses                                    (1,281)     (993)
    -------------------------------------------------------------------------
    Total G&A                                                2,891     1,702
    -------------------------------------------------------------------------
    Total G&A ($boe)                                          0.93      0.88
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Interest and Financing Expense

    Interest and financing charges for 2007 were $4.3 million ($1.38 per boe)
compared to $1.3 million ($0.68 per boe) for 2006. The increase in interest
and financing charges for the year as compared to the prior year, was a result
of higher average debt levels to finance a portion of the Asset Acquisition in
addition to the capital expenditures incurred during the year. Details of
ProEx's bank debt are described in the Capitalization and Capital Resources
section below and Note 4 in the audited financial statements.

    Long Term Incentive Compensation Expense

    For 2007, long term incentive compensation expense, relating to
outstanding stock options, Class B Performance Shares and the Progress long
term incentive compensation plan (the "LTI"), was $2.9 million ($0.92 per boe)
compared to $1.7 million ($0.75 per boe) for 2006. The increase in
compensation expense per boe over the prior year is primarily a result of the
issuance of 1.2 million stock options during 2007 in addition to the expense
relating to the new LTI. At December 31, 2007 there were 1,933,501 options
outstanding at a weighted average exercise price of $12.63 (2006 - 778,334
options at a weighted average price of $10.63).
    During the second quarter of 2007, the LTI was established for the
benefit of the non-executive Progress employees. ProEx agreed to contribute to
the LTI to ensure that service providers retain incentives related to the
success of ProEx. On May 3, 2007, Progress granted an award of 173,789 common
shares of ProEx to Progress employees, in their capacity as service providers
to ProEx, resulting in a total compensation cost of $2.4 million. ProEx has
agreed to reimburse Progress for this expense, the amount of which has been
recorded as a prepaid expense and will be amortized through long term
incentive compensation expense over the two year vesting period. Awards
granted under the LTI will vest on the second anniversary date of the date of
grant. During the year, all of the shares required to fulfill the initial LTI
grant were acquired from the open market by Progress and the cost was
reimbursed by ProEx. ProEx's long term incentive compensation plans are
described in Note 6 in the audit financial statements.

    Depletion, Depreciation and Accretion Expense

    For 2007, depletion and depreciation of capital assets and the accretion
of the asset retirement obligations ("DD&A") was $47.5 million compared to
$21.5 million for 2006. On a boe basis, DD&A expense for 2007 was $15.29
compared to $11.17 for 2006. The increase in DD&A was primarily due to the
Asset Acquisition.

    
    ($ thousands)                                             2007      2006
    -------------------------------------------------------------------------
    Depletion                                               47,034    21,357
    Depreciation                                                 3         3
    Accretion                                                  432       183
    -------------------------------------------------------------------------
    Total depletion, depreciation and accretion             47,469    21,543
    -------------------------------------------------------------------------
    DD&A  ($/boe)                                            15.29     11.17
    Depletion and depreciation rate (%)                       11.0      10.6
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Future Income Taxes

    Future income tax expense for 2007 was $4.5 million (18.3 percent
effective rate) compared to $6.4 million (29.8 percent effective rate) for
2006. The current year provision includes a recovery of $4.2 million relating
to a reduction in future federal and provincial income tax rates enacted
during the year. The Company has approximately $441.0 million of federal tax
pools to shelter taxable income in future years. The federal tax pools are as
follows:

    
    ($ thousands)                                             2007      2006
    -------------------------------------------------------------------------
    Canadian Exploration Expense                            88,000    61,000
    Canadian Development Expense                           111,000    74,000
    Canadian Oil and Gas Property Expense                  152,000    44,000
    Undepreciated Capital Cost                              80,000    42,000
    Other                                                   10,000     5,000
    -------------------------------------------------------------------------
    Total tax pools                                        441,000   226,000
    -------------------------------------------------------------------------
    

    Net Earnings, Comprehensive Income and Funds Generated from Operations

    Net earnings for 2007 of $20.1 million was 32 percent higher than 2006 of
$15.2 million. The increase was due to higher revenues as a result of higher
production in the year, as well as future income tax recoveries due to a
reduction in future federal and provincial income tax rates enacted during the
year. Basic net earnings per share for 2007 was $0.42 per share (2006 - $0.43
per share), while diluted net earnings per share for the year was $0.38 (2006
- $0.36 per share).
    Other comprehensive income for 2007 includes a charge of $4.9 million for
the amortization of the amount recognized in accumulated other comprehensive
income on the adoption of the new accounting standards for financial
instruments (see the "Risk Management" section above). This resulted in total
comprehensive income for 2007 of $15.1 million (2006 - $15.2 million).
    Funds generated from operations increased 70 percent in 2007 to
$73.8 million, compared to $43.5 million for 2006. The increase was due to
higher revenues from increased production as a result of the Asset Acquisition
and successful drilling. Funds generated from operations per basic share for
the year was $1.56 per share (2006 - $1.23 per share), while funds generated
from operations per diluted share for the year was $1.40 (2006 - $1.04 per
share).
    On a per boe basis, net income was $6.46 per boe during the year compared
to $7.86 for 2006. Funds generated from operations was $23.77 per boe during
the year compared to $22.57 per boe in the prior year.
    The following table summarizes the netbacks, funds generated from
operations and net earnings on a barrel of oil equivalent basis for 2007 and
2006:

    
    ($/boe)                                                   2007      2006
    -------------------------------------------------------------------------
    Petroleum and natural gas revenues                       42.55     43.54
    Royalties                                                (9.51)   (12.15)
    -------------------------------------------------------------------------
                                                             33.04     31.39
    Realized gain on financial instruments                    2.56      1.31
    Interest income                                           0.02         -
    -------------------------------------------------------------------------
                                                             35.62     32.70
    Operating expenses                                       (5.09)    (4.75)
    Transportation expenses                                  (4.10)    (3.60)
    -------------------------------------------------------------------------
    Operating netback                                        26.43     24.35
    General and administrative expenses                      (0.93)    (0.88)
    Long term incentive - cash component                     (0.24)        -
    Interest expenses                                        (1.38)    (0.68)
    Asset retirement expenditures(1)                         (0.11)    (0.22)
    -------------------------------------------------------------------------
    Funds generated from operations                          23.77     22.57
    Asset retirement expenditures(1)                          0.11      0.22
    Stock based compensation expense                         (0.68)    (0.43)
    Depletion, depreciation and accretion expenses          (15.29)   (11.17)
    -------------------------------------------------------------------------
    Net earnings before taxes                                 7.91     11.19
    Future income taxes                                      (1.45)    (3.33)
    -------------------------------------------------------------------------
    Net earnings                                              6.46      7.86
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Actual asset retirement costs incurred during the year are classified
        for cash flow purposes on the statement of cash flows as an operating
        item, however these costs are not an expense of the period and are
        therefore added back for purposes of determining net earnings.


    QUARTERLY FINANCIAL SUMMARY

    The following table highlights ProEx's performance for the three month
reporting periods from January 1, 2006 to December 31, 2007:


                                                         2007
    -------------------------------------------------------------------------
    ($ thousands, except per share
     amounts)                              Dec 31  Sept 30  June 30   Mar 31
    -------------------------------------------------------------------------
    Petroleum and natural gas sales        38,057   28,231   37,347   28,524
    Funds generated from operations        22,098   15,176   18,628   17,907
      -Per share basic                       0.42     0.31     0.39     0.45
      -Per share diluted                     0.39     0.28     0.35     0.39
    Net earnings                            7,725      716    7,564    4,066
      -Per share basic                       0.15     0.01     0.16     0.10
      -Per share diluted                     0.14     0.01     0.14     0.09
    Total assets                          549,343  484,888  470,906  339,252
    Bank debt and working capital
     deficiency                           110,986   59,352   88,411   69,858
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

                                                         2006
    -------------------------------------------------------------------------
    ($ thousands, except per share
     amounts)                              Dec 31  Sept 30  June 30   Mar 31
    -------------------------------------------------------------------------
    Petroleum and natural gas sales        23,386   19,419   20,723   20,472
    Funds generated from operations        13,995    8,766   10,118   10,653
      -Per share basic                       0.37     0.24     0.29     0.32
      -Per share diluted                     0.32     0.21     0.25     0.26
    Net earnings                            4,293    2,627    3,978    4,265
      -Per share basic                       0.11     0.07     0.12     0.13
      -Per share diluted                     0.10     0.06     0.10     0.11
    Total assets                          290,307  246,227  217,078  192,613
    Bank debt and working capital
     deficiency                            27,838   41,499   18,364   49,126
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Lower petroleum and natural gas revenue, funds generated from operations
and net earnings in the first three quarters of 2006 was due to a sharp
decline in natural gas prices, while the fourth quarter of 2006 and first and
second quarters of 2007 increased due to consistent production growth and
strengthening natural gas prices. The third quarter of 2007 experienced
declines in realized natural gas prices which was reflected in the lower
revenues, funds generated from operations and net earnings amounts. Production
increases and higher natural gas prices in the fourth quarter of 2007 led to
higher revenues, funds generated from operations and net earnings.

