Compton reports 2007 year end results



    CALGARY, March 25 /CNW/ - Compton Petroleum Corporation (TSX - CMT,
NYSE - CMZ) is pleased to report its financial and operating results for the
year and quarter ended December 31, 2007.

    
    2007 HIGHLIGHTS

    -  Reserve additions, proved plus probable    22 million boe (net of
                                                  production & divestments),
                                                  9% increase

    -  Reserve value, before tax                  $3.4 billion, 8% DCF

    -  FD&A costs, $/boe
           Including change in future capital     $12.86 proved plus probable
                                                  $23.36 proved

    -  2007 Average production                    31,326 boe/d

    -  Production replacement                     1.9 times

    -  Adjusted cash flow from operations         $196 million
    

    Drilling Results

    During 2007 Compton successfully completed a 322 well drilling program,
with a 97% success rate. Of the 322 wells drilled in 2007, 91% were classified
as development wells and nine percent were classified as exploratory wells,
compared to 84% and 16% respectively in 2006. The higher percentage of
development wells in the current year reflects the increasing success of our
oil and gas plays.
    Of particular note was our very successful horizontal drilling program
targeting the Rock Creek formation in the Niton area of central Alberta. We
completed a total of six horizontal natural gas wells utilizing multi-stage
frac technology with excellent results. As announced in our recent news
release of March 6, 2008 we are excited at the potential of applying this
technology to other core areas including the Basal Quartz at Hooker and the
Belly River in southern Alberta.

    Dispositions and Acquisitions

    We were also very active on the Acquisition and Divestment front during
2007. We pursued our strategy of divesting of non-focus assets and the
redeployment of the proceeds into our focus area natural gas plays. We closed
non-core property divestments, including our conventional light oil property
at Worsley, for total net proceeds of $303.1 million. We also added to our
core areas through a series of property acquisitions that totaled
approximately $73.7 million and completed two corporate acquisitions, Stylus
Energy Inc. and WIN Energy Corporation, that significantly expanded our
presence in southern Alberta and the Foothills at a total cost of
$131.4 million.

    Reserve Growth

    Our 2008 activities resulted in strong reserve growth. We replaced 192%
of our 2007 production on a proved plus probable basis at very competitive
Finding, Development, and Acquisition costs ("FD&A") of $12.86/boe, including
change in future capital. We added 2.3 million boe of proved reserves and
22 million boe proved plus probable reserves, net of production and asset
divestitures. Asset divestitures during the year included total reserves of
12.2 million boe, of which 11.9 million boe were classified as proved
reserves.
    Total proved plus probable reserves rose nine percent from the prior year
to 271 million boe and were valued before tax at $3.4 billion, based on
eight percent discounted cash flow. Total proved reserves at year end were
150 million boe. Proved producing reserves comprise 69% of total proved
reserves. Total proved reserves account for 55% of the proved plus probable
reserves.
    2007 proved plus probable reserves of 271 million boe equate to 2.10 boe
per common share outstanding, versus 1.93 boe per common share in 2006. During
the past five years, we have grown our reserve base at a 21% compound annual
growth rate.

    Production, Revenue, and Adjusted Cash Flow From Operations

    Overall average production, revenue, and adjusted cash flow from
operations for 2007 declined from 2006 levels primarily as a result of an
overall reduction in drilling, particularly during the first half of the year,
and natural declines and property divestments. During the last half of 2007,
activity increased appreciatively. We drilled a total of 238 wells during the
third and fourth quarters of 2007 and fourth quarter production averaged
32,646 boe/d, an increase of 7% over the third quarter.

    2007 Objectives

    A primary goal during 2007 was that of positioning the Company to execute
on its three year strategic plan to realize on the Company's large resource
potential through expanding drill programs. To this end, much was achieved in
2007 including:

    
    -   The continued strengthening of our technical and professional teams
        necessary to manage expanded drilling programs,
    -   The testing of the applicability of advanced drilling and completion
        technologies to our resource plays,
    -   The continued divestment of non-core properties and redeployment of
        capital to our focus areas, and
    -   Developing internal systems and procedures to efficiently and cost
        effectively manage larger drilling programs.

    We are largely pleased with the result of our efforts in these areas and
look forward to 2008.
    The following sections of this news release discuss in significant detail
our 2007 operational and financial results together with our plans for 2008
and beyond.


    FINANCIAL SUMMARY

    -------------------------------------------------------------------------
                      Three Months Ended Dec. 31        Year Ended Dec. 31
    ($000s, except
     per share
     amounts)          2007      2006   % Change    2007      2006   % Change
    -------------------------------------------------------------------------

    Gross revenue    $125,959  $130,289     -3%   $500,987  $540,837     -7%

    Adjusted cash
     flow from
     operations(1)   $ 45,696  $ 55,263    -17%   $196,194  $256,305    -23%
    Per share
      - basic        $   0.35  $   0.43    -19%   $   1.52  $   2.01    -24%
      - diluted      $   0.35  $   0.42    -17%   $   1.48  $   1.92    -23%

    Net earnings     $ 50,457  ($10,037)   603%   $129,266  $127,426      1%
    Per share
      - basic        $   0.39  ($  0.08)   588%   $   1.00  $   1.00      0%
      - diluted      $   0.38  ($  0.08)   588%   $   0.98  $   0.95      3%

    Adjusted net
     earnings from
     operations(2)   $ (2,017) $ 11,822   -117%   $ 21,286  $ 65,168    -67%

    Capital
     expenditures                                 $385,532  $491,511    -22%
    Corporate debt, net                           $871,403  $875,548      0%

    Shareholders'
     equity                                       $869,956  $734,124     19%

    Weighted
     averages
     shares (000s)
      - basic                                      128,993   127,820
      - diluted                                    132,539   133,626
    -------------------------------------------------------------------------
    (1) Adjusted cash flow from operations is a non-GAAP term that represents
        net earnings adjusted for non-cash items. We consider adjusted cash
        flow from operations to be a key financial measure as it demonstrates
        our ability to generate the cash flow necessary to fund future growth
        through capital investment. Adjusted cash flow from operations may
        not be comparable to similar measures presented by other companies.
    (2) Adjusted net earnings from operations was referred to as Operating
        Earnings in prior years.


    OPERATING SUMMARY

    -------------------------------------------------------------------------
                      Three Months Ended Dec. 31        Year Ended Dec. 31
    (6:1 boe
     conversion)       2007      2006   % Change    2007      2006   % Change
    -------------------------------------------------------------------------

    Average daily
     production
      Natural gas
       (MMcf/d)           167       148     13%        145       142      2%
      Liquids (light
       oil & ngls)
       (bbls/d)         4,818     8,600    -44%      7,166     9,516    -25%
      Total oil
       equivalent
       (boe/d)         32,646    33,245     -2%     31,326    33,187     -6%

    Average realized
     prices
      Natural gas
       ($/Mcf)       $   6.00  $   6.48     -7%   $   6.33  $   6.32      0%
      Liquids ($/bbl)   77.60     50.18     55%      62.28     59.09      5%
      Total oil
       equivalent
       ($/boe)       $  41.94  $  42.60     -1%   $  43.82  $  44.65     -2%

    Field operating
     netback ($/boe) $  23.93  $  27.03    -11%   $  26.54  $  28.17     -6%
    Cash flow
     netback ($/boe) $  16.91  $  19.38    -13%   $  18.25  $  21.53    -15%

    Undeveloped land
      Gross acres                                1,121,130   980,179     14%
      Net acres                                    893,462   798,192     12%
      Average working
       interest                                        80%       81%

    Reserves (Mboe)
      Proved oil
       equivalent                                  149,564   147,218      2%
      Proved plus
       probable oil
       equivalent                                  270,819   248,755      9%
      Proved plus
       probable gas
       equivalent, Tcfe                              1.625     1.492

    Proved reserve
     life index (years)                                 13        12
    -------------------------------------------------------------------------
    


    OPERATIONS

    1. PROPERTY REVIEW

    Compton engages in oil and gas exploration and development in the Western
Canada Sedimentary Basin of Alberta, Canada. Our focus is on the Deep Basin
portion of the Basin, which extends from Northwest Alberta and British
Columbia to the United States border. In this large geographical region, we
pursue two types of resource plays. A shallow gas resource play, targeting the
Plains Belly River and overlying Edmonton Horseshoe Canyon zones, and the
three deep gas plays that include the Basal Quartz sands at Hooker, the
Gething/Rock Creek sands at Niton and Caroline in central Alberta, and the
Foothills stacked, thrusted Upper Cretaceous Belly River play at Callum in the
south.

    SHALLOW GAS

    The Plains Belly River and overlying Edmonton Horseshoe Canyon shallow
gas zones cover more than 1,200 sections of Compton held land in southern
Alberta. The entire 900 metre gas-charged section is comprised of multiple
Belly River sands, silts, shales, and coals, overlain by the
Edmonton/Horseshoe Canyon Coals that similarly include sands, silts, and
shales. In 2007 we drilled a total of 226 wells through the Edmonton Horseshoe
Canyon Group targeting the Belly River section. Going forward, we will focus
on downspacing, development drilling, and recompletions in order to establish
a resource manufacturing and processing model designed to maximize production.

    Plains Belly River and Edmonton Coal Bed Methane

    At December 31, 2007, we were producing approximately 55 mmcf/d from 630
Belly River and Edmonton coal bed methane wells. With 1,200 sections of land,
at four wells per section automatic downspacing, this translates to a
significant multi-year, low risk drilling inventory on which to grow our
company.
    During 2007, we took full advantage of the four well per section reduced
spacing initiative for our Belly River drilling program. Wherever possible,
our shallow gas wells were drilled in batches in areas close to existing
infrastructure. This initiative enabled us to significantly reduce our 2007
spud to rig release and rig release to on-stream times to 2.8 days and
99 days, respectively. Drilling results at our southern Alberta Belly River
play were 100% successful in 2007, and we made particularly notable advances
in the Brant, south Hooker, Ghost Pine, and Vulcan areas. Using our 1,200
km(2) of proprietary 3D seismic, coupled with detailed geological mapping, has
allowed us to model the Belly River sands for consistent, repeatable success.
    At Brant, our 3-5-17-27W4M compressor station became fully operational in
November 2007, providing us the requisite horsepower needed to bring on eight
new 100% owned Belly River wells. These wells were producing a combined
four mmcf/d at year end. The average production rate of these wells is
approximately double the 30 day initial production rate of a typical Belly
River well. Our 2007 drilling targeted longer term producing wells such as
Compton Brant 00/07-05-017-27W4M/0 and Compton Silver 00/13-32-016-28W4M/2.
These two wells are producing 570 and 860 mcf/d, respectively. In 2008, we
will aggressively follow up similar trends into south Hooker and south Brant.
    In the Ghost Pine area, we expanded our 15-11-30-23W4M compressor station
from eight to 12 mmcf/d in 2007. A total of 62 Belly River and Horseshoe
Canyon coal wells are currently producing 12 mmcf/d at Ghost Pine. We have 14
standing gas wells that are scheduled to be tied-in in the first quarter 2008.
We have recently reprocessed our 3D seismic in this area, and in 2008 we plan
to use this seismic to replicate the Ghost Pine Belly River gas well
02/07-10-030-23W4M, which had an initial production rate of 1,300 mcf/d, and
the 00/05-01-030-23W4/4 Coal Bed Methane gas well, which had an initial
production rate of 74 mcf/d.
    Finally, further south in the Vulcan area, we placed five Belly River gas
wells drilled by Stylus Energy on production in late 2007. In aggregate, these
wells were placed on production at 2.2 mmcf/d. These wells are the
southernmost Belly River gas wells producing in Alberta.
    Our total compression capacity for southern Alberta low pressure gas is
95 mmcf/d. Compton had 27,000 horsepower of installed compression dedicated to
the play installed and running at year end 2007.
    In 2008, we plan to drill 275 Belly River wells, focusing specifically on
the top tier prospects identified by our technical teams. We have allocated
approximately $180 million in our budget to this area, with $5 million
ear-marked specifically to continue with identification of well locations and
licensing such that as industry conditions improve, we can readily ramp-up
activity. We estimate that roughly 40% of our 2008 Belly River wells drilled
in the latter part of the year will not come on production until early 2009
and will, as a result, take full advantage of the lower shallow gas royalty
rates effective for 2009.
    Our 2008 southern Alberta plans also include an eight well per section
pilot project. Additionally and following on our Deep Basin deeper target
success, we will use extended reach drilling with multi-stage fracturing
techniques.

    DEEP BASIN

    Compton has two Deep Basin gas plays: the Basal Quartz sands at Hooker
and the Gething/Rock Creek sands at Niton and Caroline in central Alberta.

    Southern Alberta: Hooker

    Discovered by Compton in 1999, the Basal Quartz sandstone pool at Hooker
is the southern Alberta extension of the Lower Cretaceous Deep Basin gas
trend. Current production extends over five townships, and in 2007, we drilled
10 wells at Hooker.
    In March 2008, Compton successfully completed the first horizontal well
in southern Alberta at Niton targeting the Basal Quartz formation utilizing
multi-stage fracturing technology. The well at 9-17-17-29W4 was drilled with a
700 metre horizontal leg that flow tested at six mmcf/d. It is scheduled to be
tied-in during mid March. A second horizontal well is currently drilling at
15-30-16-29W4 and 15 follow-up locations have been identified.
    While Compton has been employing horizontal drilling and multi-stage frac
technology in the Niton area in central Alberta with good success, the 9-17
well at Hooker is of major significance in that it establishes that this
technology is applicable to the development of the Hooker Basal Quartz play in
southern Alberta. To date the Hooker play has been developed through drilling
one to two vertical wells per section. Reservoir modeling indicates up to four
vertical wells per section may be necessary to fully develop the play. A
horizontal well could replace two to three vertical wells, eliminating the
need for extensive down-spacing in the area

    Central Alberta: Niton and Caroline

    The Niton area in central Alberta, 150 miles west of Edmonton, is also in
the Alberta Deep Basin fairway. Our main targets are the Jurassic Rock Creek
and Cretaceous Gething, analogous to the Hooker pool in southern Alberta.
Proprietary exploration, development, and operational knowledge gained in
southern Alberta has resulted in accelerated growth of this core area. In
2007, we drilled 35 wells at Niton and Caroline.
    We experienced significant drilling success with our Rock Creek
horizontal gas well program at Niton in 2007. The average cost to drill and
complete a Niton horizontal gas well is $4.5 million, or roughly two times the
cost of a comparative vertical Rock Creek gas well. With a 30 day initial
production average of 5.0 mmcfe/d per well, horizontal wells produce about
four times that of a comparative vertical well. Compton's average horizontal
gas well is 2,600 meters deep and has a 1,000 meter open-hole section.
Multiple open-hole packers are set within the horizontal section and three to
four staged hydraulic fractures are completed. At year end, we had eight Niton
horizontal Rock Creek wells on production. Six of these wells were gas wells
and two were oil wells, with the gas wells producing approximately
16.2 mmcfe/d in aggregate and the two oil wells were producing a combined
153 boe/d.
    To date in 2008 we have drilled two additional horizontal wells at Niton
and a third well is currently drilling. The first well tested 3.0 mmcf/d and
most recently, the well at 4-27-52-17W5 completed at the end of February is
currently flow testing at 11 mmcf/d. The third well is scheduled to be
completed later this month. Production from these wells will be facility
constrained pending the completion of additional compression and gathering
lines. This work is currently underway and is scheduled for completion by the
end of March barring any delay resulting from an early spring break-up. A
total of 10 additional locations are planned for this area in 2008.
    In 2008, Compton's Niton budget plans for 15 horizontal wells using this
multi-stage frac technology. Last year's focus by a number of producers,
including Compton, targeted the Compton discovered Edson Rock Creek P pool.
Following the Niton Rock Creek successes, Compton posted and acquired a 100%
interest in 12 sections of mineral rights on a second Rock Creek discovery.
Late in 2007, Compton drilled Edson 00/01-31-052-16W5M/0 discovery well on
this 100% block of land. This well was successful and is currently producing
at 3.5 mmcfe/d.
    All major compression equipment has been ordered for this play and we are
currently drilling the third and fourth horizontal wells in this play. Pending
break-up and drilling success, we plan to have eight 100% working interest
horizontal wells on stream by the end of May 2008.
    For 2008 we have allocated approximately $135 million or 33% of our total
planned capital expenditures to our central Alberta resource play. We plan to
drill 48 wells in this area, with 13 of these wells slated to be horizontal.
The 2008 plan is to continue to aggressively drill similar Rock Creek plays
and to transfer this multi-staged horizontal fracture technology to other
Compton operated deep basin gas plays throughout Alberta.