    
    COMMON SHARE INFORMATION

    (thousands)                                               2007      2006
    -------------------------------------------------------------------------
    Weighted average outstanding common shares
      - Basic                                               47,326    35,336
      - Diluted                                             52,702    41,749
    Outstanding securities at December 31,
      - Common shares                                       52,528    39,691
      - Common share options                                 1,934       778
      - Common share warrants                                4,765     6,144
    -------------------------------------------------------------------------
      - Diluted common shares outstanding                   59,227    46,613
    -------------------------------------------------------------------------
      - Class B performance shares                             551       695
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Outstanding securities at February 25, 2008
      - Common shares                                       52,903
      - Common share options                                 1,934
      - Common share warrants                                4,447
      - Diluted common shares outstanding                   59,284
      - Class B performance shares                             524
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Per Share Information

    ($ thousand, except per share amounts)                    2007      2006
    -------------------------------------------------------------------------
    Net earnings                                            20,072    15,163
    Net earnings per share
      - Basic                                                 0.42      0.43
      - Diluted                                               0.38      0.36
    -------------------------------------------------------------------------
    Funds generated from operations                         73,808    43,531
    Funds generated from operations per share
      - Basic                                                 1.56      1.23
      - Diluted                                               1.40      1.04
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    On a per share basis, net earnings for 2007 was consistent with 2006,
while on a diluted basis, net earnings per share increased six percent. Funds
generated from operations per basic share increased by 27 percent in 2007
compared to 2006 while funds generated from operations per diluted share
increased 35 percent.

    INVESTMENT

    Capital Investment

    During 2007 the Company invested approximately $150.2 million with the
drilling of 70 gross wells (45.5 net) for a success rate of 91 percent
(93 percent net). The net property acquisitions include the Asset Acquisition
completed on April 2, 2007 for $136.4 million, as well as an asset acquisition
in the Blair and Cameron areas of the Foothills region completed November 30,
2007 for $14.3 million. The following table summarizes the capital investments
for 2007 and 2006.

    
    ($ thousands)                                             2007      2006
    -------------------------------------------------------------------------
    Land acquisitions and retention                          6,266    17,146
    Geological and geophysical                              11,175    10,252
    Drilling and completions                               109,939    95,913
    Equipping and facilities                                22,787    28,158
    Corporate assets                                             -         9
    -------------------------------------------------------------------------
    Total exploration and development capital              150,167   151,478
    Net property acquisitions (dispositions)               152,523       683
    -------------------------------------------------------------------------
    Total capital expenditures                             302,690   152,161
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Drilling results

                                              2007                2006
    -------------------------------------------------------------------------
                                         Gross       Net     Gross       Net
    -------------------------------------------------------------------------
    Crude oil                                -         -         3       1.3
    Natural gas                             64      42.3        57      41.0
    Dry and abandoned                        6       3.2         3       1.7
    -------------------------------------------------------------------------
    Total                                   70      45.5        63      44.0
    -------------------------------------------------------------------------
    Success rate (%)                        91        93        95        96
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Undeveloped Land

    ProEx has undeveloped land at December 31, 2007 of approximately 433,000
net acres and in addition has access to approximately 32,000 acres of option
lands for a total acreage under its control of approximately 465,000.
Approximately 409,000 net acres (95 percent) of the undeveloped lands are in
the Foothills region of northeast British Columbia and ProEx's average
interest in these lands is 62 percent. Including option lands, ProEx has
441,000 net acres or 95 percent of its acreage in the Foothills region. The
balance of the northeast British Columbia undeveloped lands are in the Fort
St. John Plains region where the Company has an average working interest of
21 percent.

    Undeveloped Land Additions
    During 2007 ProEx acquired approximately 86,000 net acres of undeveloped
land included in the Asset Acquisition, approximately 33,000 net acres
acquired in the Blair and Cameron areas of the Foothills region and purchased
approximately 53,000 net acres at Crown land sales. ProEx has an average
working interest in its undeveloped land base of 56 percent. ProEx continues
to generate opportunities to earn land through farm-ins with 50 sections of
option lands available to it at December 31, 2007. Over the next twelve
months, 11 percent of ProEx's net undeveloped acreage will be subject to
expiry. With an active drilling program, ProEx anticipates minimal undeveloped
acres expiring in 2008.

    Option Land Additions
    At December 31, 2007, ProEx has 32,000 gross acres of land in its core
areas in British Columbia on which it has the option to earn an interest. Of
these option lands, 100 percent are in the Foothills region of British
Columbia. These lands are subject to various agreements whereby the Company
must perform certain activities to earn an interest in the lands. The term of
these agreements extend through various terms to August 2008.

    
                                              2007                2006
    -------------------------------------------------------------------------
                                         Gross       Net     Gross       Net
    -------------------------------------------------------------------------
    Foothills - British Columbia       663,000   409,000   322,000   246,000
    Fort St. John Plains
     - British Columbia                112,000    24,000   126,000    25,000
    -------------------------------------------------------------------------
    Total owned British Columbia
     undeveloped lands                 775,000   433,000   448,000   271,000
    -------------------------------------------------------------------------
    Total controlled British Columbia
     option lands                       32,000         -    14,000         -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    CAPITALIZATION AND CAPITAL RE