    FOOTHILLS

    Our Callum/Cowley property consists of a series of over pressured,
thrusted, low permeability Belly River sands in the foothills of southern
Alberta. A total of 15 exploratory wells have been drilled over the life of
the play. Based on our initial detailed geological, geophysical, and
engineering analysis of seismic, cores, well logs, and test and production
data, Callum appears to exhibit many similarities to the deep unconventional
gas pools of the Rocky Mountain region of the United States.
    In 2007, we drilled a horizontal well targeting a specific group of sands
plus intersecting mapped fracture systems. The well came on production at
approximately 6.5 mmcf/d, without stimulation. Further reservoir and
completion work is planned on this well bore in 2008.
    During the fourth quarter of 2007, we acquired WIN Energy Inc., a junior
oil and gas company that was active on lands immediately adjacent to ours.
This $30 million acquisition added 68,000 gross (53,600 net) acres of
undeveloped land in the Cowley area in southern Alberta prospective for the
thrusted Belly River trend. As at December 31, 2007, we held approximately
239 net sections of high impact exploration lands at Callum and Cowley.
    With our acquisition of WIN Energy Inc., we also acquired 55 kilometres
of 2D seismic and a new 36 square mile 3D seismic survey surrounding currently
producing wells. Using this seismic data, we plan to replicate our recent
horizontal well success at Callum in the Cowley area. In 2008, we plan to
drill four extended reach horizontal wells. These wells will be oriented to
intersect the maximum number of natural fractures in the foothills gas play.
Each of these horizontal wells will use multi-stage fracturing techniques and
they will be drilled from existing pads to minimize our environmental impact.
We plan to drill a total of nine wells in the Callum and Cowley area in 2008.
    Compton treats the southern Alberta Foothills region as a unique
environmental eco- system. In conjunction with a number of southern Alberta
ranching operations, we are completing a rangeland health assessment that
addresses optimal ways to restore these systems to their natural state. This
includes funding of studies on native rough fescue grasses by the University
of Alberta, as well as working closely with both industry and landowner work
groups. Surface impact on all proposed wells will be minimized by using
existing drill pads or by selecting surface areas on sites previously
disturbed by the agriculture industry.

    OPERATING RESULTS

    UNDEVELOPED LAND

    In 2007, we continued to build and maintain a dominant land position in
our core areas. The Company's total net land inventory increased 15% in 2007,
with acquisitions occurring primarily in the southern and central Alberta core
areas. Net undeveloped land increased 12% from the prior year.

    
    Land Summary

    -------------------------------------------------------------------------
                                     Undeveloped Acres           Total Acres
    Area                              Gross        Net      Gross        Net
    -------------------------------------------------------------------------
    Southern Alberta                576,253    537,631  1,058,145    941,972
    Central Alberta                 311,835    225,437    692,453    399,042
    Peace River Arch                 60,660     35,969    128,980     67,195
    Northern Alberta                143,840     87,345    226,210    122,876
    Other                            28,542      7,080     63,149     11,750
    -------------------------------------------------------------------------
    December 31, 2007 total       1,121,130    893,462  2,168,937  1,542,835
    -------------------------------------------------------------------------

    December 31, 2006 total         980,179    798,192  1,838,863  1,339,481
    -------------------------------------------------------------------------
    

    During 2008, we plan to continue to invest in the future and expand in
our core areas. Our 2008 budget includes $28 million directed towards land
acquisitions and seismic surveys in our major operating areas.

    DRILLING ACTIVITY

    We drilled 322 gross (266 net) wells in 2007 with a 97% success rate,
compared with 342 gross (274 net) wells in 2006.
    Of the 322 wells drilled in 2007, 91% were classified as development
wells and nine percent were classified as exploratory wells, compared to 84%
and 16% respectively in 2006. The higher percentage of development wells in
the current year reflects the increasing maturity of our oil and gas plays.

    
    Drilling Summary

    -------------------------------------------------------------------------
                             Natural
    Years ended December 31,     Gas     Oil     D&A   Total     Net  Success
    -------------------------------------------------------------------------
    Southern Alberta             236       -       1     237     208    100%
    Central Alberta               37       8       6      51      36     88%
    Peace River Arch               3      17       3      23      13     87%
    -------------------------------------------------------------------------

    Standing, cased wells                                 11       9
    -------------------------------------------------------------------------
    2007 Total                                           322     266     97%
    -------------------------------------------------------------------------

    2006 Total                   266      56      20     342     274
    -------------------------------------------------------------------------
    

    RESERVES

    Netherland, Sewell & Associates Inc. ("NSAI"), independent reserve
evaluators, have completed an evaluation of 96% of Compton's petroleum and
natural gas reserves in accordance with National Instrument 51-101. The
remaining four percent of the Company's reserves have been evaluated
internally.
    As required by National Instrument 51-101 "Standards of Disclosure for
Oil and Gas Activities" ("NI 51-101"), Compton filed Form 51-101 F1 as part of
its Annual Information Form ("AIF"). The AIF is considered comprehensive.
Certain information has been summarized below regarding the Company's
operations. All such information is consistent with the Form NI 51-101 F1
filing. Compton's extended disclosure contained in the AIF is available on
both the SEDAR website and Compton's website.

    
    i) Summary of Estimated Reserve Volumes - Forecast Prices and Costs(1)

    -------------------------------------------------------------------------
                                 Crude Oil      Natural Gas         NGLs
                               Gross     Net   Gross     Net   Gross     Net
    As at December 31, 2007    (Mbbl)  (Mbbl)   (Bcf)   (Bcf)  (Mbbl)  (Mbbl)
    -------------------------------------------------------------------------
    Proved
      Developed producing      9,015   8,501     502     411   9,182   6,498
      Developed non-producing    222     197      55      45   1,079     749

      Undeveloped              1,695   1,502     188     154   2,100   1,432
    -------------------------------------------------------------------------
    Total proved              10,933  10,199     745     610  12,362   8,679
    Probable                   6,495   5,842     625     510   9,820   6,879
    -------------------------------------------------------------------------
    Total proved plus
     probable                 17,427  16,042   1,369   1,120  22,182  15,558
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    2006 total proved
     plus probable            29,233  26,213   1,189     984  19,068  13,761
    -------------------------------------------------------------------------


    ----------------------------------------------------------
                                 Sulphur            Total
                              Gross     Net    Gross      Net
    As at December 31, 2007    (Mlt)   (Mlt)   (Mboe)   (Mboe)
    ----------------------------------------------------------
    Proved
      Developed producing     1,968   1,674  103,884   85,205
      Developed non-producing    66      55   10,464    8,559

      Undeveloped               149     124   35,216   28,710
    ----------------------------------------------------------
    Total proved              2,183   1,853  149,564  122,474
    Probable                    839     711  121,255   98,391
    ----------------------------------------------------------
    Total proved plus
     probable                 3,022   2,563  270,819  220,865
    ----------------------------------------------------------

    ----------------------------------------------------------
    2006 total proved
     plus probable            2,271   1,975  248,755  205,895
    ----------------------------------------------------------
    (1) Numbers may not add due to rounding.
    

    In 2007, we added 22 MMboe, after production, to our proved plus probable
reserves primarily through the drill bit. Total proved plus probable reserves
increased nine percent from the prior year to 271 MMboe. Year end 2007
reserves do not include any reserves associated with our light oil asset at
Worsley, which was sold at the end of the third quarter of 2007.
    Our total proved reserve base is comprised of 84% natural gas and 16%
liquids. Proved producing reserves comprise 69% of total proved reserves,
while total proved reserves account for 55% of the proved plus probable
reserves. We have a 13 year proved and a 23 year proved plus probable reserve
life index.

    
    ii) Net Present Value of Reserves - Forecast Prices and Costs(1)

    -------------------------------------------------------------------------
                                            Future net revenue before income
                                            taxes(1) discounted at a rate of
                                           ----------------------------------
    ($millions)                                  0%           8%          10%
    -------------------------------------------------------------------------

    Proved
      Producing                             $2,872       $1,453       $1,304
      Non-producing                            383          183          160
      Undeveloped                            1,020          416          345
    -------------------------------------------------------------------------
    Total proved                            $4,275       $2,051       $1,809
    Probable                                 3,800        1,356        1,109
    -------------------------------------------------------------------------
    2007 Total proved plus probable         $8,075       $3,406       $2,919
    -------------------------------------------------------------------------

    2006 proved plus probable               $7,633       $3,312       $2,845
    -------------------------------------------------------------------------
    (1) Pricing assumptions are the average of four major Canadian oil and
        gas evaluation firms. Numbers may not add due to rounding.

    Future net revenues are calculated based upon estimated revenue less
royalties, operating costs, future development costs, and well abandonment
costs. Estimated income taxes have not been deducted. The net present value
should not be considered the current market value of our reserves or the costs
that would be incurred to obtain equivalent reserves.

    iii) Reserve Reconciliation (before royalties) -- Forecast Prices and
         Costs (1)

    -------------------------------------------------------------------------
                                     Crude oil, Ngls, &
                                           Sulphur           Natural Gas
                                    -----------------------------------------
                                       Proved   Probable   Proved   Probable
                                        (Mbbl)    (Mbbl)    (Bcf)     (Bcf)
    -------------------------------------------------------------------------
    December 31, 2006                   32,745    17,827       687       502
    Extensions, improved recovery,
     & discoveries                       1,460     1,770        60       113
    Technical Revisions                  2,254    -3,377        14       -39
    Acquisitions                         1,386       948        49        50
    Dispositions                        -9,753       -14       -13        -1
    Production                          -2,616         0       -53         0
    -------------------------------------------------------------------------
    December 31, 2007                   25,477    17,154       745       625
    -------------------------------------------------------------------------


    -------------------------------------------------------------
                                                Total
                                   ------------------------------
                                                          Proved
                                                           plus
                                     Proved    Probable  Probable
                                      (Mboe)    (Mboe)    (Mboe)
    -------------------------------------------------------------
    December 31, 2006                147,218   101,537   248,755
    Extensions, improved recovery,
     & discoveries                    11,511    20,549    32,059
    Technical Revisions                4,627    -9,848    -5,221
    Acquisitions                       9,583     9,269    18,851
    Dispositions                     -11,940      -252   -12,192
    Production                       -11,434         0   -11,434
    -------------------------------------------------------------
    December 31, 2007                149,564   121,255   270,819
    -------------------------------------------------------------
    (1) Numbers may not add due to rounding.


    FINDING & DEVELOPMENT COSTS

    -------------------------------------------------------------------------
                                                                      3 Year
    FD&A costs ($/boe)                 2007       2006       2005    Average
    -------------------------------------------------------------------------

    Including future capital
      Proved                         $23.36     $18.48     $15.42     $17.85
      Proved plus probable           $12.86     $13.57     $13.02     $13.17

    Excluding future capital
      Proved                         $24.18     $14.38     $12.84     $15.22
      Proved plus probable           $ 9.95     $ 8.85     $ 7.05     $ 8.27
    -------------------------------------------------------------------------
    

    FINANCIAL REVIEW

    ADVISORIES

    Management's Discussion and Analysis ("MD&A") is intended to provide both
an historical and prospective view of our activities. The MD&A was prepared as
at March 24, 2008, and should be read in conjunction with the audited
consolidated financial statements and related notes for the year ended
December 31, 2007 and the advisories set out below. The consolidated financial
statements have been prepared in accordance with Canadian generally accepted
accounting principles ("GAAP"). A reconciliation to U.S. GAAP is included in
Note 21 to the consolidated financial statements.

    FORWARD LOOKING STATEMENTS

    Certain information regarding the Company contained herein constitutes
forward-looking information and statements and financial outlooks
(collectively, "forward-looking statements") under the meaning of applicable
securities laws, including Canadian Securities Administrators' National
Instrument 51-102 Continuous Disclosure Obligations and the United States
Private Securities Litigation Reform Act of 1995. Forward-looking statements
include estimates, plans, expectations, opinions, forecasts, projections,
guidance, or other statements that are not statements of fact, including
statements regarding (i) cash flow and capital and operating expenditures,
(ii) exploration, drilling, completion, and production matters, (iii) results
of operations, (iv) financial position, and (v) other risks and uncertainties
described from time to time in the reports and filings made by Compton with
securities regulatory authorities. Although Compton believes that the
assumptions underlying, and expectations reflected in, such forward-looking
statements are reasonable, it can give no assurance that such assumptions and
expectations will prove to have been correct. There are many factors that
could cause forward-looking statements not to be correct, including risks and
uncertainties inherent in the Company's business. These risks include, but are
not limited to: crude oil and natural gas price volatility, exchange rate
fluctuations, availability of services and supplies, operating hazards, access
difficulties and mechanical failures, weather related issues, uncertainties in
the estimates of reserves and in projection of future rates of production and
timing of development expenditures, general economic conditions, and the
actions or inactions of third-party operators, and other risks and
uncertainties described from time to time in the reports and filings made with
securities regulatory authorities by Compton. Statements relating to
"reserves" and "resources" are deemed to be forward-looking statements, as
they involve the implied assessment, based on estimates and assumptions, that
the reserves and resources described exist in the quantities predicted or
estimated, and can be profitably produced in the future.
    The forward-looking statements contained herein are made as of the date
of this MD&A solely for the purpose of generally disclosing Compton's views of
its prospective activities. Compton may, as considered necessary in the
circumstances, update or revise the forward-looking statements, whether as a
result of new information, future events, or otherwise, but Compton does not
undertake to update this information at any particular time, except as
required by law. Compton cautions readers that the forward-looking statements
may not be appropriate for purposes other than their intended purposes and
that undue reliance should not be placed on any forward-looking statement. The
Company's forward-looking statements are expressly qualified in their entirety
by this cautionary statement.

    NON-GAAP FINANCIAL MEASURES

    Included in the MD&A and elsewhere in this report are references to
financial measures commonly used in the oil and gas industry, including
adjusted cash flow from operations and adjusted net earnings from operations.
These financial measures are not defined by Canadian generally accepted
accounting principles ("GAAP") and therefore are referred to as non-GAAP
measures. The non-GAAP measures used by the Company may not be comparable to
similar measures provided by other companies. We use these non-GAAP measures
to evaluate our performance.
    Adjusted cash flow from operations should not be considered an
alternative to, or more meaningful than, cash provided by operating, investing
and financing activities or net earnings as determined in accordance with
Canadian GAAP, as an indicator of our performance or liquidity. Adjusted cash
flow from operations is used by us to evaluate operating results and our
ability to generate cash to fund future growth through capital investment.
    Adjusted net earnings from operations represents net earnings excluding
certain items that are largely non-operational in nature and should not be
considered an alternative to, or more meaningful than, net earnings as
determined in accordance with Canadian GAAP. Adjusted net earnings from
operations is used by us to facilitate comparability of earnings between
periods.

    USE OF BOE EQUIVALENTS

    The oil and natural gas industry commonly expresses production volumes
and reserves on a barrel of oil equivalent ("boe") basis whereby natural gas
volumes are converted at the ratio of six thousand cubic feet to one barrel of
oil. The intention is to sum oil and natural gas measurement units into one
basis for improved measurement of results and comparisons with other industry
participants. We use the 6:1 boe measure which is the approximate energy
equivalency of the two commodities at the burner tip. However, boes do not
represent a value equivalency at the plant gate where we sell our production
volumes and therefore may be a misleading measure if used in isolation.

    
    RESULTS OF OPERATIONS

    2007 SUMMARY

    -   Drilled 322 gross (266 net) wells with a 97% success rate.
    -   Achieved annual average production of 31,326 boe/d.
    -   Generated adjusted cash flow from operations of $196.2 million, or
        $1.48 per diluted share.
    -   Adjusted net earnings from operations for the year were
        $21.3 million.
    -   Net earnings for the year were $129.2 million.


    ADJUSTED CASH FLOW FROM OPERATIONS AND NET EARNINGS

    -------------------------------------------------------------------------
    Years ended December 31,                  2007         2006         2005
    -------------------------------------------------------------------------
    Adjusted cash flow from
     operations(1) ($000s)              $  196,194   $  256,305   $  278,112
    Per share: basic                    $     1.52   $     2.01   $     2.21
               diluted                  $     1.48   $     1.92   $     2.11
    Net earnings ($000s)                $  129,266   $  127,426   $   81,326
    Per share: basic                    $     1.00   $     1.00   $     0.65
               diluted                  $     0.98   $     0.95   $     0.62
    -------------------------------------------------------------------------
    (1) Adjusted cash flow from operations is a non-GAAP term that represents
        net earnings adjusted for non-cash items. We consider adjusted cash
        flow from operations to be a key financial measure as it demonstrates
        our ability to generate the cash flow necessary to fund future growth
        through capital investment. Adjusted cash flow from operations may
        not be comparable to similar measures presented by other companies.


    Adjusted cash flow from operations
    -------------------------------------------------------------------------
    Years ended December 31, ($000s)          2007         2006         2005
    -------------------------------------------------------------------------
    Net earnings                        $  129,266   $  127,426   $   81,326
    -------------------------------------------------------------------------
      Amortization of deferred charges
       and other                             3,417        1,996        2,190
    -------------------------------------------------------------------------
      Tender costs                               -            -       20,750
    -------------------------------------------------------------------------
      Depletion and depreciation           151,411      143,057      105,504
    -------------------------------------------------------------------------
      Accretion of asset retirement
       obligations                           2,718        2,257        1,975
    -------------------------------------------------------------------------
      Unrealized foreign exchange (gain)   (79,740)        (665)      (7,808)
    -------------------------------------------------------------------------
      Future income taxes                  (26,452)      (3,636)      52,317
    -------------------------------------------------------------------------
      Unrealized risk management
       (gain) loss                           5,467      (27,522)      10,171
    -------------------------------------------------------------------------
      Stock-based compensation               8,416        9,121        5,903
    -------------------------------------------------------------------------
      Asset retirement expenditures         (4,441)      (2,352)        (749)
    -------------------------------------------------------------------------
      Non-controlling interest               6,132        6,623        6,533
    -------------------------------------------------------------------------
    Adjusted cash flow from operations  $  196,194   $  256,305   $  278,112
    -------------------------------------------------------------------------
    

    Adjusted cash flow from operations declined in 2007 from the prior year's
level by approximately $60 million. The major causes of the decline were a
$25 million reduction in realized risk management gains, a reduction of
$19 million in revenue after royalties, and increases in general and
administrative and interest expenses. Additionally, at the end of the third
quarter of 2007, we closed the sale of our conventional light oil asset at
Worsley, which reduced production, adjusted cash flow from operations, and net
income accordingly for the last three months of the year as compared to the
prior year.
    Net earnings for the year increased by approximately $2 million over 2006
and benefited from a foreign exchange gain of $79 million and a $26 million
future income tax recovery.

    ADJUSTED NET EARNINGS FROM OPERATIONS

    Adjusted net earnings from operations is a non-GAAP measure that
represents net earnings adjusted for certain items of a non-operational and
non-cash nature. We evaluate our performance on adjusted net earnings from
operations which eliminates these non-operational items that can introduce a
level of volatility to net earnings determined in accordance with GAAP.
    The following reconciliation identifies the after-tax effects of certain
items of non-operational nature that are included in our financial results.
Adjusted net earnings from operations may not be comparable to similar
measures presented by other companies.

    
    SUMMARY OF ADJUSTED NET EARNINGS FROM OPERATIONS(1)

    -------------------------------------------------------------------------
    Years ended December 31,
     ($000s, except per share amounts)        2007         2006         2005
    -------------------------------------------------------------------------

    Net earnings, as reported           $  129,266   $  127,426   $   81,326
    Non-operational items, after tax
      Unrealized foreign exchange (gain)   (66,934)        (550)      (6,339)
      Unrealized risk management
       (gain) loss                           3,711      (18,027)       6,345
      Stock-based compensation               5,713        5,974        3,682
      Tender costs on repurchase
       of 9.90% notes                            -            -       14,414
      Future income tax recovery due to
       income tax rate reductions          (50,470)     (49,655)      (5,764)
    -------------------------------------------------------------------------
    Adjusted net earnings from
     operations                         $   21,286   $   65,168   $   93,664
    Per share: basic                    $     0.17   $     0.51   $     0.75
               diluted                  $     0.16   $     0.49   $     0.71
    -------------------------------------------------------------------------
    (1) Adjusted net earnings from operations was referred to as Operating
        Earnings in prior years.

    Revenue

    -------------------------------------------------------------------------
    Years ended December 31,                  2007         2006         2005
    -------------------------------------------------------------------------

    Average production
      Natural gas (mmcf/d)                     145          142          131
      Liquids (bbls/d)                       7,166        9,516        7,646
    -------------------------------------------------------------------------
      Total (boe/d)                         31,326       33,187       29,424

    Benchmark prices
      NYMEX (U.S.$/mmbtu)               $     6.86   $     7.26   $     8.55
      AECO ($/GJ)
        Monthly index                   $     6.27   $     6.21   $     8.04
        Daily index                     $     6.11   $     6.19   $     8.27
      WTI (U.S.$/bbl)                   $    72.37   $    66.22   $    56.56
      Edmonton par ($/bbl)              $    76.23   $    72.77   $    68.72

    Realized prices
      Natural gas ($/mcf)               $     6.33   $     6.32   $     8.36
      Liquids ($/bbl)                        62.28        59.09        56.47
    -------------------------------------------------------------------------
      Total ($/boe)                     $    43.82   $    44.65   $    52.54

    Revenue ($000s)
      Natural gas                       $  334,920   $  327,629   $  398,543
      Liquids                              166,067      213,208      165,698
    -------------------------------------------------------------------------
      Total                             $  500,987   $  540,837   $  564,241
    -------------------------------------------------------------------------


    SUMMARY OF REVENUE INCREASES FROM PRODUCTION AND PRICING

    -------------------------------------------------------------------------
                                       Natural Gas     Liquids         Total
    ($000s)                                Revenue     Revenue       Revenue
    -------------------------------------------------------------------------

    Reported 2006 revenue               $  327,629   $  213,208   $  540,837
    Change in production volumes             7,291      (49,875)     (42,584)
    Change in prices                             -        2,734        2,734
    -------------------------------------------------------------------------
    Reported 2007 revenue               $  334,920   $  166,067   $  500,987
    -------------------------------------------------------------------------
    

    Overall production in 2007 fell 6% from the prior year. Natural gas
volumes increased 2%, while liquids production decreased 25% from 2006
volumes. The significant reduction in our year over year liquids volumes is
attributable to natural declines and the sale of our conventional light oil
asset, Worsley. This transaction closed at the end of the third quarter of
2007.
    We market the majority of our natural gas production through a
combination of daily and monthly indexed contracts and aggregator contracts.
During 2007, approximately 10% of our natural gas production remained
committed to longer term aggregator contracts which realized a price that was,
on average, $0.75/mcf less than that received on non-aggregator volumes.
    Our crude oil sales are priced based upon Edmonton postings and are
typically sold on 30 day evergreen arrangements. Natural gas liquids are bid
out on an annual basis to obtain the most favourable pricing. We sell our
crude oil and natural gas liquids primarily to refineries and marketers of
crude oil and natural gas liquids.
    Periodically we enter into financial instrument contracts to hedge
against price volatility. This activity is fully disclosed in the Risk
Management and Financial Instrument sections of this MD&A. Realized commodity
prices, as reported in the MD&A, are before any hedging gains or losses.

    
    ROYALTIES

    -------------------------------------------------------------------------
    Years ended December 31,
     ($000s, except where noted)              2007         2006         2005
    -------------------------------------------------------------------------

    Crown royalties                     $   86,850   $  100,230   $  105,827
    Other royalties                         15,828       23,447       26,890
    -------------------------------------------------------------------------
    Net royalties                       $  102,678   $  123,677   $  132,717

    Percentage of revenues                   20.5%        22.9%        23.5%
    -------------------------------------------------------------------------
    

    Royalties are paid to various government entities and other land and
mineral rights owners. Virtually all Crown royalties are paid to the province
of Alberta which has a royalty structure based upon commodity prices and well
productivity, with higher prices and well productivity attracting higher
royalty rates. Our royalty rate in 2007, as a percentage of revenue, decreased
from 2006 as a result of the increased contribution from lower productivity
wells to total production.
    We anticipate 2008 royalty rates will remain relatively consistent with
prior years; however, significant changes to the Alberta royalty structure may
occur in 2009 as a result of the recent Alberta royalty review, the final
results of which are yet to be announced.

    
    OPERATING EXPENSES

    -------------------------------------------------------------------------
    Years ended December 31,                  2007         2006         2005
    -------------------------------------------------------------------------

    Operating expenses ($000s)          $  101,478   $  102,643   $   73,164
    Operating expenses per boe ($/boe)  $     8.88   $     8.47   $     6.81
    -------------------------------------------------------------------------
    

    Year over year operating costs remained constant. However, when measured
on a $/boe basis, 2007 operating expenses increased by 5% when compared to
2006. Specific increases of note include salaries for field staff and contract
operators and rising electricity prices. Additionally, fourth quarter 2007
operating costs included significant lease repair and maintenance costs
associated with assets acquired during the last half of the year.
    In prior years, operating costs were reported net of third party
processing fees. Commencing in 2007, third party processing income is included
in revenue and not netted against operating expenses. 2006 and 2005 operating
expenses have been reclassified accordingly.
    With the current reduced level of activity in the industry, we are now
beginning to see indications that cost inflation is moderating. With an
increased emphasis on cost controls, we anticipate 2008 operating costs, on a
unit of production basis, will remain similar to those experienced in 2007.

    
    TRANSPORTATION EXPENSES

    -------------------------------------------------------------------------
    Years ended December 31,                  2007         2006         2005
    -------------------------------------------------------------------------

    Transportation costs ($000s)        $   12,615   $   12,564   $   10,858
    Transportation costs per boe
     ($/boe)                            $     1.10   $     1.04   $     1.01
    -------------------------------------------------------------------------
    

    We incur charges for the transportation of our production from the
wellhead to the point of sale. Pipeline tariffs and trucking rates for liquids
are primarily dependent upon production location and distance from the sales
point. Regulated pipelines transport natural gas within Alberta at tolls
approved by the government.
    2007 transportation expense remained relatively constant with that of
2006. However, with the closing of the sale of our conventional oil property,
Worsley, at the end of the third quarter of 2007, our fourth quarter
transportation expense fell to $0.55/boe, as our oil trucking requirements
were reduced significantly.

    
    GENERAL AND ADMINISTRATIVE EXPENSES

    -------------------------------------------------------------------------
    Years ended December 31,
     ($000s, except where noted)              2007         2006         2005
    -------------------------------------------------------------------------

    General and administrative expenses $   41,633   $   38,321   $   34,638
    Capitalized general and
     administrative expenses                (7,470)      (9,625)     (11,158)
    Operator recoveries                     (2,835)      (2,465)      (2,257)
    -------------------------------------------------------------------------
    Total general and administrative
     expenses                           $   31,328   $   26,231   $   21,223

    General and administrative per boe
     ($/boe)                            $     2.74   $     2.17   $     1.98
    -------------------------------------------------------------------------
    

    Employee costs associated with increased personnel levels, together with
a general increase in remuneration necessary to attract and retain qualified
personnel in a very competitive industry, were the main contributors to the
increase in general and administrative expenses in 2007. Other increases
included insurance and costs associated with ongoing regulatory compliance
requirements. Additionally, increased expenses associated with additional
office space were incurred as a result of corporate acquisitions. During 2007,
we incurred direct expenses totaling approximately $1.5 million relating to
compliance requirements pursuant to the U.S. Sarbanes-Oxley Act of 2002 and
Canadian Multilateral Instrument 52-109.
    General and administrative expenses in 2008 will be impacted by costs
associated with current shareholder activism activities. Such costs will
include additional legal fees, advisory fees and expenses, and employee
retention costs. Such costs are expected to be approximately $22 million, as
discussed in the Outlook and Guidance section of this MD&A and Note 20 to the
financial statements.

    
    INTEREST AND FINANCE CHARGES

    -------------------------------------------------------------------------
    Years ended December 31,
     ($000s, except where noted)              2007         2006         2005
    -------------------------------------------------------------------------

    Interest on bank debt, net          $   22,476   $   14,243   $   11,520
    Interest on Senior Notes                38,345       35,880       20,912
    -------------------------------------------------------------------------
    Interest expense                    $   60,821   $   50,123   $   32,432
    Finance charges                          2,672        3,952        2,519
    -------------------------------------------------------------------------
    Total interest and finance charges  $   63,493   $   54,075   $   34,951
    -------------------------------------------------------------------------
    Total interest and finance charges
     per boe ($/boe)                    $     5.55   $     4.47   $     3.25
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    Weighted average annual debt
     ($000s, except where noted)              2007         2006         2005
    -------------------------------------------------------------------------

    Bank debt                           $  348,216   $  254,476   $  228,381
    Effective interest rate                  6.46%        5.60%        4.23%

    Senior notes (US$)                  $  450,000   $  412,802   $  179,583
    Effective interest rate                  7.63%        7.64%        9.50%
    -------------------------------------------------------------------------

    Interest expenses relating to bank debt in 2007 increased from the prior
year as a result of increased borrowings incurred to fund our 2007 capital
program and overall floating interest rate increases.