SOURCES The Company's total capitalization was $757.8 million at December 31, 2007 with a market value of common shares representing 82 percent of total capitalization and total debt representing 14 percent of total capitalization. The market value of the Company's common shares at December 31, 2007 was $621.4 million compared to $510.0 million in the prior year. (thousands except per share amounts) % 2007 % 2006 ------------------------------------------------------------------------- Common shares outstanding 52,528 39,691 Share price(1) 11.83 12.85 ------------------------------------------------------------------------- Total market capitalization 82 621,406 93 510,029 ------------------------------------------------------------------------- Working capital deficiency 14,105 2,035 Bank debt 96,881 25,803 ------------------------------------------------------------------------- Total debt 14 110,986 5 27,838 ------------------------------------------------------------------------- Asset retirement obligations 1 5,691 - 1,791 Future income tax liability 3 19,752 2 11,291 ------------------------------------------------------------------------- Total capitalization 100 757,835 100 550,949 ------------------------------------------------------------------------- Total debt to total capitalization (%) 15 5 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Represents the closing price on the TSX on December 31. Bank Facility At December 31, 2007 the Company had $96.9 million outstanding on its $185 million credit facilities and a working capital deficit of $14.1 million, resulting in $111.0 million of total debt. In June of 2007, the Company amended its existing credit facilities agreement with its lender from a demand revolving operating credit facility to an extendable revolving term credit facility. In accordance with the terms of the new revolving term credit facilities, the Company now classifies bank debt as a long term liability on its balance sheet. In the third quarter of 2007, the Company increased the credit facility borrowing base from $150 million to $185 million. The credit facilities consist of a $175 million extendible revolving term credit facility and a $10 million working capital credit facility with a syndicate of Canadian chartered banks. The facilities are available on a revolving basis for a period of at least 364 days until June 21, 2008, and such initial term out date may be extended for further 364 day periods at the request of the Company, subject to approval by the banks. Following the term out date, the facilities will be available on a non-revolving basis for a one year term, at which time the facilities would be due and payable. The facility is a borrowing base facility that is determined based on, among other things, the Company's current reserve report, results of operations, current and forecasted commodity prices and the current economic environment. Investing Program Funding ($ thousands) 2007 2006 ------------------------------------------------------------------------- Cash and short term investments, beginning of year - 667 Funds generated from operations 73,808 43,531 Changes in non-cash working capital 12,069 (7,906) Issue of common shares (net of share issue costs) 145,735 90,066 Increase in bank debt 71,078 25,803 Less cash and short term investments, end of period - - ------------------------------------------------------------------------- Capital expenditures and asset acquisitions during the year 302,690 152,161 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The Company's 2007 capital investment program was funded by funds generated from operations and two equity offerings during the year. On April 2, 2007, ProEx issued 8,050,000 common shares at a price of $12.45 per share for aggregate gross proceeds of $100.2 million ($95.6 million net of issue costs) to finance the Asset Acquisition (see "Asset Acquisition" section above). On September 12, 2007 ProEx issued 1,830,000 common shares at a price of $13.70 per common share and 1,420,000 flow-through common shares at a price of $17.65 per flow-through common share. The aggregate proceeds, net of share issue costs of $2.3 million ($1.6 million net of tax) were $47.8 million. The proceeds were used to reduce outstanding bank debt. Working Capital The capital intensive nature of the Company's activities may create a negative working capital position in years with high levels of capital investment. The working capital deficiency increased from $2.0 million as at December 31, 2006 to $14.1 million as at December 31, 2007 due to increased accounts payable as a result of increased capital expenditures for the fourth quarter of 2007 ($60.0 million) compared to the fourth quarter of 2006 ($43.5 million). Substantially all of the Company's petroleum and natural gas production is marketed by Progress under standard industry terms and in accordance with the terms of the Technical Services Agreement. Accounts payable consist of amounts payable to suppliers, field operating activities and capital spending activities. These invoices are processed within the Company's normal payment period. At December 31, 2007 the Company had no material accounts receivable that it deemed uncollectible. The Company actively manages its capital structure. The Company's objective when managing capital is to maintain a flexible capital structure which will allow it to execute on its capital investment program, which includes investing in oil and gas activities which may or may not be successful. Therefore the Company continually strives to balance the proportion of debt and equity in its capital structure to take into account the level of risk being incurred in its capital expenditures. In order to maintain or adjust the capital structure, the Company will consider: its forecasted debt to forecasted funds flow from operations ratio while attempting to finance an acceptable investment program including incremental investment and acquisition opportunities; the current level of bank credit available from the bank syndicate; the level of bank credit that may be obtainable from its banking syndicate as a result of natural gas reserve growth; the availability of other sources of debt with different characteristics than the existing bank debt; the sale of assets; limiting the size of the investment program and new common equity if available on favorable terms. Off-Balance Sheet Arrangements ProEx has no guarantees or off-balance sheet arrangements except for certain lease agreements. ProEx 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". Contractual Obligations and Commitments The Company has an extendible revolving term credit facility with a syndicate of Canadian chartered banks and is available on a revolving basis until June 21, 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, at which time the facilities would be due and payable. Management believes that the facilities will be extended for a further 364 day period by June 21, 2008. ProEx contracts for firm transportation on the Spectra Energy system in British Columbia as well as transportation and processing services at other gas plants in northeast British Columbia. As part of the Company's land capture strategy, it will commit to industry partners to drill wells, and or shoot seismic in order to earn positions in contiguous land blocks. As at December 31, 2007, ProEx had commitments to drill and complete three wells costing approximately $3.3 million (net) in 2008 which will earn lands from area competitors in the Foothills region of northeast British Columbia. These commitments are scheduled in the Company's 2008 capital investment plans. The Company must pay Crown royalties, surface rentals, mineral taxes and abandonment and reclamation costs with respect to its ongoing ownership of hydrocarbon production rights. The amount paid with respect to these burdens will depend on the future ownership, production, commodity prices and regulatory environment at the time. In addition, subsequent to December 31, 2007, the Company entered into several derivative financial instruments under its commodity risk management program, the terms and commitments of which are disclosed in note 9 of the financial statement. The future premiums ProEx is committed to pay are included in the table below. The Company's future contractual commitments are highlighted below. ($ thousands) Total 2008 2009 2010 2011 2012 ------------------------------------------------------------------------- Bank debt(1) 96,881 - 96,881 - - - Gas transmission and treatment 51,964 16,269 15,901 13,688 6,106 - Drilling rig commitments 1,779 1,779 - - - - Operating leases 3,159 2,146 881 132 - - Farm-in commitments 3,280 3,280 - - - - Financial instrument premiums 3,189 3,189 - - - - ------------------------------------------------------------------------- Total contractual obligations 160,252 26,663 113,663 13,820 6,106 - ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Based on existing terms of the revolving term credit facility, however Management believes the term will be extended for a further 364 day period by June 21, 2008, the next renewal date. SELECTED QUARTERLY INFORMATION AND FOURTH QUARTER ANALYSIS Q4 Q3 Q2 Q1 Q4 2007 2007 2007 2007 2006 ------------------------------------------------------------------------- Operational Results Production - Natural gas (mcf/d) 52,917 48,082 49,530 36,631 33,505 - Crude oil (bbls/d) 590 438 414 384 343 - Natural gas liquids (bbls/d) 270 225 239 246 152 - Total production (boe/d) 9,680 8,677 8,909 6,735 6,080 Pricing - Natural gas ($/mcf) 6.48 5.36 7.40 7.57 6.71 - Crude oil ($/bbl) 83.77 77.64 68.32 64.46 60.87 - Natural gas liquids ($/bbl) 78.11 66.98 66.29 61.24 56.35 Selected Financial Results ($ thousands, except per share amounts) Petroleum and natural gas revenue 38,057 28,231 37,347 28,524 23,386 Royalties 7,031 6,349 8,609 7,557 6,367 Realized gain on financial instruments 1,257 3,107 38 3,535 2,524 Operating expenses 4,511 4,062 4,339 2,907 2,586 Transportation expenses 3,615 3,250 3,635 2,232 2,037 General and administrative expenses 478 929 774 710 361 Interest and financing expenses 1,227 1,268 1,299 490 518 Funds generated from operations 22,098 15,176 18,628 17,907 13,995 Depletion, depreciation and accretion expense 13,339 13,037 13,000 8,093 7,600 Net earnings 7,725 716 7,564 4,066 4,293 -Basic per share 0.15 0.01 0.16 0.10 0.11 -Diluted per share 0.14 0.01 0.14 0.09 0.10 Capital Spending -Exploration and development 59,340 33,992 6,591 50,244 43,484 -Net acquisitions and dispositions 14,680 591 137,008 244 53 ------------------------------------------------------------------------- Total capital expenditures 74,020 34,583 143,599 50,488 43,537 ------------------------------------------------------------------------- Bank debt and working capital deficiency (surplus) 110,986 59,352 88,411 69,858 27,838 Shareholders' equity 389,350 380,727 331,044 225,866 225,398 Common shares outstanding 52,528 52,362 48,548 39,829 39,691 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Production Production during the fourth quarter of 2007 (the "Quarter") of 9,680 boe per day was 12 percent higher than the third quarter of 2007 of 8,677 boe per day and 59 percent higher than the fourth quarter of 2006 of 6,080 boe per day. The increase in production over the third quarter of 2007 was due to successful drilling and tie-in work performed during the Quarter. The increase in production over the fourth quarter of 2006 was due to the Asset Acquisition and the successful 2007 capital program. Petroleum and Natural Gas Revenues Petroleum and natural gas revenues for the Quarter increased 35 percent to $38.1 million compared to the third quarter of 2007 of $28.2 million and increased 63 percent over the fourth quarter of 2006 of $23.4 million. Contributing to the increase over the third quarter of 2007 was the increase in production and a 21 percent increase in realized natural gas prices to $6.48 per mcf in the Quarter compared to $5.36 per mcf in the third quarter of 2007. The increase in revenues over the fourth quarter of 2006 was due to the increase in production. Royalties Royalties for the Quarter increased 11 percent to $7.0 million compared to the third quarter of 2007 of $6.3 million and increased 10 percent over the fourth quarter of 2006 of $6.4 million. The increase was due to the increase in revenues compared to those periods. The average royalty rate decreased to 18.5 percent for the Quarter compared to 22.5 percent for the third quarter of 2007 and 27.2 percent for the fourth quarter of 2006. The decrease was due to royalty credits received during the Quarter. Operating Expenses Operating expenses for the Quarter increased 11 percent to $4.5 million from $4.1 million in the third quarter of 2007 due to increased production. Operating expenses for the Quarter were 74 percent higher than the fourth quarter of 2006 of $2.6 million due to increased production, as well as higher operating costs on the properties acquired in the Asset Acquisition. On a boe basis, operating expenses in the Quarter decreased slightly to $5.07 from the $5.09 that was realized in the third quarter of 2007 and increased 10 percent over the fourth quarter of 2006 of $4.62. Transportation Expenses Transportation expenses for the Quarter of $3.6 million ($4.06 per boe) was 11 percent higher than the third quarter of 2007 of $3.3 million ($4.07 per boe) due to the increase in production. Transportation expenses for the Quarter were 77 percent higher than the fourth quarter of 2006 of $2.0 million ($3.64 per boe) on account of higher production, as well as higher transportation and treatment tolls associated with the Asset Acquisition including higher treatment tolls associated with Slave Point production processed through the Keyera-owned Caribou gas plant. Although Management favorably renegotiated the terms of the Caribou gas plant, the benefit will only be recognized in 2008. In British Columbia, Spectra Energy owns the infrastructure that enables gas producers to avoid facility construction in exchange for regulated gathering, processing and transmission fees. This all- in charge is included in transportation expenses. General and Administrative Expenses For the Quarter, G&A expenses of $0.5 million were 49 percent lower than the third quarter of 2007 of $0.9 million on account of higher operator recoveries from higher capital spending. G&A expenses for the Quarter were 32 percent higher than the fourth quarter of 2006 of $0.4 million due to higher technical service fees from Progress as a result of the increased activity and production levels partially offset by higher recoveries and capitalized expenses. On a per boe basis, G&A expenses for the Quarter of $0.54 decreased 53 percent from the third quarter of 2007 of $1.16, consistent with change in total G&A. On a per boe basis, G&A expenses for the Quarter decreased 17 percent from the fourth quarter of 2006 of $0.65 due to the increase in production exceeding the increase in total G&A. Q4 Q3 Q4 ($ thousands) 2007 2007 2006 ------------------------------------------------------------------------- Direct expenses 422 254 451 Technical services fee from Progress 1,635 1,540 1,103 ------------------------------------------------------------------------- Gross G&A 2,057 1,794 1,554 Operator recoveries (951) (623) (867) Capitalized expenses (628) (242) (326) ------------------------------------------------------------------------- Total G&A 478 929 361 ------------------------------------------------------------------------- Total G&A ($boe) 0.54 1.16 0.65 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Interest and Financing Expenses Interest and financing expenses for the Quarter was $1.2 million, consistent with the third quarter of 2007 of $1.3 million and 137 percent higher than the fourth quarter of 2006 of $0.5 million due to increased debt as a result of the Asset Acquisition and capital spending during 2007. On a boe basis, interest and financing expenses for the Quarter were $1.38 compared to $1.59 for the third quarter of 2007 and $0.93 for the fourth quarter of 2006. Depletion, Depreciation and Accretion For the Quarter, DD&A expenses of $13.3 million was consistent with the third quarter of 2007 of $13.0 million and increased 76 percent from the fourth quarter of 2006 of $7.6 million. On a boe basis, DD&A was $14.98 for the Quarter compared to $16.33 for the third quarter of 2007 and $13.59 for the fourth quarter of 2006. The increase over the fourth quarter of 2006 is due to the Asset Acquisition. Income taxes Future income taxes were a recovery of $0.7 million for the Quarter compared to an expense of $0.5 million for the third quarter of 2007 and an expense of $1.9 million for the fourth quarter of 2006. The provision for the Quarter includes a $3.7 million recovery relating the reduction in future federal income tax rates enacted during the Quarter. Net Earnings and Funds Generated From Operations Net earnings for the Quarter increased to $7.7 million ($0.15 per basic share, $0.14 per diluted share) from $0.7 million ($0.01 per basic and diluted share) recognized in the third quarter of 2007. Net earnings for the Quarter were 80 percent higher than the fourth quarter of 2006 of $4.3 million ($0.11 per basic share, $0.10 per diluted share). The increase was due to both higher revenues in the Quarter, as well as the future income tax recovery described above. Funds generated from operations for the Quarter were $22.1 million ($0.42 per basic share, $0.39 per diluted share), a 46 percent increase over the $15.2 million ($0.31 per basic share, $0.28 per diluted share) for the third quarter of 2007. The increase was due to increased production and natural gas prices. Funds generated from operations for the Quarter was 58 percent higher than the fourth quarter of 2006 of $14.0 million ($0.37 per basic share, $0.32 per diluted share). The increase was due to increased revenues as a result of the Asset Acquisition and the successful 2007 capital program. Capital Investment Exploration and development expenditures during the Quarter of $59.3 million was 75 percent higher than the $34.0 million spent in the third quarter of 2007 and 36 percent higher than the $43.5 million spent in the fourth quarter of 2006. The increase in the Quarter compared to the third quarter of 2007 was due to the timing of capital projects as ProEx typically conducts more drilling in the fourth quarter than in the third. The increase over the fourth quarter of 2006 is due to the increased size of the Company. During the Quarter, ProEx acquired certain petroleum and natural gas assets in the Blair and Cameron areas of the Foothills region for $14.3 million. ENVIRONMENT, HEALTH AND SAFETY ProEx 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. ProEx actively participates in industry-recognized programs at the highest possible levels in an effort to support continuous improvement. ProEx is committed to meeting its responsibilities to protect the environment through a variety of programs and actively monitoring its compliance with all regulators. ProEx strives to employ capital and energy efficient methods to minimize its footprint and maximize the recovery of its resources. In 2007 ProEx achieved the Canadian Association of Petroleum Producers ("CAAP") highest level, "Platinum". Platinum stewardship means that ProEx 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. ProEx participated in the Environment, Health and Safety Stewardship Program developed by CAAP. ProEx's 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. ProEx 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. ProEx 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 ProEx is becoming more active with contractor safety management through industry committee participation and the promotion of industry recognized best practices. In 2007, ProEx's overall safety and environmental performance remained relatively static compared to 2006. Contractor safety statistics have increased in part due to enhanced reporting and tracking practices. There was no employee lost time incidents in 2007 or 2006. A total of 15 recordable injury incidents, all contractors, were recorded in 2007, compared to nine incidents in 2006. ProEx's contractors had three lost-time incidents in 2007 compared to two 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. OUTLOOK AND 2008 BUDGET With the Company's extensive exploration and development drilling inventory, undeveloped land position, low finding costs and balance sheet strength, it is well positioned to capitalize on its opportunities in 2008 and beyond. Our exploration land base in northeast British Columbia has grown very rapidly to approximately 465,000 acres under our control. With the results from our 2007 drilling program and over 2,000 square kilometers of 3-D seismic data in the Foothills, we have developed an extensive knowledge of the subsurface and the opportunities to expand the Halfway tight gas play as well as Cretaceous and the Debolt intervals. We expect to invest approximately $150 million in 2008, almost exclusively in the Foothills region in northeast British Columbia. Approximately 20 percent of the capital program will be invested in land capture and seismic data acquisition to continuously expand our inventory of drilling opportunities. We are targeting average production for 2008 of between 12,000 to 13,000 boe per day and exiting the year between 14,000 to 15,000 boe per day. We anticipate funding our 2008 investment program with funds generated from operations and the existing bank debt facility. 2008 Sensitivities Based on the above assumptions, the following sensitivities are provided to demonstrate the impact on funds generated from operations and net earnings of changes in commodity prices, and interest rates. Funds generated Net ($ thousand) from operations earnings ------------------------------------------------------------------------- Impact on the year ended December 31, 2008 - Change in Canadian crude oil price by $1.00 per barrel 60 43 - Change in average field price of natural gas by Cdn $0.25 per mcf 4,924 3,497 - Change of 1% in prime interest rates 1,393 989 ------------------------------------------------------------------------- ------------------------------------------------------------------------- CRITICAL ACCOUNTING ESTIMATES The preparation of the financial statements in accordance with Canadian GAAP requires Management to make judgments and estimates that affect the financial results of the Company. ProEx's 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 financial statements. The critical estimates are discussed below: Petroleum and Natural Gas Reserves All of ProEx's 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 Company 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. Depletion Expense The Company 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 capital is amortized using the unit-of-production method based on estimated proved reserves. Changes in estimated proved reserves or future development capital 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 obligation 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 Company'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. DISCLOSURE CONTROLS AND PROCEDURES Disclosure controls and procedures have been designed to ensure that information required to be disclosed by ProEx is accumulated and communicated to the Company's Management as appropriate to allow timely decisions regarding required disclosures. The Company'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 Company's internal controls over financial reporting are effective to provide reasonable assurance that material information related to the issuer, is made known to them by others within the Company. It should be noted that while the Company's Chief Executive Officer and Chief Financial Officer believe that the Company's internal controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that these controls 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 objectives of the control system are met. CHANGE IN ACCOUNTING POLICIES AND RECENT ACCOUNTING PRENOUNCEMENTS 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 a suitable control framework. This proposed amendment is expected to apply for the year ended December 31, 2008. ProEx is continuing with its evaluation of ICOFR to ensure it meets the criteria for the proposed certification for December 31, 2008. Financial Instruments The following standards regarding financial instruments are effective for January 1, 2007; 3855 - "Financial Instruments - Recognition and Measurement", 3861 Financial Instruments - Disclosure and Presentation, 1530 - "Comprehensive Income", and 3865 - "Hedges". The standards require all financial instruments other than held-to-maturity investments, loans and receivables, to be included on a company's balance sheet at their fair value. Held-to-maturity investments, loans and receivables would be measured at their amortized cost. The standards create a new statement for