    NETBACKS

    -------------------------------------------------------------------------
    Years ended December 31, ($/boe)          2007         2006         2005
    -------------------------------------------------------------------------

    Realized price                        $  43.82     $  44.65     $  52.54
    Realized commodity hedge gain (loss)      1.68         3.24        (0.90)
    Royalties                                (8.98)      (10.21)      (12.36)
    Operating expenses                       (8.88)       (8.47)       (6.81)
    Transportation                           (1.10)       (1.04)       (1.01)
    -------------------------------------------------------------------------
    Field operating netback               $  26.54     $  28.17     $  31.46
    -------------------------------------------------------------------------

    General and administrative               (2.74)       (2.17)       (1.98)
    Interest                                 (5.55)       (4.47)       (3.25)
    Current taxes                                -            -        (0.47)
    -------------------------------------------------------------------------
    Cash flow netback                     $  18.25     $  21.53     $  25.76
    -------------------------------------------------------------------------
    

    RISK MANAGEMENT

    Our financial results are impacted by external market risks associated
with fluctuations in commodity prices, interest rates, and the Canadian/U.S.
dollar exchange rate. We utilize various financial instruments for non-trading
purposes to manage and mitigate our exposure to these risks. Our financial
instruments are not designated for hedge accounting, and accordingly are
recorded at fair value on the consolidated balance sheets, with subsequent
changes recognized in consolidated net earnings and other comprehensive
income.
    Financial instruments utilized to manage risk are subject to periodic
settlements throughout the term of the instruments. Such settlements may
result in a gain or loss, which is recognized as a realized risk management
gain or loss at the time of settlement.
    The mark-to-market values of financial instruments outstanding at the end
of a reporting period reflect the values of the instruments based upon market
conditions existing as of that date. Any change in the fair values of the
instruments from that determined at the end of the previous reporting period
is recognized as an unrealized risk management gain or loss. Unrealized risk
management gains or losses may or may not be realized in subsequent periods
depending upon subsequent moves in commodity prices, interest rates, or
exchange rates affecting the financial instruments.
    Risk management gains and losses recognized in 2007 are outlined below.

    
    -------------------------------------------------------------------------
    Year ended December 31, ($000s)           2007         2006         2005
    -------------------------------------------------------------------------

    Commodity contracts
      Realized (gain) loss              $  (19,220)  $  (39,217)  $    9,663
      Unrealized (gain) loss                20,834      (25,775)       5,136
    Foreign currency contracts
      Realized (gain) loss                   7,739        3,018         (532)
      Unrealized (gain) loss               (15,367)      (1,747)       5,035
    -------------------------------------------------------------------------
    Total risk management (gain) loss   $   (6,014)  $  (63,721)  $   19,302
    -------------------------------------------------------------------------

    Realized (gain) loss                $  (11,481)  $  (36,199)  $    9,131
    Unrealized (gain) loss                   5,467      (27,522)      10,171
    -------------------------------------------------------------------------
    Total risk management (gain) loss   $   (6,014)  $  (63,721)  $   19,302
    -------------------------------------------------------------------------


    DEPLETION AND DEPRECIATION

    -------------------------------------------------------------------------
    Years ended December 31,                  2007         2006         2005
    -------------------------------------------------------------------------

    Total depletion and depreciation
     ($000s)                            $  151,411   $  143,057   $  105,504
    Depletion and depreciation
     per boe ($/boe)                    $    13.24   $    11.81   $     9.82
    -------------------------------------------------------------------------
    

    Accelerated capital programs and competition throughout the oil and gas
industry during the current and prior years increased the demand and costs of
goods and services. This increase in costs is reflected in higher finding,
development, and on-stream costs which in turn, have resulted in an increase
in depletion and depreciation rates on a boe basis in the current year in
comparison to prior periods.

    FOREIGN EXCHANGE

    The foreign exchange gain recognized on the consolidated statements of
earnings results primarily from the translation of our U.S. dollar denominated
Senior Notes into Canadian dollars. The Senior Notes are translated and
recorded in the financial statements at the year end exchange rate, with any
differences from prior measurements being recognized as an unrealized foreign
exchange gain or loss.
    In 2007, we entered into foreign currency exchange contracts related to
our $450 million of U.S. dollar denominated Senior Notes. The notes were
issued in 2005 and 2006 and are due in 2013. The strengthening of the Canadian
dollar against that of the U.S. resulted in the Company recognizing the
unrealized foreign exchange gain referred to in the preceding paragraph. On
October 26 and 31, 2007 we entered into foreign exchange forward contracts to
purchase U.S.$450 million for C$436 million, as at December 1, 2010 being the
second call date on the notes. These contracts effectively crystallize a total
foreign exchange gain of approximately $91.7 million.
    On November 22, 2005, pursuant to a tender offer, we repurchased
U.S.$158 million of the 9.90% Senior Notes issued in 2002. As a result of the
repurchase, we crystallized $62 million of the accumulated unrealized foreign
exchange gains in 2005 that had previously been recognized with the
strengthening of the Canadian dollar subsequent to the note issuance.

    
    STOCK-BASED COMPENSATION

    -------------------------------------------------------------------------
    Years ended December 31,                  2007         2006         2005
    -------------------------------------------------------------------------

    Options granted (000s)                   2,074        2,228        2,930
    Weighted average fair value of
     options granted ($/share)          $     4.23   $     6.90   $     5.45
    Stock-based compensation expense
     recognized ($000s)                 $   11,034   $   10,488   $    5,903
    -------------------------------------------------------------------------
    

    We have a stock option plan for employees, officers, and directors. The
plan is designed to attract, motivate, and retain outstanding individuals and
to align their success with that of our shareholders. The fair value of
options granted is estimated on the date of grant using the Black-Scholes
option pricing model and the associated compensation expense is recognized
over the vesting period.
    During 2006, in recognition of the shortage of, and competition for,
qualified personnel within the oil and gas industry in Western Canada, we
implemented an Employee Retention Program in July 2006 for our existing
employees, excluding officers and directors. Pursuant to the program, and
based upon various conditions existing on July 1, 2007, including the market
value of the Company's shares, we incurred additional compensation expense of
$4.0 million. For the years ended December 31, 2006 and 2007, we recognized
$1.4 million and $2.6 million respectively in stock-based compensation in
relation to this program.

    INCOME TAXES

    Income taxes are recorded using the liability method of accounting.
Future income taxes are calculated based on the difference between the
accounting and income tax basis of an asset or liability. The classification
of future income taxes between current and non-current is based upon the
classification of the liabilities and assets to which the future income tax
amounts relate. The classification of a future income tax amount as current
does not imply a cash settlement of the amount within the following
twelve month period.

    CURRENT INCOME TAXES

    No current income taxes were incurred in 2007 and 2006 primarily as a
result of the elimination of federal capital tax effective January 1, 2006.
Current taxes of $5 million in 2005, in addition to capital taxes, included
$3 million related to the resolution of a Notice of Objection with respect to
a corporate acquisition in a prior tax period. As a result of the reassessment
resulting from resolution of the Notice of Objection, $7 million of tax
deductible exploration expenses denied to the acquired corporation were added
to our income tax pools as a positive offset to incurring the current
liability. The resolution of this matter did not impact our total future
income tax expense for 2006.

    FUTURE INCOME TAXES

    Future income taxes in 2007 included a $50 million recovery as a result
of reductions in the federal corporate tax rates, which were enacted in the
second and fourth quarter of 2007. The federal tax rate is to be reduced by
1.0% in 2008, 1.0% in 2009, 1.0% in 2010, 2.0% in 2011, and 3.5% in 2012.
Future taxes in 2006 also included a $50 million recovery as a result of
reductions in the federal and Alberta corporate tax rates, which were enacted
in the second quarter of 2006.

    
    CORPORATE TAX RATES

    -------------------------------------------------------------------------
    Years ended December 31,                  2007         2006         2005
    -------------------------------------------------------------------------

    Statutory rate                           32.1%        34.5%        37.6%
    Effective rate                         (24.3)%       (2.8)%        39.5%
    -------------------------------------------------------------------------

    A reconciliation of our effective tax rate to the statutory rate may be
found in Note 16a to the consolidated financial statements.

    TAX POOLS

    The following table summarizes our estimated tax pool balances by
classification.

    -------------------------------------------------------------------------
                                                      Available     Maximum
                                                       Balance       Annual
    As at January 1, 2008                              ($000s)     Deduction
    -------------------------------------------------------------------------

    Canadian exploration expense
     and non-capital losses                         $  360,500          100%
    Canadian development expense                       367,241           30%
    Canadian oil and natural gas property expense       74,070           10%
    Undepreciated capital cost and financing costs     316,151          ~25%
    -------------------------------------------------------------------------
    Total                                           $1,117,962
    -------------------------------------------------------------------------
    

    A significant portion of our taxable income is generated by a wholly
owned partnership. Consolidated earnings before income taxes include
$149 million (2006 - $259 million) of partnership earnings that will be
included in the following year's income for income tax purposes. Future income
taxes include $44 million (2006 - $83 million) as a result of this deferral of
partnership earnings.
    Based upon planned capital expenditure programs and current commodity
price assumptions, it appears we will not incur current income taxes until at
least 2010.

    
    SUMMARY OF CAPITAL EXPENDITURES

    -------------------------------------------------------------------------
    Years ended December 31,    2007             2006             2005
    -------------------------------------------------------------------------
                              ($000s)    %     ($000s)    %     ($000s)    %
    -------------------------------------------------------------------------

    Drilling and
     completions            $226,789    59   $294,197    60   $318,502    66
    Land and seismic          47,528    12     59,905    12     55,469    11
    Facilities               111,215    29    137,409    28    109,729    23
    -------------------------------------------------------------------------
    Sub-total               $385,532   100   $491,511   100   $483,700   100
    Corporate acquisitions   131,380                -                -
    Acquisitions and
     divestments, net       (229,391)          34,394           28,575
    -------------------------------------------------------------------------
    Sub-total               $287,521         $525,905         $512,275
    MPP                        4,796              (31)           1,261
    -------------------------------------------------------------------------
    Total capital
     expenditures           $292,317         $525,874         $513,536
    -------------------------------------------------------------------------
    

    Capital spending in 2007 was directed towards the continued development
of our core natural gas resource plays in southern and central Alberta.
Overall, 2007 capital spending, before acquisitions and divestitures,
decreased by 22% when compared to 2006. This reduction reflects the fewer
number of wells drilled in 2007 versus the prior year as well as an overall
reduction in certain service costs in 2007 as compared to 2006. We drilled 6%
fewer wells in 2007 as compared to 2006, and drilling and completions
expenditures declined by 23%, which implies an overall reduction in service
costs of approximately 17%. Lower spending on land and seismic and facilities
during 2007 also reflect the lower level of activity as compared to 2006.
    During 2007, we pursued our strategy of divesting of non-focus assets and
the redeployment of the proceeds into our focus area natural gas plays
including strategic acquisitions. We closed non-core property divestments,
including our conventional light oil property at Worsley, for total net
proceeds of $303.1 million. We also added to our core areas through a series
of property acquisitions that totaled approximately $73.7 million, resulting
in $229.4 million property divestments net of acquisitions. Through two
corporate acquisitions, Stylus Energy Inc. and WIN Energy Corporation, we
significantly expanded our presence in southern Alberta and the Foothills in
2007 at a total cost of $131.4 million.
    During the second quarter of 2007, we undertook a major two week
maintenance turn around at the Mazeppa gas plant. This scheduled maintenance,
which is necessary every three years, accounts for the increased capital
spending at Mazeppa when compared to 2006 and 2005.
    Capital expenditures, before acquisitions and divestitures, in 2006
increased only marginally from 2005; however, they reflect overall cost
inflation experienced in the industry during the year. We drilled a total of
274 net wells in 2006 at an average cost, to drill and complete, of $1,074,000
per well. In contrast, we drilled 334 net wells during 2005 at an average cost
of $954,000 per well. Although not an entirely comparable analysis, as the mix
of shallow, deep, and oil wells affected this comparison, this represented a
12.6% increase in drilling and completion costs, on a per well basis, in 2006
as compared to 2005.
    Spending on production facilities increased $27.7 million in 2006 over
2005 and comprised 28% of our total capital program, before acquisitions and
divestments as compared to 23% in 2005. Although we deferred a portion of our
initial 2006 drilling program in deference to lower commodity prices and the
inflationary cost environment, we continued with the majority of our planned
expenditures in 2006 relating to equipment and facilities.