comprehensive income that will include changes in the fair value of certain derivative financial instruments. As a result of these new standards, the Company elected not to use hedge accounting beginning January 1, 2007 and marked-to-market its natural gas derivative contracts under its risk management program. The accounting for hedging relationships for prior fiscal years was not retroactively changed, therefore, there was no restatement of the year ended December 31, 2006. Effective December 31, 2007 ProEx 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 9 of the audited financial statements. Capital Disclosures Effective December 31, 2007 ProEx 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 6 of the audited 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 is the process of examining changes to securities rules as a result of this initiative. As this change initiative is in its infancy, ProEx has not determined its impact on its financial position or results of operations. ADDITIONAL INFORMATION Additional information relating to the Company, is filed on SEDAR and can be viewed at www.sedar.com. Also information can also be obtained by contacting the Company at ProEx Energy Ltd. 1200, 205 - 5th Avenue S.W., Calgary, Alberta, Canada T2P 2V7 or by e-mail at ir@proexenergy.com. Information is also accessible on the Company's web site at www.proexenergy.com. BALANCE SHEETS ProEx Energy Ltd. As at December 31 ($ thousands) 2007 2006 ------------------------------------------------------------------------- ASSETS Current Cash and short-term investments - - Accounts receivable 20,091 22,774 Prepaid expenses and deposits 3,473 1,215 ------------------------------------------------------------------------- 23,564 23,989 Property, plant and equipment (Note 3) 525,779 266,318 ------------------------------------------------------------------------- 549,343 290,307 ------------------------------------------------------------------------- ------------------------------------------------------------------------- LIABILITIES Current Accounts payable and accrued liabilities 37,669 26,024 Bank debt (Note 4) - 25,803 ------------------------------------------------------------------------- 37,669 51,827 Bank debt (Note 4) 96,881 - Asset retirement obligations (Note 5) 5,691 1,791 Future income taxes (Note 7) 19,752 11,291 ------------------------------------------------------------------------- 159,993 64,909 SHAREHOLDERS' EQUITY Share capital and warrants (Note 6) 333,861 192,050 Contributed surplus (Note 6) 3,522 1,453 Retained earnings 51,967 31,895 ------------------------------------------------------------------------- 389,350 225,398 ------------------------------------------------------------------------- Commitments (Note 10) ------------------------------------------------------------------------- 549,343 290,307 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to the financial statements Approved on behalf of the Board of Directors (signed) (signed) Gary E. Perron David D. Johnson Director Director STATEMENTS OF EARNINGS, COMPREHENSIVE INCOME AND RETAINED EARNINGS ProEx Energy Ltd. Year ended December 31 ($ thousands, except per 2007 2006 share amounts) ------------------------------------------------------------------------- REVENUES Petroleum and natural gas 132,160 84,000 Royalties (29,546) (23,441) ------------------------------------------------------------------------- 102,614 60,559 Realized gain on financial instruments (Note 1, 9) 7,936 2,524 Interest 72 3 ------------------------------------------------------------------------- 110,622 63,086 ------------------------------------------------------------------------- EXPENSES Operating 15,819 9,172 Transportation 12,732 6,950 General and administrative 2,891 1,702 Long term incentive compensation (Note 6) 2,861 825 Interest and financing 4,284 1,307 Depletion, depreciation and accretion 47,469 21,543 ------------------------------------------------------------------------- 86,056 41,499 ------------------------------------------------------------------------- Net earnings before taxes 24,566 21,587 TAXES Future income taxes (Note 7) 4,494 6,424 ------------------------------------------------------------------------- NET EARNINGS 20,072 15,163 OTHER COMPREHENSIVE INCOME Amortization of fair value of financial instruments (Note 1, 9) (4,947) - ------------------------------------------------------------------------- COMPREHENSIVE INCOME 15,125 15,163 ------------------------------------------------------------------------- Retained earnings, beginning of year 31,895 16,732 ------------------------------------------------------------------------- Retained earnings, end of year 51,967 31,895 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net earnings per share (Note 6) Basic $0.42 $0.43 Diluted $0.38 $0.36 ------------------------------------------------------------------------- See accompanying notes to the financial statements STATEMENTS OF CASH FLOWS ProEx Energy Ltd. Year ended December 31 ($ thousands) 2007 2006 ------------------------------------------------------------------------- Cash provided by (used in) OPERATING Net earnings 20,072 15,163 Depletion, depreciation and accretion 47,469 21,543 Long term incentive compensation (Note 6) 2,114 825 Asset retirement expenditures (Note 5) (341) (424) Future income taxes 4,494 6,424 ------------------------------------------------------------------------- 73,808 43,531 Change in non-cash working capital (Note 8) 1,592 (6,134) ------------------------------------------------------------------------- 75,400 37,397 ------------------------------------------------------------------------- ------------------------------------------------------------------------- FINANCING Increase in bank debt 71,078 25,803 Issue of shares and warrants (Note 6) 152,584 94,247 Share issue costs (Note 6) (6,849) (4,180) Change in non-cash working capital (Note 8) (79) 30 ------------------------------------------------------------------------- 216,734 115,900 ------------------------------------------------------------------------- ------------------------------------------------------------------------- INVESTING Asset acquisitions (Note 3) (150,731) - Capital expenditures (Note 3) (151,959) (152,161) Changes in non-cash working capital (Note 8) 10,556 (1,803) ------------------------------------------------------------------------- (292,134) (153,964) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Decrease in cash and short-term investments - (667) Cash and short-term investments, beginning of year - 667 ------------------------------------------------------------------------- Cash and short-term investments, end of year - - ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to the financial statements NOTES TO FINANCIAL STATEMENTS ProEx Energy Ltd. December 31, 2007 1. SIGNIFICANT ACCOUNTING POLICIES Nature of Business and Basis of Presentation ProEx Energy Ltd. ("ProEx" or the "Company") was incorporated on April 8, 2004 and commenced commercial operations on July 2, 2004 under a Plan of Arrangement. Under the Plan of Arrangement various assets of Progress Energy Ltd. ("Progress") were transferred to ProEx. ProEx is involved in the exploration, development and production of petroleum and natural gas in British Columbia. The financial statements are stated in Canadian dollars and have been prepared in accordance with Canadian generally accepted accounting principles. The preparation of financial statements in conformity with Canadian generally accepted accounting principles 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 period. Actual results may differ from those estimates. Joint Operations Substantially all of the exploration, development and production activities are conducted jointly with others and accordingly, the Company 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 provision for asset retirement obligations 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 Company follows the full cost method of accounting for petroleum and natural gas operations, whereby 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. Petroleum and natural gas assets are evaluated at least annually 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 petroleum and natural gas assets. If the carrying value of the petroleum and natural gas assets is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying value exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves and the lower of cost and market of unproved properties. The cash flows are 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 company 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. Asset Retirement Obligations The Company records a liability for the fair value of legal obligations associated with the retirement of long-lived assets 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 known as the asset retirement cost, which is depleted on a unit-of-production basis over the life of the reserves. The liability is adjusted each reporting period to reflect the passage of time, with the accretion charged to earnings. Estimates used are evaluated on a periodic basis and any adjustments are applied prospectively. 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. Financial Instruments The Company uses derivative financial instruments from time to time to hedge its exposure to commodity price and foreign exchange fluctuations. The Company 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 U.S. dollar denominated petroleum and natural gas sales. The derivative financial instruments are initiated within the guidelines of the Company's risk management policy and the Company does not enter into derivative financial instruments for trading or speculative purposes. On January 1, 2007 ProEx 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 Company 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 was no restatement of the prior period. On adoption, the Company recognized a current asset of $7.4 million for the fair value of its natural gas derivative contracts and an increase to accumulated other comprehensive income of $4.9 million, net of tax of $2.5 million. The $4.9 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 $7.4 million being offset by the amortization of other comprehensive income. The impact of the change in fair value as at December 31, 2007 is disclosed in note 9. 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 9. Revenue Recognition Revenues from the sale of petroleum and natural gas are recorded when title passes to an external party. Income Taxes The Company 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. Flow-through shares The Company issues flow-through shares from time to time to finance a portion of its exploration and development activities. Pursuant to the terms of these issues, the tax benefits associated with the resource expenditures will be renounced to the shareholders in accordance with income tax legislation. To recognize the renunciation of the tax benefits, the future tax liability is increased and share capital is reduced by the estimated amount of the tax benefits renounced to the shareholders at the time the related expenditures are renounced. Stock Based Compensation The Company has established a long term incentive compensation plan for directors and officers of ProEx and Progress employees in their capacity as service providers. The Company follows the fair value method for valuing stock option grants and Class B Performance Share issues. Under this method, the compensation cost attributable to stock options granted and Class B Performance Shares issued is measured at fair value at the grant date and expensed over the vesting period with a corresponding increase to contributed surplus. Upon the exercise of the stock options and conversion of Class B Performance Shares, the consideration paid together with the amount previously recognized in contributed surplus is recorded as an increase to share capital. The Company has not incorporated an estimated forfeiture rate for stock options, and Class B Performance Shares that will not vest, rather, the Company accounts for actual forfeitures as they occur. ProEx has participated in a new long term incentive component ("LTI") of Progress' long term incentive plan for non-executive Progress employees in their capacity as service providers. Under the terms of the LTI, Progress employees may be granted LTI awards to be paid in Common Shares of the Company. ProEx agreed to contribute to the LTI to ensure that service providers retain incentives related to the success of ProEx. The LTI awards vest on the second anniversary date of the date of grant. ProEx has agreed to reimburse Progress for this expense and any amount paid is amortized through long term incentive compensation expense over the vesting period. The details of the LTI is described in note 6. 2. RELATIONSHIP WITH PROGRESS ENERGY LTD. In conjunction with the Plan of Arrangement, ProEx and Progress entered into a Technical Services Agreement which provides for the shared services required to manage ProEx's activities and define the allocation of general and administrative expenses between the entities. Under the Technical Services Agreement, ProEx is charged a technical services fee by Progress, on a cost recovery basis, in respect of management, development, exploitation, operations and marketing activities on the basis of relative production and capital expenditures. For the year ended December 31, 2007, the technical services fee was $6.3 million (2006 - $4.5 million). Under the Technical Services Agreement, Progress markets ProEx's natural gas, crude oil and natural gas liquids under standard industry marketing arrangements on a cost recovery basis. 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 at some other date as may be mutually agreed. To ensure good governance practices, both ProEx and Progress have each created independent committees of their Board of Directors to monitor compliance with the Technical Services Agreement and the Protocol Arrangement. As contemplated in the Plan of Arrangement, the Company has issued Class B Performance Shares and stock options to officers and directors of ProEx and employees of Progress in their capacity as service providers to ProEx. ProEx and Progress have joint interest in certain properties and undeveloped land. These joint interest properties are governed by standard industry agreements and in addition, the companies have entered into a Protocol Arrangement that specifies how each company will govern the management of 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. Both Progress and ProEx have created independent committees of their board of directors to monitor compliance with the Technical Services Agreement and the Protocol Arrangement. On April 2, 2007, ProEx acquired certain interests in northeast British Columbia Foothills assets previously acquired by Progress. ProEx's total consideration, including transaction costs of $0.9 million was $136.4 million. When considering the bid process for the Asset 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, ProEx and Progress 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, ProEx acquired an 80 percent interest ($14.3 million) and Progress acquired a 20 percent interest in the assets ($3.6 million). As at December 31, 2007, accounts receivable included $0.7 million due from Progress, which includes standard joint venture amounts including revenue. These amounts were received subsequent to the year end. 3. PROPERTY, PLANT AND EQUIPMENT ($ thousands) 2007 2006 ------------------------------------------------------------------------- Petroleum and natural gas properties 607,392 300,894 Accumulated depletion, depreciation (81,613) (34,576) ------------------------------------------------------------------------- Property, plant and equipment, net 525,779 266,318 ------------------------------------------------------------------------- ------------------------------------------------------------------------- As described in note 2, on April 2, 2007, ProEx acquired certain interests in northeast British Columbia Foothills assets previously acquired by Progress. ProEx's total consideration, including transaction costs of $0.9 million was $136.4 million. The full purchase cost of the Asset Acquisition was recorded to property, plant and equipment (including unproved property value of $16.0 million which is excluded from the calculation of depletion and depreciation), in addition, the Company recorded an asset retirement obligation on the acquired assets of $1.9 million. The Asset Acquisition was financed through an equity offering of 8,050,000 Common Shares of the Company at a price of $12.45 per share for aggregate gross proceeds of $100.2 million ($95.6 million net of issue costs). The remainder of the purchase price was financed through bank debt. On November 30, 2007 ProEx acquired certain assets in the Blair and Cameron areas of the Foothills region for $14.3 million. During the year ended December 31, 2007, the Company capitalized $1.3 million of general and administrative expenses (2006 - $1.0 million) related to exploration and development activities. The calculation of 2007 depletion and depreciation included an estimated $82.1 million (2006 - $46.5 million) for future development capital associated with proven undeveloped reserves and excluded $78.1 million (2006 - $44.6 million) for the estimated value of unproved properties and $3.5 million (2006 - $1.8 million) for the estimated future net realizable value of production equipment and facilities. Depletion and depreciation expense for the year ended December 31, 2007 was $47.0 million (2006 - $21.5 million). The Company performed a ceiling test calculation at December 31, 2007 resulting in the undiscounted cash flows from proved reserves and the lower of cost and market of unproved properties exceeding the carrying value of oil and gas assets. The prices used in the ceiling test evaluation of the Company's oil and gas assets is summarized in the following chart: ------------------------------------------------------------------------- Crude Oil Natural Gas ------------------------------------------------------------------------- West Texas Edmonton AECO Gas Intermediate Par Price Price (Cdn$/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 The Company's credit facilities totaling $185 million are with a syndicate of Canadian chartered banks consisting of a $175 million extendible revolving term credit facility and a $10 million working capital facility. At December 31, 2007 the Company had $96.9 million outstanding on its credit facilities (2006 - $25.8 million on a $100 million facility). On June 21, 2007, the Company amended its' existing credit facility agreement with its' lender from a demand revolving operating credit facility to an extendable revolving term credit facility. In accordance with the terms of the new revolving term credit facility, the Company, beginning in the second quarter of 2007, now classifies bank debt as a long term liability on its balance sheet. On August 16, 2007, the Company increased the credit facility borrowing base from $150 million to $185 million. The facilities are available on a revolving basis for a period of at least 364 days until June 21, 2008, and such initial term out date may be extended for further 364 day periods 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, 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. The credit facilities are secured by a $500 million fixed and floating charge debenture on the assets of the Company. The borrowing base is subject to semi-annual review by the banks. 5. ASSET RETIREMENT OBLIGATIONS The total future asset retirement obligation was estimated based on the Company'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 $28.9 million which will be incurred over the next 42 years with the majority of costs incurred between 2008 and 2020. A credit adjusted risk-free rate of eight percent was used to calculate the fair value of the asset retirement obligations. The following reconciles the Company's asset retirement obligations: ($ thousands) 2007 2006 ------------------------------------------------------------------------- Balance, beginning of year 1,791 1,426 Liabilities incurred 1,819 606 Liabilities settled (341) (424) Liabilities acquired 1,990 - Accretion expense 432 183 ------------------------------------------------------------------------- Balance, end of year 5,691 1,791 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 6. SHARE CAPITAL Authorized Unlimited number of voting Common Shares, without nominal or par value 701,300 Class B Performance Shares, without nominal or par value Issued 2007 2006 ------------------------------------------------------------------------- ($ thousands, except for share and warrant amounts) Number Amount Number Amount ------------------------------------------------------------------------- Common Shares Balance, beginning of year 39,690,659 189,820 32,997,815 98,193 Issued for cash 11,300,000 150,357 6,250,000 93,563 Issued on exercise of Warrants 1,378,511 2,412 433,776 759 Issued on exercise of Class B Performance shares 129,746 1 - - Issued on exercise of Options 29,000 355 10,266 96 Forfeited - - (1,198) (3) Flow through share renouncement (6,094) - Share issue costs, net of tax $2,127 (2006 - $1,393) (4,723) (2,788) ------------------------------------------------------------------------- Balance, end of year 52,527,916 332,128 39,690,659 189,820 ------------------------------------------------------------------------- Warrants Balance, beginning of year 6,143,539 2,223 6,584,503 2,381 Exercised (1,378,511) (496) (433,776) (156) Forfeited - - (7,188) (2) ------------------------------------------------------------------------- Balance, end of year 4,765,028 1,727 6,143,539 2,223 ------------------------------------------------------------------------- Class B Performance Shares Balance, beginning of year 694,661 7 694,851 7 Exercised (143,369) (1) - - Cancelled (95) - (190) - ------------------------------------------------------------------------- Balance, end of year 551,197 6 694,661 7 ------------------------------------------------------------------------- Total share capital and warrants, end of year 333,861 192,050 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Issue of Common Shares On May 17, 2006, ProEx issued 3,000,000 Common Shares at a price of $16.15 per share for aggregate gross proceeds of $48.5 million ($46.3 million net of issue costs). On November 30, 2006 the Company issued 2,000,000 Common Shares at a price of $12.40 per Common Share and 1,250,000 flow-through Common Shares at a price of $16.25 per flow-through Common Share. The aggregate proceeds, net of share issue costs of $2.0 million ($1.4 million net of tax) were $43.1 million. Pursuant to the flow-through share offering, the Company renounced $20.3 million of qualifying resource expenditures, effective December 31, 2006, and incurred these costs in 2007. The future income tax effect and reduction to share capital was accounted for in 2007, the date that the Company filed the renouncement documents with the tax authorities. On April 2, 2007, ProEx issued 8,050,000 Common Shares at a price of $12.45 per Common Share for aggregate gross proceeds of $100.2 million ($95.6 million net of issue costs) to finance the Asset Acquisition (refer to note 3). On September 12, 2007 ProEx issued 1,830,000 Common Shares at a price of $13.70 per Common Share and 1,420,000 flow-through Common Shares at a price of $17.65 per flow-through Common Share. The aggregate proceeds, net of share issue costs of $2.3 million ($1.6 million net of tax) were $47.8 million. Pursuant to the flow-through share offering, ProEx will incur $25.1 million of qualifying resource expenditures prior to December 31, 2008, to satisfy its flow-through share obligation. ProEx will renounce the qualifying resource expenditures to holders of the flow-through shares effective on or before December 31, 2007. The future income tax effect and reduction to share capital will be accounted for in the first quarter of 2008, the date that the Company files the renouncement documents with the tax authorities. Warrants One Common Share may be issued for each Common Share purchase Warrant ("Warrants") at a price of $1.39 per share. All Warrants are exercisable and expire on July 2, 2008. Class B Performance Shares Each Class B Performance Share is convertible into a percentage of a Common Share equal to the closing trading price of the Common Shares on the TSX on the trading day prior to such conversion (the "Current Market Price") less $1.39, if positive, divided by the Current Market Price. Holders of Class B Performance Shares are not entitled to any voting rights or to receive notice of or attend any meetings of the shareholders of the Company, are not entitled to receive any dividends on the performance shares and are not entitled upon any liquidation, dissolution or winding-up of the Company to any return of