    
    LIQUIDITY AND CAPITAL RE

SOURCES ------------------------------------------------------------------------- As at December 31, ($000s, except where noted) 2007 2006 2005 ------------------------------------------------------------------------- Working capital deficiency(1) $ 39,215 $ 23,163 $ 62,116 Bank debt 398,426 328,000 177,900 Senior term notes 433,762 524,385 357,640 ------------------------------------------------------------------------- Total indebtedness $ 871,403 $ 875,548 $ 597,656 ------------------------------------------------------------------------- Shareholders' equity $ 869,956 $ 734,124 $ 596,336 Debt to adjusted cash flow from operations(2) 4.2 3.4 2.2 Debt to book capitalization 49% 54% 50% Debt to market capitalization 41% 39% 22% ------------------------------------------------------------------------- 1. Excludes unrealized risk management items net of related future income taxes. 2. Based on trailing 12 month adjusted cash flow from operations. Senior Term Notes The Senior Notes are repayable in U.S. dollars for 2007 and are carried on the balance sheet at their Canadian dollar equivalent less related unamortized transaction costs. The 2005 and 2006 comparative amounts have not been adjusted to reflect new accounting treatment. The Canadian dollar equivalent is determined based upon the Canadian/U.S. dollar exchange rate at December 31. During the fourth quarter of 2007, we entered into foreign currency exchange contracts to purchase US$450 million for C$436 million as at December 1, 2010, being the second call date on the Senior Notes. The Senior Notes are due on December 1, 2013. The foreign exchange contracts effectively fix the Canadian dollar repayment amount of the Senior Notes at $436 million through to December 1. 2010 and crystallized an unrealized foreign exchange gain of approximately $91.7 million. The carrying value of the Senior Notes will continue to vary in relation to the Canadian/U.S. dollar exchange rate and any resulting unrealized foreign exchange gains or losses will be recognized. The variance in the carrying amount of the notes will largely be offset by the mark-to-market value of the foreign exchange contracts. Effectively, unrealized foreign exchange gains and losses resulting from translation of the notes will be offset by unrealized gains and losses on the foreign exchange contracts until December 2, 2010. At December 31, 2007 an accumulated gain of $14.1 million has been recorded on the foreign exchange contracts as outlined in Note 17(a)(iii) to the financial statements. Bank Debt Bank debt is comprised of a syndicated credit facility with a current authorized limit of $500 million. The facility is a borrowing based facility with the borrowing base being determined based upon year end reserves. The facility is subject to review annually prior to the renewal date of July 4, 2008. We do not anticipate any reduction to the borrowing base and authorized credit facility amount given the increase in 2007 reserves over 2006. Our corporate debt is structured to provide us with financial flexibility. Of our existing debt, 50% consists of Senior Notes that are not due until 2013, giving us the ability to draw on our senior secured credit facilities to assist in funding our planned 2008 capital program. We have identified a number of non-core properties for disposition during 2008. We anticipate the proceeds from the sale of these properties to be approximately $250 million. Initially, the proceeds so generated will be applied to reduce our outstanding bank debt. Additionally, the authorized limit of $500 million may be reduced to recognize the reduction in reserves related to these dispositions. Any such potential change is expected to be minimal due to 2007 reserve additions. We believe internally generated adjusted cash flow from operations and proceeds from planned property dispositions will be more than sufficient to fund our planned 2008 capital program. Excess funds will be used to reduce bank indebtedness. CONTRACTUAL OBLIGATIONS As part of normal business, we have entered into arrangements and incurred obligations that will impact our future operations and liquidity, some of which are reflected as liabilities in the consolidated financial statements. The following table summarizes our contractual obligations as at December 31, 2007. ------------------------------------------------------------------------- Payments Due by Period Less than 1-3 4-5 After ($000s) 1 year years years 5 years Total ------------------------------------------------------------------------- Bank debt - $400,000 - - $400,000 Senior term notes - - $436,388 - 436,388 Operating leases $ 3,811 3,830 - - 7,641 Office facilities 4,351 16,565 5,569 $ 33,414 59,899 MPP partnership distributions 9,172 3,057 - 12,229 Asset retirement obligations 2,818 3,910 7,203 232,631 246,562 ------------------------------------------------------------------------- Total $ 20,152 $427,362 $449,160 $266,045 $1,162,719 ------------------------------------------------------------------------- We have the ability and the intention to extend the term of our bank debt and therefore repayment of the facility, although included in the schedule of contractual obligations, is not expected to occur. OUTLOOK AND GUIDANCE FOR 2008 The following section summarizes our plans and guidance for 2008 as announced in a news release dated January 23, 2008. We believe our budget to be achievable, however, certain events more fully described under "Recent Events", will impact our 2008 operations. Summary of 2008 Guidance ------------------------------------------------------------------------- 2008 Budget Range ------------------------------------------------------------------------- Capital expenditures ($millions) $410 Gross wells 350 Average production - total boe/d 36,000 - 37,000 Adjusted cash flow from operations ($millions) $245 - $255 ------------------------------------------------------------------------- Our 2008 projected adjusted cash flow from operations is based upon the following pricing assumptions: ------------------------------------------------------------------------- Benchmark Realized ------------------------------------------------------------------------- Natural gas AECO Cdn $6.98/mcf Cdn $6.95/mcf Crude oil ($/bbl) WTI U.S. $81.00/bbl Cdn $72.75bbl ------------------------------------------------------------------------- The average Canadian/U.S. exchange rate is budgeted at $1.00 U.S. = $1.00 Cdn. Concurrent with strengthening commodity prices during the first part of 2008, we have systematically entered into a number of commodity hedge contracts as summarized in the Risk Management section of this MD&A and Note 17(a) (ii) to the financial statements. The effect of these contracts is an increase in projected 2008 cash flow of $10.8 million from the amount noted above. It is our intent to hedge approximately 50% of our gross production forward 12 to 18 months. Cash Flow Sensitivities for 2008 ------------------------------------------------------------------------- ($millions) Change in Cash Flow ------------------------------------------------------------------------- Change of Cdn $0.25/mcf in the benchmark AECO natural gas price $14.0 Change of U.S. $1.00/bbl in the benchmark WTI oil price $0.4 ------------------------------------------------------------------------- In the event of significant changes in commodity prices, operating and exploration costs, or an overall change in general economic or industry conditions, we can readily amend our capital expenditure program as appropriate. RECENT EVENTS In response to concerns raised by a major shareholder of Compton, the Board of Directors of the Company, as announced in a news release dated February 27, 2008 will conduct a formal review of the Company's business plans and strategic alternatives. This will include exploring potential asset divestments, equity alternatives, strategic alliances, joint venture opportunities, mergers, or a corporate transaction. In the aforementioned news release, the Company cautioned shareholders that there is no assurance that the review will result in any specific transaction and no timetable had been set for its completion. The Company has estimated that during 2008 direct costs and costs resulting from the process associated with shareholder activism will be approximately $22 million. Such costs will include additional legal fees, advisory fees and expenses, and employee retention costs. Such costs will be included in 2008 general and administrative expenses and will reduce cash flow from operations. Depending upon the outcome of the process the Company could incur additional cash outlays relating to change of control provisions applicable to the Company's Senior Notes, Mazeppa Processing Partnership arrangements, employee contracts, and additional advisory and legal fees. At this stage, we are unable to predict the outcome of the review process and the direction that Compton may ultimately take. As events unfold, we will provide complete and timely updates. ADDITIONAL DISCLOSURES CONTROLS AND PROCEDURES With respect to disclosure controls and procedures and internal control over financial reporting, we are required to comply with the U.S. Sarbanes-Oxley Act of 2002 and Canadian Multilateral Instrument 52-109, Certification of Disclosure in Issuers' Annual and Interim Filings. These regulations are substantially the same. However, the most significant difference is the U.S. requirement for the registered public accounting firm that audits our financial statements, included in our annual report, to issue an attestation report on our internal control over financial reporting. There is no corresponding Canadian attestation requirement. There are certain procedural and wording differences between the U.S. and Canadian certifications. We have chosen to file the form of certification pursuant to Section 302 of the Sarbanes-Oxley Act with the U.S. Securities and Exchange Commission ("SEC") and Form 52-109 F1, Certification of Annual Filings, with the Canadian Securities Administrators ("CSA"). We have complied with both the U.S. and Canadian requirements in respect of disclosure controls and procedures and internal control over financial reporting and our report is below. MANAGEMENT'S EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES The term "disclosure controls and procedures" is defined, under Rule 13a-15(d) of the U.S. Exchange Act of 1934, as controls and other procedures that are designed to ensure both non-financial and financial information required to be disclosed by us in our periodic reports is recorded, processed, summarized, and reported within the time periods required, and this information is accumulated and communicated to management as appropriate, to allow timely decisions regarding required disclosures. The definition of disclosure controls and procedures with respect to Canadian Multilateral Instrument 52-109 is substantially the same. As indicated in our certifications filed with the SEC and CSA, we completed an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2007, under the supervision and with the participation of our Management, including our President & CEO and VP Finance & CFO. Based upon our evaluation, we concluded our disclosure controls and procedures were effective. MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Management, including our President & CEO and VP Finance & CFO, is responsible for establishing and maintaining adequate internal control over financial reporting. The term "internal control over financial reporting" is defined, under both Rule 13a-15(f) of the U.S. Exchange Act of 1934 and Canadian Multilateral Instrument 52-109, as processes designed by, or under the supervision of, our principal executive and principal financial officers, and effected by our board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with GAAP. These controls would include policies and procedures that: 1. Pertain to the maintenance of our records, that accurately and fairly reflect the transactions affecting, and dispositions of, our assets; 2. Provide reasonable assurance that transactions are recorded to be able to prepare our financial statements in accordance with GAAP, and that our receipts and expenditures are made only in accordance with authorizations of our management and directors; and 3. Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets, which could have a material effect on our financial statements. We completed an evaluation of the effectiveness of the design and operation of our internal control over financial reporting under the supervision, and with the participation, of our Management, including our President & CEO and VP Finance & CFO. We conducted our evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control - Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission, also known as COSO. Based upon our evaluation, we have concluded, as of December 31, 2007, internal control over financial reporting was effective. The effectiveness of internal control over financial reporting as of December 31, 2007 was audited by Grant Thornton LLP, Chartered Accountants, the independent registered public accounting firm, which also audits our financial statements. They have issued their Independent Auditors' Report which is included in this Annual Report. CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING During the quarter ended March 31, 2007, we made two material changes to internal control over financial reporting. On March 1, 2007 we converted our production accounting and royalty management information systems. These changes were implemented to improve both operational efficiencies and internal controls. These conversions were not due to any identified internal control weaknesses. During the quarter ended December 31, 2007, we made one material change to internal control over financial reporting. On October 15, 2007, we implemented our substantially re-engineered capital expenditure approval and tracking business process. This included improved policies and procedures as well as new workflow software to support those policies and procedures. This change was implemented to improve operational effectiveness and efficiency as well as remediate internal control deficiencies. These changes were subject to our change management procedures which are effective. There were no other changes during the year ended December 31, 2007 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. CRITICAL ACCOUNTING ESTIMATES Accounting estimates require us to make assumptions regarding matters that are uncertain at the time the estimate is made and may have a material impact on our financial condition. A comprehensive discussion of our significant accounting policies may be found in Note 1 to the consolidated financial statements. OIL AND NATURAL GAS RESERVES The independent petroleum engineering and geological consulting firm of Netherland, Sewell & Associates, Inc. evaluated and reported on 96% of our oil and natural gas reserves. The remainder was internally evaluated. The estimation of reserves is a subjective process. Forecasts are based on engineering data, projected future rates of production, and the timing of future expenditures, all of which are subject to numerous uncertainties and various interpretations. We expect that our estimates of reserves will change with updated information from the results of future drilling, testing, or production levels. Such revisions could be upwards or downwards. Reserve estimates have a material impact on depletion and depreciation, asset retirement obligations, and impairment costs, all of which could possibly have a material impact on our consolidated net earnings. DEPLETION Capitalized costs and estimated future expenditures to develop proved reserves, including abandonment costs, are depleted based on the proportion of proved oil and natural gas reserves produced during the year compared to estimated total proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If it is determined that properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. In 2007, we incurred $151 million of depletion and depreciation. If our proved reserves were to increase by 5%, our depletion and depreciation expense would decrease by $1.8 million and consolidated net earnings after tax would increase by $1.4 million. If our proved reserves were to decrease by 5%, our depletion and depreciation expense would increase by $2.0 million and consolidated net earnings after tax would decrease by $1.5 million. IMPAIRMENT In applying the full cost method of accounting, we periodically calculate a ceiling or limitation on the amount that property and equipment may be carried for on the consolidated balance sheets. An impairment exists if the undiscounted future net cash flows from proved reserves at future commodity prices plus the cost of undeveloped properties is less than the carrying value of the capitalized costs. As at December 31, 2007, the ceiling amount calculated was $2.4 billion (2006 - $2.7 billion) in excess of the carrying value of the costs capitalized. If an impairment is found to exist, the impaired properties are written down to their fair value. The fair value of the assets is calculated based on future net cash flows from proved plus probable reserves, discounted at a risk free interest rate using future commodity prices, plus the cost of undeveloped properties. An impairment may result in a material loss for a particular period; however, future depletion and depreciation expense would be reduced as a result. Assumptions about reserves and future prices are required to calculate future net cash flows. The assumptions made to estimate reserves have been discussed above. There is significant uncertainty regarding forecasting future commodity prices due to economic and political uncertainties. Future prices are derived from a consensus of price forecasts among recognized reserve evaluators. Estimates of future cash flows assume a long term price forecast and current operating costs per boe plus an inflation factor. It is difficult to determine and assess the impact of a decrease in proved reserves on impairment. The relationship between reserve estimates and the estimated undiscounted cash flows, and the nature of the property-by-property impairment test is complex. As a result, it is not possible to provide a reasonable sensitivity analysis of the impact that a reserve estimate decrease would have on impairment. No material downward revisions to our reserves are anticipated. ASSET RETIREMENT OBLIGATION We recognize the fair value of estimated asset retirement obligations on the consolidated balance sheet when a reasonable estimate of fair value can be made. Asset retirement obligations include those legal obligations where we will be required to retire tangible long term assets such as well sites, pipelines, and facilities. The asset retirement cost, equal to the initially estimated fair value of the