capital other than the payment of the redemption price for each performance share in preference to the holders of Common Shares. All Class B Performance Shares are exercisable and expire on July 2, 2008. Management of Capital Structure Since inception of the Company in July 2004, $576.7 million has been incurred in capital expenditures and acquisitions (net of dispositions of $12.0 million). This has been funded by cash flow from operating activities (before changes in non-cash working capital) of $158.1 million, the issuance of new equity of $317.5 million and increased bank debt and working capital of $101.1 million. The Company's objective when managing capital is to maintain a flexible capital structure which will allow it to execute on its capital investment program, which includes investing in oil and gas activities which may or may not be successful. Therefore the Company continually strives to balance the proportion of debt and equity in its capital structure to take into account the level of risk being incurred in its capital expenditures. In the management of capital, the Company includes share capital and total debt (defined as the sum of current assets, current liabilities and bank debt) in the definition of capital. The key measures that the Company utilizes in evaluating its capital structure are total debt to cash flow from operating activities (before changes in non-cash working capital) and the current credit available from its creditors in relation to the Company's budgeted capital program. Total debt to cash flow from operating activities (before changes in non- cash working capital) is calculated as total debt divided by cash flow from operating activities (before changes in non-cash working capital) and represents the time period it would take to pay off the debt if no further capital expenditures were incurred and if cash flow from operating activities (before changes in non-cash working capital) stayed constant. At December 31, 2007 total debt was $111.0 million and cash flow from operating activities (before changes in non-cash working capital) for the year ended December 31, 2007 was $73.8 million, resulting in a total debt to cash flow from operating activities (before changes in non-cash working capital) ratio of 1.50. Annualized fourth quarter 2007 cash flow from operating activities (before changes in non- cash working capital) was $87.2 million, resulting in a total debt to cash flow from operating activities (before changes in non-cash working capital) ratio of 1.26. Both of these ratios are in an acceptable range for the Company. The Company manages its capital structure and makes adjustments by continually monitoring its business conditions, including; the current economic conditions; the risk characteristics of the underlying assets; the depth of its investment opportunities, forecasted investment levels; the past efficiencies of our investments; the efficiencies of the forecasted investments and the desired pace of investment; current and forecasted total debt levels; current and forecasted natural gas prices and other factors that influence natural gas prices and cash flow from operating activities (before changes in non-cash working capital), such as foreign exchange and basis differential. In order to maintain or adjust the capital structure, the Company will consider: its forecasted debt to forecasted cash flow from operating activities (before changes in non-cash working capital) ratio while attempting to finance an acceptable investment program including incremental investment and acquisition opportunities; the current level of bank credit available from the bank syndicate; the level of bank credit that may be obtainable from its banking syndicate as a result of natural gas reserve growth; the availability of other sources of debt with different characteristics than the existing bank debt; the sale of assets; limiting the size of the investment program and new common equity if available on favorable terms. During 2007, the Company's strategy in managing its capital was unchanged. Earnings per share Net earnings per Common Share figures have been calculated using the treasury stock method. The following table reconciles the denominators used for the basic and diluted earnings per Common Share calculations. Weighted Average Common Shares 2007 2006 ------------------------------------------------------------------------- Basic 47,326,111 35,335,754 Effect of Warrants 4,820,057 5,772,849 Effect of stock options - 22,669 Effect of Class B Performance Shares 555,858 617,697 ------------------------------------------------------------------------- Diluted 52,702,026 41,748,969 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Long term incentive compensation Stock options Under the terms of the stock option plan (the "Plan"), directors and officers of ProEx and Progress employees in their capacity as service providers, may be granted options to purchase Common Shares. The Plan provides for the granting of up to 10 percent of the issued and outstanding Common Shares of the Company. As at December 31, 2007, the Company could grant up to 5,252,792 options. Options granted under the Plan have a term of five years to expiry and vest equally over a three year period starting on the first anniversary date of the grant. The exercise price of each option equals the market price of the Company's Common Shares on the date of grant. The following table sets forth a reconciliation of the Plan activity through December 31, 2007. Weighted average Number of exercise options price ------------------------------------------------------------------------- Balance, December 31, 2005 471,600 8.38 Granted 324,000 13.85 Exercised (10,266) 7.76 Forfeited (7,000) 14.64 ------------------------------------------------------------------------- Balance, December 31, 2006 778,334 10.63 Granted 1,207,500 13.87 Exercised (29,000) 10.72 Forfeited (23,333) 13.16 ------------------------------------------------------------------------- Balance, December 31, 2007 1,933,501 12.63 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The following table summarizes stock options outstanding and exercisable under the Plan at December 31, 2007. Options outstanding Options exercisable Weighted Weighted Number ex- Weighted Range of Number average average ercisable average exercise outstanding remaining con- exercise at year exercise price at year end tractual life price end price ------------------------------------------------------------------------- $5.60 to $7.95 224,000 1.59 5.80 219,333 5.75 $9.08 to $13.40 275,001 2.73 11.27 132,001 10.70 $13.66 to $16.50 1,434,500 4.35 13.96 78,833 14.43 ------------------------------------------------------------------------- 1,933,501 3.77 12.63 430,167 8.86 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The Company accounts for its long term incentive compensation using the fair value method. Under this method, a compensation cost is charged over the vesting period for stock options and Class B Performance Shares granted to officers and directors of ProEx and Progress employees in their capacity as service providers, with a corresponding increase to contributed surplus. The fair value of the options granted during the year ended December 31, 2007 and December 31, 2006 was estimated on the date of grant using the Black-Scholes option pricing model with weighted average assumptions and resulting values for grants as follows: Assumptions 2007 2006 ------------------------------------------------------------------------- Risk free interest rate (%) 4.48 3.97 Expected life (years) 3.00 3.00 Expected volatility (%) 40.4 42.5 ------------------------------------------------------------------------- Weighted average fair value of options granted ($) 5.88 5.94 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The following table reconciles the Company's contributed surplus: ($ thousands) 2007 2006 ------------------------------------------------------------------------- Balance, beginning of year 1,453 637 Stock based compensation expense Stock options 2,090 748 Class B Performance shares 24 77 Redemption of Common Shares and warrants (45) 5 Exercise of Stock Options - (14) ------------------------------------------------------------------------- Balance, end of year 3,522 1,453 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ProEx has agreed to participate in the long term incentive component ("LTI") of Progress' long term incentive plan for non-executive Progress employees in their capacity as service providers. Under the terms of the LTI, Progress employees may be granted LTI awards to be paid in Common Shares of the Company. ProEx agreed to contribute to the LTI to ensure that service providers retain incentives related to the success of ProEx. Awards granted under the LTI will vest on the second anniversary date of the date of grant. ProEx has agreed to reimburse Progress for this expense, therefore the total compensation expense has been included in prepaid expenses and will be amortized through long term incentive compensation expense over the two year vesting period. On May 3, 2007, ProEx committed to an award of 173,789 Common Shares of ProEx to Progress employees in their capacity as service providers at a total compensation cost of $2.4 million. For the year ended December 31, 2007 $0.7 million was charged to long term compensation expense (2006 - nil) and $0.1 million was capitalized (2006 - nil). Accumulated Other Comprehensive Income ------------------------------------------------------------------------- ($ thousands) 2007 2006 ------------------------------------------------------------------------- Balance, beginning of year - - Fair value of financial instruments upon initial adoption of new accounting standard (net of tax of $2.5 million) 4,947 - Fair value applicable to the year, amortized to earnings (net of tax of $2.5 million) (4,947) - ------------------------------------------------------------------------- Balance, end of year - - ------------------------------------------------------------------------- ------------------------------------------------------------------------- 7. FUTURE INCOME TAXES The provision for future income taxes in the statements of earnings and retained earnings reflect an effective tax rate which differs from the expected statutory tax rate. Differences were accounted for as follows: ($ thousands) 2007 2006 ------------------------------------------------------------------------- Net earnings before taxes 24,566 21,587 Statutory income tax rate 33.12% 35.31% ------------------------------------------------------------------------- Expected income taxes 8,136 7,622 Add (deduct): Non-deductible crown charges - 2,294 Resource allowance - (1,943) Change in provincial/federal tax rates (4,178) (1,770) Other 536 221 ------------------------------------------------------------------------- Future income tax expense 4,494 6,424 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The future income tax liability at December 31, 2007 and December 31, 2006 is comprised of the tax effect of temporary differences as follows: ($ thousands) 2007 2006 ------------------------------------------------------------------------- Property, plant and equipment 24,245 13,878 Asset retirement obligations (1,479) (549) Loss carry-forward (78) (90) Share issue costs (2,765) (1,731) Attributed Canadian Royalty Income (171) (217) ------------------------------------------------------------------------- Future income tax liability 19,752 11,291 ------------------------------------------------------------------------- ------------------------------------------------------------------------- As at December 31, 2007, the Company has federal tax deductions of approximately $441.0 million (2006 - $226.0 million) that is available to shelter future taxable income. 8. SUPPLEMENTAL CASH FLOW INFORMATION Changes in non-cash working capital ($ thousands) 2007 2006 ------------------------------------------------------------------------- Accounts receivable 2,683 (8,526) Prepaid expenses and deposits (2,259) (847) Accounts payables and accrued liabilities 11,645 1,466 ------------------------------------------------------------------------- Change in non-cash working capital 12,069 (7,907) Relating to: Financing activities (79) 30 Investing activities 10,556 (1,803) ------------------------------------------------------------------------- Operating activities 1,592 (6,134) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Interest ($ thousands) 2007 2006 ------------------------------------------------------------------------- Interest paid (4,111) (1,210) Interest received 72 3 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 9. FINANCIAL INSTRUMENTS Fair value of financial assets The Company's financial instruments recognized in the balance sheet as at December 31, 2007 consist of cash and short-term investments, accounts receivable, accounts payable and accrued liabilities and bank debt. The fair value of these instruments approximate their carrying amounts due to their short terms to maturity or the indexed rate of interest on the bank debt. From time to time ProEx enters into derivative natural gas contracts ("financial instruments"), however there were none outstanding as at December 31, 2007. Credit risk Substantially all of the Company's petroleum and natural gas production is marketed under standard industry terms by Progress in accordance with the Technical Services Agreement. ProEx monitors the financial condition of Progress on a quarterly basis in order to mitigate the concentration of credit risk with this counterparty. At December 31, 2007 $0.7 million was owed from Progress and was received subsequent to year end. All other accounts receivable are with customers and joint venture partners in the petroleum and natural gas business under normal industry sale and payment terms and are subject to normal credit risks. The Company routinely assesses the financial strength of its customers. At December 31, 2007, financial assets on the balance sheet are only comprised of accounts receivable. There were no natural gas derivative contracts outstanding at December 31, 2007. The maximum credit exposure at December 31, 2007 is the carrying amount of accounts receivable of $20.1 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. Production is sold to customers with investment grade credit ratings, if available in the area of production, or parental guarantees and letters of credit are sought. Of the $20.1 million accounts receivable outstanding, $13.5 million related to the sale of petroleum and natural gas and was received January 25, 2008. Of the remaining balance, $3.1 million was due from the federal and provincial governments relating to GST refunds and provincial drilling credits and $3.6 million was due from joint venture partners, including Progress mentioned above, relating to the recovery of their interest in operating costs and capital spent. The largest amount owing from one partner was $0.9 million. As the operator of properties, ProEx 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 allowance for the impairment of accounts receivable. Currency risk The Company does not sell or transact in any foreign currency, however, the United States ("U.S.") 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 accurately quantified. There were no derivative natural gas contracts outstanding at December 31, 2007. The Company's other financial assets and liabilities are not affected by a change in currency rates. Interest rate risk The Company is exposed to interest rate risk on its outstanding bank debt which has a floating interest rate and would impact the Company's future cash flows. The Company had no interest rate swaps or hedges at December 31, 2007. Liquidity risk Liquidity risk relates to the risk the Company will encounter difficulty in meeting obligations associated with financial liabilities. The financial liabilities on its balance sheet consist of accounts payable and bank debt. The credit facilities are available on a revolving basis for a period of at least 364 days until June 21, 2008, and such initial term out date may be extended for further 364 day periods 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, at which time the facilities would be due and payable. ProEx anticipates it will continue to have adequate liquidity to fund its financial liabilities through its future cash flows and available credit facility (for further information, refer to "Management of Capital Structure" in note 6). The Company 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. Currency risk has no impact on the value of the financial assets and liabilities on the balance sheet at December 31, 2007. Changes to the U.S. to Canadian exchange rate, however, could influence future petroleum and natural gas prices which could impact the value of certain derivative contracts, however this indirect influence cannot be accurately quantified. In regards to interest rate risk, an increase or decrease of one percent to the effective interest rate for the Company would have impacted net earnings by $0.5 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 $0.1 million and a $0.25 change to the price per thousand cubic feet of natural gas would have impacted net earnings by $2.9 million. Financial Derivative Contracts ProEx enters into derivative natural gas 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 2007, the Company's natural gas price risk management program had a net realized gain of $7.9 million (2006 - 2.5 million). As described in note 1, the Company 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 $7.4 million and resulted in an increase to accumulated other comprehensive income and the future income tax liability of $4.9 million and $2.5 million, respectively. The $4.9 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 statements of earnings. As a result, for the year ended December 31, 2007, $4.9 million, net of tax, was charged to other comprehensive income with a corresponding unrealized gain on financial instruments of $7.4 million, and a charge to future income tax expense of $2.5 million. The unrealized gain of $7.4 million was offset by the change in fair value on the natural gas financial instruments from January 1, 2007 of $7.4 million resulting in an unrealized gain of nil for 2007. Contracts entered into subsequent to December 31, 2007 are as follows: Pricing Strike Cost/ Natural Gas Volume Point Price ($gj) Premium Term ------------------------------------------------------------------------- Swap - call Cdn$7.02 - Apr 01/08- spread(1) 10,000 gj/d AECO Cdn$8.02 $0.37/gj Oct 31/08 Swap - call Cdn$7.12 - Apr 01/08- spread(1) 10,000 gj/d AECO Cdn$8.12 $0.37/gj Oct 31/08 Swap - call Cdn$7.22 - Apr 01/08- spread(1) 10,000 gj/d AECO Cdn$8.22 $0.37/gj Oct 31/08 Swap - call Cdn$7.83 - Apr 01/08- spread(1) 10,000 gj/d AECO Cdn$8.83 $0.38/gj Oct 31/08 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Call spread strike prices indicate minimum floor and maximum ceiling 10. COMMITMENTS The Company is committed to future minimum payments for natural gas transmission and processing, operating leases on compression equipment, drilling rig contracts, farm-in agreements and future premiums on financial derivative contracts. The Company's extendible term credit facility is available on a revolving basis until June 21, 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 - $26.7 million; 2009 - $113.7 million; 2010 - $13.8 million; 2011 - $6.1 million; and 2012 - nil. 2007 SELECTED QUARTERLY INFORMATION ProEx Energy Ltd. FINANCIAL HIGHLIGHTS ($ thousands, except per share amounts) Three months ended 2007 Annual ------------------------------------------------------------------------- March 31 June 30 Sept. 30 Dec. 31 2007 ------------------------------------------------------------------------- Income Statement Petroleum and natural gas revenues 28,524 37,347 28,231 38,057 132,160 Funds generated from operations 17,907 18,628 15,176 22,098 73,808 Per share - basic 0.45 0.39 0.31 0.42 1.56 Per share - diluted 0.39 0.35 0.28 0.39 1.40 Net earnings 4,066 7,564 716 7,725 20,072 Per share - basic 0.10 0.16 0.01 0.15 0.42 Per share - diluted 0.09 0.14 0.01 0.14 0.38 Balance Sheet Capital investment Land acquisitions and retention 2,811 290 1,225 1,940 6,266 Geological and geophysical 4,885 1,181 1,424 3,686 11,175 Drilling and completions 34,660 3,387 26,409 45,483 109,939 Equipping and facilities 7,888 1,733 4,934 8,232 22,787 Net property acquisitions (dispositions) 244 137,007 591 14,681 152,523 ------------------------------------------------------------------------- 50,488 143,598 34,583 74,022 302,690 ------------------------------------------------------------------------- Total debt Bank debt 59,772 95,149 53,777 96,881 96,881 Working capital deficiency (surplus) 10,086 (6,738) 5,575 14,105 14,105 ------------------------------------------------------------------------- 69,858 88,411 59,352 110,986 110,986 ------------------------------------------------------------------------- Shareholders' equity 225,865 331,090 380,727 389,350 389,350 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Share Information (thousands, except per share amounts) Shares outstanding at end of period Common 39,829 48,548 52,362 52,528 52,528 Weighted average shares outstanding for the period Basic 39,768 47,940 49,318 52,121 47,326 Diluted 45,820 53,960 54,575 56,776 52,702 Volume traded 13,855 16,492 12,650 10,157 53,154 Common share price ($) High 15.49 16.74 15.25 14.91 16.74 Low 11.83 14.02 12.79 11.10 11.10 Closing 15.15 15.00 14.14 11.83 11.83 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 2007 SELECTED QUARTERLY INFORMATION ProEx Energy Ltd. OPERATIONAL HIGHLIGHTS Three months ended 2007 Annual ------------------------------------------------------------------------- March 31 June 30 Sept. 30 Dec. 31 2007 ------------------------------------------------------------------------- Production Natural gas (mcf/d) 36,631 49,530 48,082 52,917 46,838 Crude Oil (bbls/d) 384 414 438 590 457 Natural gas liquids (bbls/d) 246 239 225 270 245 Total production (boe/d) 6,735 8,909 8,677 9,680 8,509 Pricing Natural gas ($/mcf) 7.57 7.40 5.36 6.48 6.64 Crude oil ($/bbl) 64.46 68.32 77.64 83.77 74.80 Natural gas liquids ($/bbl) 61.24 66.29 66.98 78.11 68.49 Highlights ($/boe) Petroleum and natural gas revenues 47.06 46.07 35.37 42.73 42.55 Realized gain on financial instrument 5.83 0.05 3.89 1.41 2.56 Royalties (12.47) (10.62) (7.95) (7.89) (9.51) Operating expenses (4.80) (5.35) (5.09) (5.07) (5.09) Transportation expenses (3.68) (4.48) (4.07) (4.06) (4.10) ------------------------------------------------------------------------- Operating netback 31.94 25.67 22.15 27.12 26.43 Interest income - 0.08 - 0.01 0.02 General and administrative expenses (1.17) (0.95) (1.16) (0.54) (0.93) Long term incentive compensation expense (cash component) - (0.23) (0.32) (0.34) (0.24) Interest and financing expenses (0.81) (1.60) (1.59) (1.38) (1.38) Asset retirement expenditures (0.42) 0.02 (0.06) (0.06) (0.11) ------------------------------------------------------------------------- Funds generated from operations 29.54 22.99 19.02 24.81 23.77 Unrealized gain/(loss) on financial instruments (6.65) 6.43 (0.41) (0.95) - Asset retirement expenditures 0.42 (0.02) 0.06 0.06 0.11 Stock based compensation expense (0.47) (0.38) (0.79) (1.00) (0.68) Depletion, depreciation and accretion expenses (13.35) (16.04) (16.33) (14.98) (15.29) ------------------------------------------------------------------------- Net earnings before taxes 9.49 12.98 1.55 7.94 7.91 Future income taxes (2.78) (3.63) (0.65) (0.73) (1.45) ------------------------------------------------------------------------- Net earnings 6.71 9.35 0.90 8.67 6.46 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Gross Drilling Results (No. of wells) Natural gas 19 - 15 30 64 Crude oil - - - - - Dry and abandoned 5 - - 1 6 ------------------------------------------------------------------------- 24 - 15 31 70 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net Drilling Results (No. of wells) Natural gas 12.8 - 10.3 19.2 42.3 Crude oil - - - - - Dry and abandoned 2.4 - - 0.8 3.2 ------------------------------------------------------------------------- 15.2 - 10.3 20.0 45.5 ------------------------------------------------------------------------- Success rate (%) 84 - 100 96 93 ------------------------------------------------------------------------- ------------------------------------------------------------------------- %SEDAR: 00020978E

For further information:

For further information: Mr. David Johnson, President & Chief Executive
Officer; Steve A. Allaire, VP Finance and Chief Financial Officer, ProEx
Energy Ltd., 1200, 205 - 5th Avenue S.W., Calgary, Alberta, T2P 2V7, Phone:
(403) 539-1809, Fax - (403) 216-2514, Email ir@proexenergy.com; Web:
www.proexenergy.com

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PROEX ENERGY LTD.

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