asset retirement obligation, is capitalized as part of the cost of the related long term assets. Increases in the asset retirement obligations resulting from the passage of time are recorded as accretion of asset retirement obligations in the consolidated statement of earnings. Amounts recorded for asset retirement obligations are subject to uncertainty associated with the method, timing, and extent of future retirement activities. Actual payments to settle the obligations may differ from estimated amounts. RECENT ACCOUNTING PRONOUNCEMENTS On January 1, 2008, the Company will adopt the following CICA Handbook Sections: a. Section 3031, "Inventories" which replaces the existing standard. The requirements include the consistent grouping of like assets and the application of the first-in-first-out or weighted average cost formula methodologies. b. Section 1400, "General Standards of Financial Statement Presentation" which requires assessing and disclosing the Company's ability to continue as a going concern. c. Section 3862, "Financial Instruments - Disclosures" and Section 3863, "Financial Instruments - Presentation". These new standards will require increased disclosure of financial instruments with particular emphasis on the risks associated with recognized and unrecognized financial instruments and how those risks are managed. d. Section 1535, "Capital Disclosures", requiring disclosure of information about an entity's capital and the objectives, policies, and processes for managing capital. The adoption of these standards is not expected to have a material impact on the Company's consolidated financial statements. On January 1, 2009 the Company will be required to adopt CICA Handbook Section 3064, "Intangible Assets". The new section established standards for the recognition, measurement, and disclosure of goodwill and intangible assets and replaces the existing Handbook Section 3062, "Goodwill and Other Intangible Assets" and Section 3450, "Research and Development Costs". Intangible assets associated with the exploration and development of oil and gas assets are specifically excluded under the new standard. The Company is evaluating the implications of this adoption, but expects no material impact on the consolidated financial statements. On January 10, 2006, the CICA Accounting Standards Board ("AcSB") ratified a new strategic plan that would see the convergence of Canadian Generally Accepted Accounting Principles ("GAAP") with International Financial Reporting Standards ("IFRS") within 5 years. In March 2007, the AcSB released an "Implementation Plan for Incorporating IFRSs into Canadian GAAP", which assumed a convergence date of January 1, 2011. The AcSB confirmed this date in February 2008. The Company continues to monitor and assess the consequences of convergence on the consolidated financial statements as they could have a material impact. RISK MANAGEMENT Our operations are subject to risks inherent to the oil and natural gas industry. We are exposed to financial risks including fluctuations in commodity prices, currency exchange rates, interest rates, credit ratings, and changing expenditure costs due to shifts in market conditions. We take specific measures to manage these risks, particularly those impacting adjusted cash flow from operations. A more detailed discussion of risk factors is presented in our most recent Annual Information Form, filed with securities regulatory authorities on or before March 31, 2008 on www.sedar.com. COMMODITY PRICE RISK MANAGEMENT We enter into commodity price contracts to actively manage risk associated with price volatility to protect adjusted cash flow from operations required to fund our capital program. We use fixed price and costless collar contracts as well as balancing physical and financial contracts in terms of volumes, timing of performance, and delivery obligations to manage risk. Net open positions may exist or may be established to take advantage of market conditions. Net earnings for the year ended December 31, 2007, include realized and unrealized loss of $1.6 million (2006 - $65.0 million gain) on these transactions. The following table outlines commodity hedge transactions in place at December 31, 2007 together with transactions entered into subsequent to the year end: ------------------------------------------------------------------------- Commodity Term Amount Average Price Index ------------------------------------------------------------------------- Natural gas Collar Nov. 2007 - March 2008 9,524 mcf/d $8.27 - $10.50 AECO Collar April 2008 - Oct. 2008 52,381 mcf/d $7.33 - $8.48 AECO Fixed April 2008 - Oct. 2008 19,048 mcf/d $7.86 AECO Collar Nov. 2008 - March 2009 28,571 mcf/d $8.40 - $10.00 AECO Fixed Nov. 2008 - March 2009 9,524 mcf/d $8.51 AECO Crude oil Fixed March 2008 - Dec. 2008 1,000 bbls/d U.S.$93.00/bbl WTI ------------------------------------------------------------------------- FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT Our 7.625% Senior Notes due December 1, 2013 and semi-annual interest obligations thereon are payable in U.S. dollars. Accordingly, we are exposed to fluctuations in the exchange rate between the Canadian and the U.S. dollar. To manage this risk we entered into a series of foreign exchange contracts relating to the principle amount of the Notes, effectively fixing the liability at $436 million Canadian through to December 1, 2010, being the second call date on the Notes. Additionally, we entered into a series of foreign exchange contracts relating to the interest obligations associated with the Notes through to December 1, 2010. We are also exposed to fluctuations in the exchange rate between the Canadian dollar and the U.S. dollar. Commodity prices are based on U.S. dollar benchmarks that result in our realized price being influenced by the Canadian/U.S. currency exchange rate. Should the Canadian dollar strengthen compared to the U.S. dollar we will experience a negative effect on net earnings. Conversely, should the Canadian dollar weaken compared to the U.S. dollar we will experience a positive effect on net earnings. INTEREST RATE RISK MANAGEMENT We are exposed to fluctuations in interest rates on corporate borrowings. To manage this risk we attempt to achieve a balance between fixed and floating interest rate debt instruments. Our Senior Notes bear a fixed interest charge of 7.625% and our borrowings under are syndicate credit facility incur floating rate interest charges. At year end approximately 52% of our total corporate debt incurred fixed rate interest charges and the balance incurred floating rate charges. Concurrent with the closing of our 9.90% Senior Notes offering in May of 2002, we entered into a cross currency interest rate swap. The swap, which converted fixed rate U.S. dollar interest obligations into floating rate Canadian dollar interest obligations, was entered into to fix the exchange rate on interest payments and take advantage of lower floating interest rates. On repurchase of the majority of 9.90% Senior Notes in November 2005, we elected not to collapse the swap and incur the then associated costs of $12 million. The swap remains outstanding and at December 31, 2007, we valued the liability relating to future unrealized losses on the swap arrangement to be $10.4 million (2006 - $11 million) determined on a mark-to-market basis. The loss associated with the swap has resulted primarily from the strengthening of the Canadian dollar. Should the Canadian dollar continue to increase against the U.S. dollar, the loss could increase further; alternatively if the Canadian dollar were to weaken the loss would be reduced. Cash settlements of the swap positions are made semi-annually and losses realized will be recorded over the remaining term of the swap agreement which expires in May 2009. SELECTED QUARTERLY INFORMATION The following tables set out selected quarterly financial information for the last two fiscal years. ------------------------------------------------------------------------- Three Months Ended Year Ended ------------------------------------------------------------------------- ($000s, except March 31, June 30, Sept. 30, Dec. 31, Dec. 31, where noted) 2007 2007 2007 2007 2007 ------------------------------------------------------------------------- Average production (boe/d) 33,316 28,918 30,440 32,646 31,326 Average pricing ($/boe) $ 46.98 $ 47.94 $ 38.56 $ 41.94 $ 43.82 Total revenue $140,877 $126,171 $107,980 $125,959 $500,987 Adjusted cash flow from operations $ 68,783 $ 48,582 $ 33,133 $ 45,696 $196,194 Per share: basic $ 0.53 $ 0.38 $ 0.26 $ 0.35 $ 1.52 diluted $ 0.52 $ 0.36 $ 0.25 $ 0.35 $ 1.48 Adjusted net earnings from operations $ 17,933 $ 7,364 $ (1,994) $ (2,017) $ 21,286 Net earnings (loss) $ 13,719 $ 45,307 $ 19,782 $ 50,457 $129,266 Per share: basic $ 0.11 $ 0.35 $ 0.15 $ 0.39 $ 1.00 diluted $ 0.10 $ 0.34 $ 0.15 $ 0.38 $ 0.98 ------------------------------------------------------------------------- September and October of 2007 were our busiest drilling months on record since Company inception. These high activity levels generated production growth of 7% from the third quarter to the fourth quarter of 2007. Strengthening commodity prices together with increased production volumes resulted in a 17% increase in fourth quarter revenue and a 38% increase in adjusted cash flow from operations over the third quarter of 2007. Revenue and net earnings were lower during the third quarter of 2007 due primarily to lower realized prices. ------------------------------------------------------------------------- Three Months Ended Year Ended ------------------------------------------------------------------------- ($000s, except March 31, June 30, Sept. 30, Dec. 31, Dec. 31, where noted) 2006 2006 2006 2006 2006 ------------------------------------------------------------------------- Average production (boe/d) 34,029 32,645 32,843 33,245 33,187 Average pricing ($/boe) $ 48.58 $ 45.37 $ 42.03 $ 42.60 $ 44.65 Total revenue $148,779 $134,778 $126,991 $130,289 $540,837 Adjusted cash flow from operations $ 73,596 $ 67,326 $ 60,120 $ 55,263 $256,305 Per share: basic $ 0.58 $ 0.53 $ 0.47 $ 0.43 $ 2.01 diluted $ 0.55 $ 0.50 $ 0.45 $ 0.42 $ 1.92 Adjusted net earnings from operations $ 22,249 $ 17,947 $ 13,150 $ 11,822 $ 65,168 Net earnings (loss) $ 38,002 $ 68,744 $ 30,717 $(10,037) $127,426 Per share: basic $ 0.30 $ 0.54 $ 0.24 $ (0.08) $ 1.00 diluted $ 0.28 $ 0.51 $ 0.23 $ (0.08) $ 0.95 ------------------------------------------------------------------------- During the second half of 2006, lower realized commodity prices from those experienced during the first half of the year resulted in reduced revenue, cash flow, and adjusted net earnings from operations. Production increases in the third and fourth quarter were more than offset by the reduction in commodity prices. The negative effect of lower commodity prices on cash flow was reduced by realized gains of $36 million from risk management activities. Net earnings for the nine months ended September 30, 2006 benefited from an unrealized foreign exchange gain of $19.1 million, after tax, and an income tax recovery of $35 million. Net earnings in the fourth quarter were negative due to the reversal of unrealized foreign exchange gains recorded in prior quarters, as the result of the weakening of the Canadian dollar compared to the U.S. dollar. Selected Annual Information Years ended December 31, ($000s) 2007 2006 2005 ------------------------------------------------------------------------- Total revenue $ 500,987 $ 540,837 $ 564,241 Net earnings $ 129,266 $ 127,426 $ 81,326 Per share: basic $ 1.00 $ 1.00 $ 0.65 diluted $ 0.98 $ 0.95 $ 0.62 Total assets $2,254,587 $2,145,472 $1,758,098 Total long term financial liabilities $ 832,188 $ 852,385 $ 535,540 ------------------------------------------------------------------------- Total revenue in 2007 was lower than 2006 due to lower oil prices and slightly lower production volumes arising from the disposition of our conventional oil asset Worsley. Total revenue in 2006 was marginally lower than 2005 with increases in production being more than offset by reduced commodity prices. Net earnings in 2006 increased $46.1 million over 2005 primarily as a result of risk management gains that offset the reduction in revenue and increases in expenses. Long term financial obligation in 2006 increased over 2005 as a result of increased borrowings to fund the capital programs. TRADING AND SHARE STATISTICS As at March 10, 2008 there were 129,194,721 common shares outstanding and 12,314,907 stock options. ------------------------------------------------------------------------- 2007 2006 2005(1) TSX NYSE TSX NYSE TSX NYSE ($Cdn) ($US) ($Cdn) ($US) ($Cdn) ($US) ------------------------------------------------------------------------- Average daily trading volume (000s) 485,027 213,044 545,489 115,450 736,416 138,288 Share price ($/share) High $ 13.19 US$12.16 $ 19.24 US$16.74 $ 18.66 US$16.11 Low $ 7.40 US$ 7.70 $ 10.20 US$ 9.04 $ 9.80 US$14.15 Close $ 9.14 US$ 9.20 $ 10.65 US$ 9.12 $ 17.10 US$14.65 Market capitalization at December 31 ($000s) $1,179,958 $1,368,557 $2,176,197 Shares outstanding (000s) 129,098 128,503 127,263 ------------------------------------------------------------------------- (1) Trading on the New York Stock Exchange commenced December 5, 2005. Compton Petroleum Corporation Consolidated Financial Statements December 31, 2007 (Unaudited) ------------------------------------------------------------------------- Compton Petroleum Corporation Consolidated Balance Sheets (thousands of dollars) ------------------------------------------------------------------------- December 31, December 31, 2007 2006 ------------ ------------ (unaudited) Assets Current Cash $ 8,665 $ 11,876 Accounts receivable 80,331 83,535 Unrealized risk management gain (Note 17a (i)) 1,835 22,625 Other current assets 19,772 22,869 Future income taxes(Note 16b) 2,606 1,479 ------------ ------------ 113,209 142,384 Property and equipment (Note 5) 2,116,834 1,977,062 Goodwill (Note 3) 9,933 7,914 Other assets (Note 9) 291 14,144 Unrealized risk management gain (Note 17a (i)) 14,320 - Deferred risk management loss (Note 2b) - 3,968 ------------ ------------ $2,254,587 $2,145,472 ------------ ------------ ------------ ------------ Liabilities Current Accounts payable $ 147,983 $ 141,443 Unrealized risk management loss (Note 17a (i)) 8,832 4,604 Future income taxes (Note 16b) 542 7,269 ------------ ------------ 157,357 153,316 Bank debt (Note 6) 398,426 328,000 Senior term notes (Note 7) 433,762 524,385 Asset retirement obligations (Note 11) 36,696 29,791 Unrealized risk management loss (Note 17 a(i)) 1,585 6,816 Future income taxes (Note 16b) 293,494 302,690 Non-controlling interest (Note 4) 63,311 66,350 ------------ ------------ 1,384,631 1,411,348 ------------ ------------ Shareholders' equity Capital stock (Note 12b) 235,871 231,992 Contributed surplus (Note 13a) 24,233 16,974 Retained earnings 609,852 485,158 ------------ ------------ 869,956 734,124 ------------ ------------ $2,254,587 $2,145,472 ------------ ------------ ------------ ------------ Commitments and contingent liabilities (Note 19) Subsequent events (Note 20) See accompanying notes to the consolidated financial statements. ------------------------------------------------------------------------- Compton Petroleum Corporation Consolidated Statements of Earnings and Other Comprehensive Income (unaudited) (thousands of dollars, except per share amounts) ------------------------------------------------------------------------- Three months ended Years ended December 31, December 31, -------------------- -------------------- 2007 2006 2007 2006 --------- --------- --------- --------- Revenue Oil and natural gas revenues $ 125,959 $ 130,289 $ 500,987 $ 540,837 Royalties (26,617) (29,182) (102,678) (123,677) --------- --------- --------- --------- 99,342 101,107 398,309 417,160 --------- --------- --------- --------- Expenses Operating 27,549 29,703 101,478 102,643 Transportation 1,654 3,214 12,615 12,564 General and administrative 6,594 7,422 31,328 26,231 Interest and finance charges (Note 8) 14,494 15,926 63,493 54,075 Depletion and depreciation 44,379 37,036 151,411 143,057 Foreign exchange (gain) loss (Note 10) (3,460) 22,708 (78,717) (891) Accretion of asset retirement obligations (Note 11) 769 632 2,718 2,257 Stock-based compensation (Notes 13a and c) 1,636 3,616 11,034 10,488 Risk management gain (Note 17b) (13,859) (6,028) (6,014) (63,721) --------- --------- --------- --------- 79,756 114,229 289,346 286,703 --------- --------- --------- --------- Earnings before taxes and non-controlling interest 19,586 (13,122) 108,963 130,457 --------- --------- --------- --------- Income taxes (Note 16a) Current 9 21 17 44 Future (32,289) (5,530) (26,452) (3,636) --------- --------- --------- --------- (32,280) (5,509) (26,435) (3,592) --------- --------- --------- --------- Earnings before non-controlling interest 51,866 (7,613) 135,398 134,049 Non-controlling interest (Note 4) 1,409 2,424 6,132 6,623 --------- --------- --------- --------- Net earnings 50,457 $ (10,037) 129,266 $ 127,426 --------- --------- --------- --------- --------- --------- --------- --------- Other comprehensive income - - --------- --------- Comprehensive income $ 50,457 $ 129,266 --------- --------- --------- --------- Net earnings per share (Note 14) Basic $ 0.39 $ (0.08) $ 1.00 $ 1.00 --------- --------- --------- --------- --------- --------- --------- --------- Diluted $ 0.38 $ (0.08) $ 0.98 $ 0.95 --------- --------- --------- --------- --------- --------- --------- --------- ------------------------------------------------------------------------- Compton Petroleum Corporation Consolidated Statements of Retained Earnings (unaudited) (thousands of dollars) ------------------------------------------------------------------------- Three months ended Years ended December 31, December 31, -------------------- -------------------- 2007 2006 2007 2006 --------- --------- --------- --------- Retained earnings, beginning of period As previously reported $ 560,464 $ 495,727 $ 485,158 $ 360,719 Accounting policy adjustments (Note 2) - - (1,320) - --------- --------- --------- --------- As adjusted 560,464 495,727 483,838 360,719 Net earnings 50,457 (10,037) 129,266 127,426 Premium on redemption of shares (Note 12b) (1,069) (532) (3,252) (2,987) --------- --------- --------- --------- Retained earnings, end of period $ 609,852 $ 485,158 $ 609,852 $ 485,158 --------- --------- --------- --------- --------- --------- --------- --------- See accompanying notes to the consolidated financial statements. ------------------------------------------------------------------------- Compton Petroleum Corporation Consolidated Statements of Cash Flow (unaudited) (thousands of dollars) ------------------------------------------------------------------------- Three months ended Years ended December 31, December 31, 2007 2006 2007 2006 --------- --------- --------- --------- Operating activities Net earnings $ 50,457 $ (10,037) $ 129,266 $ 127,426 Amortization and other 393 401 3,417 1,996 Depletion and depreciation 44,379 37,036 151,411 143,057 Accretion of asset retirement obligations 769 632 2,718 2,257 Unrealized foreign exchange (gain) loss (3,690) 22,500 (79,740) (665) Future income taxes (32,289) (5,530) (26,452) (3,636) Unrealized risk management (gain) loss (16,789) 6,073 5,467 (27,522) Stock-based compensation 1,636 2,249 8,416 9,121 Asset retirement expenditures (578) (485) (4,441) (2,352) Non-controlling interest 1,408 2,424 6,132 6,623 --------- --------- --------- --------- 45,696 55,263 196,194 256,305 Change in non-cash working capital (Note 18) (9,201) 14,639 (23,366) 19,823 --------- --------- --------- --------- 36,495 69,902 172,828 276,128 --------- --------- --------- --------- Financing activities Issuance (repayment) of bank debt 174,320 50,000 70,426 152,100 Proceeds from share issuances, net 649 598 3,446 4,672 Distributions to partner (2,278) (2,293) (9,171) (9,171) Redemption of common shares (1,373) (635) (3,976) (3,433) Issue costs on senior notes - - - (3,408) Issuance of senior notes - - - 174,930 Redemption of senior notes - - - (7,520) --------- --------- --------- --------- 171,318 47,670 60,725 308,170 --------- --------- --------- --------- Investing activities Property and equipment additions (121,221) (88,453) (391,070) (490,429) Corporate acquisitions (Note 3) (29,740) - (104,705) - Property acquisitions (58,766) (3,603) (66,808) (34,444) Property dispositions 1,931 - 307,527 1,350 Change in non-cash working capital (Note 18) (1,356) (35,636) 18,292 (57,853) --------- --------- --------- --------- (209,152) (127,692) (236,764) (581,376) --------- --------- --------- --------- Change in cash (1,339) (10,120) (3,211) 2,922 Cash, beginning of period 10,004 21,996 11,876 8,954 --------- --------- --------- --------- Cash, end of period $ 8,665 $ 11,876 $ 8,665 $ 11,876 --------- --------- --------- --------- --------- --------- --------- --------- See accompanying notes to the consolidated financial statements. ------------------------------------------------------------------------- Compton Petroleum Corporation Notes to the Consolidated Financial Statements December 31, 2007 (Tabular amounts in thousands of dollars, unless otherwise stated) ------------------------------------------------------------------------- 1. Significant accounting policies Compton Petroleum Corporation (the "Company" or "Compton") is in the business of the exploration for and production of petroleum and natural gas reserves in the Western Canada Sedimentary Basin. a) Basis of presentation The consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in Canada within the framework of the accounting policies summarized below. The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. The consolidated financial statements also include the accounts of Mazeppa Processing Partnership in accordance with Accounting Guideline 15 ("AcG-15") "Consolidation of Variable Interest Entities", as outlined in Note 4. All amounts are presented in Canadian dollars unless otherwise stated. b) Measurement uncertainty The timely preparation of financial statements requires that Management make estimates and assumptions and use judgment regarding the measurement of assets, liabilities, revenues, and expenses. Such estimates relate primarily to transactions and events that have not settled as of the date of the financial statements. Accordingly, actual results may materially differ from estimated amounts as future confirming events occur. Amounts recorded for depletion and depreciation, and amounts used in impairment test calculations are based upon estimates of petroleum and natural gas reserves and future costs to develop those reserves. By their nature, these estimates of reserves, costs, and related future cash flows are subject to uncertainty, and the impact on the consolidated financial statements of future periods could be material. The calculation of asset retirement obligations include estimates of the ultimate settlement amounts, inflation factors, credit adjusted discount rates, and timing of settlement. The impact of future revisions to these assumptions on the consolidated financial statements of future periods could be material. The amount of stock based compensation expense is subject to uncertainty due to the Company's best estimate of whether or not performance will be achieved and obligations incurred. The values of pension assets and obligations and the amount of pension costs charged to net earnings depend on certain actuarial and economic assumptions which by their nature are subject to measurement uncertainty. c) Property and equipment i) Capitalized costs The Company follows the full cost method of accounting for its petroleum and natural gas operations within one Canadian cost centre. Under this method all costs related to the exploration for and development of petroleum and natural gas reserves are capitalized. Costs include lease acquisition costs, geological and geophysical expenses, costs of drilling both producing and non-producing wells, production facilities, future asset retirement costs, and certain general and administrative expenses directly related to exploration and development activities. Proceeds from the sale of properties are applied against capitalized costs, without any gain or loss being realized, unless such sale would significantly alter the rate of depletion and depreciation. Expenditures related to renewals or betterments that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs, other than major turnaround costs, are expensed as incurred. Major turnaround costs are included in property and equipment when incurred and charged to depletion and depreciation in the consolidated statements of earnings and other comprehensive income over the estimated period of time to the next scheduled turnaround. ii) Depletion and depreciation Depletion and depreciation of property and equipment is provided using the unit-of-production method based upon estimated proved petroleum and natural gas reserves. The costs of significant undeveloped properties are excluded from costs subject to depletion until it is determined whether or not proved reserves are attributable to the properties or impairment has occurred. Estimated future costs to be incurred in developing proved reserves are included in costs subject to depletion and estimated salvage values are excluded from costs subject to depletion. For depletion and depreciation purposes, relative volumes of natural gas production and reserves are converted at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil. Depreciation of certain midstream facilities is provided for on a straight line basis over 30 years and depreciation of office equipment is provided for on a declining balance basis using rates which range from 20% to 30% per year. iii) Impairment test At each reporting period the Company performs an impairment test to determine the recoverability of capitalized costs associated with reserves. An impairment loss is recognized when the carrying amount of a cost centre is not recoverable. The carrying amount of the cost centre is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows from proved reserves plus the costs of unproved properties. If the sum of the cash flows is less than the carrying amount, the impairment loss is limited to the amount by which the carrying amount exceeds the sum of the fair value of discounted proved and probable reserves and the costs of unproved properties that have been subject to a separate impairment test and contain no probable reserves. vi) Asset retirement obligations The Company recognizes the present value of estimated asset retirement obligations on the consolidated balance sheet when a reasonable estimate can be made. Asset retirement obligations include those legal obligations where the Company will be required to retire tangible long-lived assets such as well sites, pipelines, and facilities. The asset retirement cost, equal to the initial estimated present value of the asset retirement obligation, is capitalized as part of the cost of the related long-lived asset. Changes in the estimated obligation resulting from revisions to estimated timing or amount of undiscounted cash flows are recognized as a change in the asset retirement obligation and the related asset retirement cost. Asset retirement costs are amortized using the unit-of- production method and are included in depletion and depreciation in the consolidated statements of earnings and other comprehensive income. Increases in the asset retirement obligations resulting from the passage of time are recorded as accretion of asset retirement obligations in the consolidated statements of earnings and other comprehensive income. Actual expenditures incurred are charged against the accumulated obligation. v) Inventories Physical inventory held for exploration, development, and operating activities is included in property and equipment and is valued at estimated realizable value. d) Goodwill Goodwill is recorded on a corporate acquisition when the purchase price is in excess of the fair values assigned to assets acquired and liabilities assumed. Goodwill is not amortized and an impairment test is performed at least annually to evaluate the carrying value. To assess impairment, the fair value of the consolidated entity, excluding the Mazeppa Processing Partnership, is determined and compared to the carrying value. If the fair value is less than the carrying value then a second test is performed to determine the amount of the impairment. Any loss recognized is equal to the difference between the implied fair value and the carrying value of the goodwill. e) Financial instruments and derivatives On January 1, 2007 the Company adopted the Canadian Institute of Chartered Accountants ("CICA") four new accounting standards: Handbook Section 1530, "Comprehensive Income", Handbook Section 3855, "Financial Instruments - Recognition and Measurement", Handbook Section 3861, "Financial Instruments - Disclosure and Presentation" and Handbook Section 3865, "Hedges". The adoption of these standards resulted in accounting changes, the impact of which are disclosed in Note 2 to these consolidated financial statements. Financial instruments are any contract that gives rise to a financial asset of one party and a financial liability or equity instrument of another party. Financial instruments were identified by the Company through a review of typical financial transactions and risk management activities. The Company also reviewed non-financial contracts, entered into subsequent to January 1, 2003, for potential embedded derivatives. Once identified, the financial instruments were classified and measured as disclosed below. Financial instruments are measured at fair value on initial recognition of the instrument except in specific circumstances. Measurement in subsequent periods depends on whether the financial instrument has been classified as "held for trading", "available for sale", "held to maturity", "loans and receivables" or "other financial liabilities" as defined by the standards. Financial assets and financial liabilities "held for trading" are measured at fair value with changes in those fair values recognized in net earnings. Financial assets "available for sale" are measured at fair value, with changes in those fair values recognized in other comprehensive income. Financial instruments "held to maturity", "loans and receivables" and "other financial liabilities" are measured at amortized cost using the effective interest method. Cash, and deposits included in other current assets, are classified as "held for trading" and are measured at carrying value which approximates fair value due to the short term nature of these instruments. Investments included in other current assets are designated as "held for trading", accounts receivable are classified as "loans and receivables" and accounts payable, bank debt and senior term notes are classified as "other financial liabilities". Transaction costs, premiums and discounts associated with the issuance of senior term notes are netted against the notes and amortized to earnings using the effective interest method. Derivative financial instruments are classified as "held for trading" and are recorded at fair value based on quoted market prices or third party market indications and forecasts. Fluctuations are recorded in earnings as risk management gains and losses during each reporting period. The Company uses derivative financial instruments for non-trading purposes to manage fluctuations in commodity prices, foreign currency exchange rates, and interest rates as outlined in Note 17. The Company does not designate any of its current risk management activities as accounting hedges. f) Joint operations Certain petroleum and natural gas activities are conducted jointly with others. These consolidated financial statements reflect only the Company's proportionate interest in such activities. g) Earnings per share amounts The Company uses the treasury stock method to determine the dilutive effect of stock options. This method assumes that proceeds received from the exercise of in-the-money stock options are used to repurchase common shares at the average market price for the period. Basic net earnings per common share are determined by dividing net earnings by the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed by giving effect to the potential dilution that would occur if stock options were exercised. h) Income taxes Income taxes are recorded using the liability method of accounting. Future income taxes are calculated based on the difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates. Changes in income tax rates are reflected in the period in which the rates are substantively enacted. i) Revenue recognition Revenue associated with the production and sale of crude oil, natural gas, and natural gas liquids owned by the Company is recognized when title passes to the customer and delivery has taken place. Revenue as reported, represents the Company's share and is presented before royalty payments to governments and other mineral interest owners. Other revenue is recognized in the period that the service is provided to the customer. j) Stock-based compensation plan The Company records compensation expense in the consolidated statements of earnings and other comprehensive income for stock options granted to directors, officers, and employees using the fair- value method. Compensation costs are recognized over the vesting period and the fair values are determined using the Black-Scholes option pricing model. Contributions to the Company's stock savings plan are recorded as compensation expense as incurred. k) Deferred financing charges On January 1, 2007 financing costs related to the issuance of senior term notes were reclassified from other assets to senior term notes, as disclosed in Note 2. The costs capitalized within long term debt are amortized using the effective interest method. l) Foreign currency translation Monetary assets and liabilities of the Company that are denominated in foreign currencies are translated into Canadian dollars at the period-end exchange rate, with any resulting gain or loss recorded in the consolidated statements of earnings and other comprehensive income. m) Dividend policy The Company has neither declared nor paid any dividends on its common shares. The Company intends to retain its earnings to finance growth and expand its operations and does not anticipate paying any dividends on its common shares in the foreseeable future. n) Defined benefit pension plan The Company accrues for obligations under a defined benefit pension plan and the related costs, net of plan assets for employees of Mazeppa Processing Partnership. The cost of the pension is actuarially determined using the projected benefit method based on length of service and reflects Management's best estimate of expected plan investment performance, salary escalation, and retirement age of employees. o) Recent accounting pronouncements On January 1, 2008, the Company will be required to adopt the following CICA Handbook Sections: a. Section 3031, "Inventories" which replaces the existing standard. The requirements include the consistent grouping of like assets and the application of the first-in-first-out or weighted average cost formula methodologies. b. Section 1400, "General Standards of Financial Statement Presentation" which requires assessing and disclosing the Company's ability to continue as a going concern. c. Section 3862, "Financial Instruments - Disclosures" and Section 3863, "Financial Instruments - Presentation". These new standards will require increased disclosure of financial instruments with particular emphasis on the risks associated with recognized and unrecognized financial instruments and how those risks are managed. d. Section 1535, "Capital Disclosures", requiring disclosure of information about an entity's capital and the objectives, policies, and processes for managing capital. The adoption of these standards is not expected to have a material impact on the Company's consolidated financial statements. On January 1, 2009 the Company will be required to adopt the CICA Handbook Section 3064, "Intangible Assets". The new section establishes standards for the recognition, measurement, and disclosure of goodwill and intangible assets and replaces the existing Handbook Section 3062, "Goodwill and Other Intangible Assets" and Section 3450, "Research and Development Costs". Intangible assets associated with the exploration and development of oil and gas assets are specifically excluded under the new standard. The Company is evaluating the implications but expects no material impact on the consolidated financial statements. On January 10, 2006, the CICA Accounting Standards Board ("AcSB") ratified a new strategic plan that would see the convergence of Canadian Generally Accepted Accounting Principles ("GAAP") with International Financial Reporting Standards ("IFRS") within 5 years. In March 2007, the AcSB released an "Implementation Plan for Incorporating IFRSs into Canadian GAAP", which assumed a convergence date of January 1, 2011. The AcSB confirmed this date in February 2008. The Company continues to monitor and assess the consequences of the convergence on the consolidated financial statements as they could have a material impact. p) Reclassification Certain amounts disclosed for prior years have been reclassified to conform with current year presentation. 2. Changes in significant accounting policies On January 1, 2007, the Company adopted the CICA Handbook Section 1530, "Comprehensive Income", Handbook Section 3855, "Financial Instruments - Recognition and Measurement", Handbook Section 3861, "Financial Instruments - Disclosure and Presentation", Handbook Section 3865, "Hedges", and Handbook Section 1506, "Accounting Changes". The adoption of these standards had no material impact on the Company's consolidated financial statements. Any significant effects from the implementation of the new standards are disclosed below. a) Comprehensive income The new standard introduced the statements of comprehensive income and accumulated other comprehensive income to temporarily provide for gains, losses and other amounts arising from changes in fair value until realized and recorded in net earnings. The Company has determined that it has no other comprehensive income nor accumulated other comprehensive income for the year ended December 31, 2007. b) Financial instruments The financial instruments standard establishes recognition and measurement criteria for financial assets, financial liabilities and derivatives. The Company's policies on accounting for financial instruments is disclosed in Note 1. Transitional provisions were outlined in the financial instruments standard and required retroactive adjustment without restatement of prior periods. In addition, the provisions required that, upon adoption at January 1, 2007, transitional adjustments, net of tax, be recognized in the opening balance of retained earnings. At January 1, 2007, the following transitional adjustments were required. - The reclassification of $14.0 million of deferred financing charges as a reduction of senior term notes to reflect the adopted policy of netting long term debt transaction costs within long term debt. The costs capitalized will be amortized using the effective interest method. Previously, the Company deferred these costs and amortized them straight line over the life of the related senior term notes. The adoption of this standard resulted in a $0.3 million net increase to opening retained earnings. - $3.97 million of deferred risk management loss, $2.7 million net of tax, previously recognized at January 1, 2004 upon initial adoption of CICA Accounting Guideline 13, "Hedging Relationships" was reclassified as a reduction to opening retained earnings. - The fair value measurement of investments resulted in a $1.1 million net increase to opening retained earnings. The net effect on opening retained earnings as a result of the transitional provisions is as follows: Deferred financing charge adjustments $ 318 Deferred risk management loss (2,743) Fair value of investments 1,105 ------------ Total adjustment to opening retained earnings $ (1,320) ------------ ------------ 3. Business combinations On August 15, 2007 and December 21, 2007, respectively, the Company acquired all of the issued and outstanding shares of Stylus Energy Inc. ("Stylus") and WIN Energy Corporation ("WIN"). Both entities were independent exploration and production companies with operations in the Company's core areas. The business combinations have been accounted for using the purchase method with results of operations included in the consolidated financial statements from the date of acquisition. If the purchase price is in excess of the fair value of net assets acquired, goodwill is recorded. The following table summarizes the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition. The Company is in the process of finalizing the estimated fair value of the WIN acquisition and therefore, the allocation of the purchase price is subject to refinement. Net assets acquired Stylus WIN Total ------------ ------------ ------------ Working capital $ (17,209) $ (2,010) $ (19,219) Petroleum and natural gas properties 106,916 24,465 131,381 ------------ ------------ ------------ 89,707 22,455 112,162 Future income taxes (12,288) 8,132 (4,156) Asset retirement obligations (4,402) (919) (5,321) Goodwill 2,020 - 2,020 ------------ ------------ ------------ $ 75,037 $ 29,668 $ 104,705 ------------ ------------ ------------ ------------ ------------ ------------ Consideration Cash $ 73,782 $ 29,414 $ 103,196 Transaction costs 1,255 254 1,509 ------------ ------------ ------------ $ 75,037 $ 29,668 $ 104,705 ------------ ------------ ------------ ------------ ------------ ------------ During the year ended December 31, 2007, both companies were wound up into Compton Petroleum Corporation. 4. Non-controlling interest Mazeppa Processing Partnership ("MPP" or "the Partnership") is a limited partnership organized under the laws of the province of Alberta and owns certain midstream facilities, including gas plants and pipelines in Southern Alberta. The Company processes a significant portion of its production from the area through these facilities pursuant to a processing agreement with MPP. The Company does not have an ownership position in MPP, however, the Company, through a management agreement, manages the activities of MPP and is considered to be the primary beneficiary of MPP's operations. Pursuant to AcG-15, these consolidated financial statements include the assets, liabilities, and operations of the Partnership. Equity in the Partnership, attributable to the partners of MPP, is recorded on consolidation as a non-controlling interest and is comprised of the following: As at December 31, 2007 2006 ------------ ------------ Non-controlling interest, beginning of year $ 66,350 $ 68,898 Earnings attributable to non-controlling interest 6,132 6,623 Distributions to limited partner (9,171) (9,171) ------------ ------------ Non-controlling interest, end of year $ 63,311 $ 66,350 ------------ ------------ ------------ ------------ Commencing May 1, 2004, pursuant to the terms of a processing agreement between Compton and MPP, Compton pays a monthly fee to MPP for the transportation and processing of natural gas through the MPP owned facilities. The fee is comprised of a fixed base fee of $764 thousand per month plus MPP operating costs, net of third party revenues. These amounts are eliminated from revenues and expenses on consolidation. The processing agreement has a five year term ending April 1, 2009, at which time Compton may renew the agreement under terms determined at that time or purchase the Partnership units for the predetermined amount of $55 million, deemed to be fair value. In the event that the Company does not renew the processing agreement nor exercise the purchase option, the limited partner may dispose of the Partnership units to an independent third party. MPP has guaranteed payment of certain obligations of its limited partner under a credit agreement between the limited partner and a syndicate of lenders. The maximum liability of the Partnership under the guarantee is limited to amounts due and payable to MPP by the Company pursuant to the processing agreement. The maximum liability at December 31, 2007 was $12.2 million (2006 - $21.4 million) payable over the remaining term of the processing agreement. The Company has determined that its exposure to loss under these arrangements is negligible. 5. Property and equipment Accumulated depletion and As at December 31, 2007 Cost depreciation Net ------------ ------------ ------------ Exploration and development costs $2,145,866 $ (603,867) $1,541,999 Production equipment and processing facilities 651,999 (105,720) 546,279 Inventory 6,871 - 6,871 Future asset retirement costs 19,940 (5,396) 14,544 Office equipment 14,111 (6,970) 7,141 ------------ ------------ ------------ $2,838,787 $ (721,953) $2,116,834 ------------ ------------ ------------ ------------ ------------ ------------ Accumulated depletion and As at December 31, 2006 Cost depreciation Net ------------ ------------ ------------ Exploration and development costs $1,931,594 $ (482,524) $1,449,070 Production equipment and processing facilities 582,705 (77,863) 504,842 Inventory 6,818 - 6,818 Future asset retirement costs 17,128 (4,906) 12,222 Office equipment 9,359 (5,249) 4,110 ------------ ------------ ------------ $2,547,604 $ (570,542) $1,977,062 ------------ ------------ ------------ ------------ ------------ ------------ During the year, $9.6 million (2006 - $10.5 million) relating to employee salaries, insurance costs, and overhead recoveries determined in accordance with industry standards, were capitalized. As at December 31, 2007, future capital expenditures of $318.3 million (2006 - $329.7 million, 2005 - $192.9 million), as estimated by independent reserve engineers, relating to the development of proved reserves have been included in costs subject to depletion. The estimated salvage value of production equipment and processing facilities at December 31, 2007 was $130.1 million (2006 - $120.1 million, 2005 - $108.6 million) and was excluded from costs subject to depletion. Undeveloped properties with a cost at December 31, 2007 of $260.6 million (2006 - $202.9 million, 2005 - $251.3 million) included in exploration and development costs, have not been subject to depletion. Prices used in the evaluation of the carrying value of the Company's reserves for the purposes of the impairment test were: Natural Crude Oil Gas (Edmonton As at December 31, 2007 (AECO C spot) par 40 API) NGL ------------ ------------ ------------ $ per MMbtu $ per bbl $ per bbl 2008 $6.74 $88.48 $91.04 2009 $7.48 $85.52 $88.03 2010 $7.69 $83.88 $86.41 2011 $7.80 $82.03 $84.54 2012 $7.84 $81.16 $83.66 Approximate % increase thereafter 2.0% 2.0% 2.0% 6. Credit facilities As at December 31, 2007 2006 ----------- ----------- Authorized $ 500,000 $ 500,000 ----------- ----------- ----------- ----------- Prime rate $ 50,000 $ 35,000 Bankers' Acceptance 350,000 295,000 Discount to maturity (1,574) (2,000) ----------- ----------- Utilized $ 398,426 $ 328,000 ----------- ----------- ----------- ----------- As at December 31, 2007, the Company had arranged a $500 million authorized senior credit facility with a syndicate of banks. Advances under the facilities can be drawn and currently bear interest as follows: Prime rate plus 0.95% Bankers' Acceptance rate plus 1.95% LIBOR rate plus 1.95% At December 31, 2007 prime and 30 day bankers acceptance rates were 6.0% and 4.6% respectively. Margins are determined based on the ratio of total consolidated debt to consolidated cash flow. The facilities reached term on July 4, 2007 and were renewed under the same terms and conditions to July 2, 2008. If not renewed in 2008 they will mature 366 days later on July 3, 2009. The senior credit facilities are secured by a first fixed and floating charge debenture in the amount of $1.0 billion covering all the Company's assets and undertakings. 7. Senior term notes As at December 31, 2007 2006 ----------- ----------- Senior term notes US$450 million, 7.625% due December 1, 2013 $ 444,645 $ 524,385 Unamortized transaction costs (10,883) - ----------- ----------- Carrying value $ 433,762 $ 524,385 ----------- ----------- ----------- ----------- On November 22, 2005, a wholly owned subsidiary of the Company issued US $300 million senior term notes maturing December 1, 2013. On April 4, 2006, an additional US$150 million was issued under the same terms and conditions as the original issue. The notes bear interest at 7.625%, are unsecured and are subordinate to the Company's bank credit facilities. The yield to maturity, using the effective interest method, was 8.840% as at December 31, 2007. Pursuant to the adoption of Handbook Section 3855, "Financial Instruments - Recognition and Measurement", transaction costs relating to the issue of the senior term notes reduce the carrying value of the notes as disclosed in Note 2. The notes are not redeemable by the Company prior to December 1, 2009, except in limited circumstances. After that time, they can be redeemed in whole or part, at the rates indicated below: December 1, 2009 103.813% December 1, 2010 101.906% December 1, 2011 and thereafter 100.000% During the year the Company entered into foreign exchange contracts as outlined in Note 17a (iii) which fixed the repayment, in Canadian dollars at December 1, 2010, being the second call date, as outlined in the senior note agreement. 8. Interest and finance charges Amounts charged to expense during the year ended are as follows: Years ended December 31, 2007 2006 2005 ------------ ------------ ------------ Interest on bank debt, net $ 22,476 $ 14,243 $ 11,520 Interest on senior term notes 38,345 35,880 20,912 Other finance charges 2,672 3,952 2,519 ------------ ------------ ------------ Total $ 63,493 $ 54,075 $ 34,951 ------------ ------------ ------------ ------------ ------------ ------------ Other finance charges include lease financing, bank service charges and fees as well as other miscellaneous expenses. The effective interest rate on bank debt at December 31, 2007 was 6.5% (2006 - 5.6%). 9. Other assets As at December 31, 2007 2006 ----------- ----------- Deferred financing charges $ - $ 14,008 Defined benefit pension plan 277 125 Other 14 11 ----------- ----------- Other assets $ 291 $ 14,144 ----------- ----------- ----------- ----------- On January 1, 2007 financing costs related to the issuance of senior term notes were reclassified from other assets to senior term notes, as disclosed in Note 2. 10. Foreign exchange (gain) loss Amounts charged to foreign exchange (gain) loss during the year ended were as follows: Years ended December 31, 2007 2006 2005 ------------ ------------ ------------ Foreign exchange gain on translation of US$ debt $ (79,740) $ (665) $ (7,808) Other foreign exchange (gain) loss 1,023 (226) 455 ------------ ------------ ------------ Total $ (78,717) $ (891) $ (7,353) ------------ ------------ ------------ ------------ ------------ ------------ 11. Asset retirement obligations The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the obligations associated with the retirement of oil and natural gas assets: As at December 31, 2007 2006 ----------- ----------- Asset retirement obligations, beginning of year $ 29,791 $ 20,770 Liabilities incurred 8,719 7,031 Liabilities settled and disposed (4,532) (267) Accretion expense 2,718 2,257 ----------- ----------- Asset retirement obligations, end of year $ 36,696 $ 29,791 ----------- ----------- ----------- ----------- The total undiscounted amount of estimated cash flows required to settle the obligations was $246.6 million (2006 - $233.0 million), which has been discounted using a credit-adjusted risk free rate of 10.8% (2006 - 10.6%). Due to the Company's long reserve life, the majority of these obligations are not expected to be settled until well into the future. Settlements will be funded from general Company resources at the time of retirement and removal. 12. Capital stock a) Authorized The Company is authorized to issue an unlimited number of common shares and an unlimited number of preferred shares, issuable in series. b) Issued and outstanding As at December 31, 2007 2006 --------------------- --------------------- Number Number of of Shares Amount Shares Amount ---------- ---------- ---------- ---------- (000s) (000s) Common shares outstanding, beginning of year 128,503 $231,992 127,263 $226,444 ---------- ---------- ---------- ---------- Shares issued under stock option plan 993 4,603 1,489 5,993 Shares repurchased (398) (724) (249) (445) ---------- ---------- ---------- ---------- Common shares outstanding, end of year 129,098 $235,871 128,503 $231,992 ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- The Company has, on an annual basis, instituted a normal course issuer bid program. Under the current program, the Company may purchase for cancellation up to 6,000,000 of its common shares, representing approximately 5.0% of the issued and outstanding common shares at the time the bid received regulatory approval. During the year, the Company purchased for cancellation 398,300 common shares at an average price of $9.98 per share (2006 - 248,900 common shares at an average price of $13.79 per share) pursuant to the normal course issuer bid. The excess of the purchase price over book value has been charged to retained earnings. c) Shareholder rights plan The Company has a shareholder rights plan (the "Plan") to ensure all shareholders are treated fairly in the event of a take-over offer or other acquisition of control of the Company. Pursuant to the Plan, the Board of Directors authorized and declared the distribution of one Right in respect of each common share outstanding. In the event that an acquisition of 20% or more of the Company's shares is completed and the acquisition is not a permitted bid, as defined by the Plan, each Right will permit the holder, other than holders not in compliance with the plan, to acquire a common share at a 50% discount to the market price at that time. 13. Stock-based compensation plans a) Stock option plan The Company has a stock option plan for employees, including directors and officers. The exercise price of each option approximated the market price for the common shares on the date the option was granted. Options granted under the plan before June 1, 2003 are fully exercisable and will expire ten years after the grant date. Options granted under the plan after June 1, 2003 are generally fully exercisable after four years and expire five years after the grant date. The following tables summarize the information relating to stock options: As at December 31, 2007 2006 --------------------- --------------------- Weighted Weighted average average Stock exercise Stock exercise options price options price ---------- ---------- ---------- ---------- (000s) (000s) Outstanding, beginning of year 11,611 $7.79 11,446 $6.13 Granted 2,074 $11.02 2,228 $13.99 Exercised (993) $3.47 (1,489) $3.14 Forfeited (608) $11.97 (574) $10.92 ---------- ---------- ---------- ---------- Outstanding, end of year 12,084 $8.49 11,611 $7.79 ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- Exercisable, end of year 7,240 $6.20 6,593 $4.82 ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- The range of exercise prices of stock options outstanding and exercisable at December 31, 2007 is as follows: Outstanding Options Exercisable Options -------------------------------- --------------------- Weighted average Number remaining Weighted Number Weighted Range of of contractual average of average exercise options life exercise options exercise prices outstanding (years) price outstanding price --------- ---------- ---------- ---------- ---------- ---------- (000s) (000s) $1.45 - $3.99 2,665 2.6 $ 2.72 2,665 $ 2.72 $4.00 - $6.99 2,013 2.7 $ 4.94 1,995 $ 4.93 $7.00 - $9.99 1,533 2.2 $ 7.94 884 $ 7.63 $10.00 - $11.99 2,740 3.4 $ 11.19 633 $ 10.92 $12.00 - $13.99 1,713 2.7 $ 12.63 698 $ 12.61 $14.00 - $18.39 1,420 3.1 $ 14.69 365 $ 14.70 ---------- ---------- ---------- ---------- ---------- 12,084 2.9 $ 8.49 7,240 $ 6.20 ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- The Company has recorded stock-based compensation expense in the consolidated statements of earnings and other comprehensive income for stock options granted to employees, directors, and officers after January 1, 2003 using the fair value method. The fair value of each option granted is estimated on the date of grant using the Black-Scholes option pricing model with weighted average assumptions for grants as follows: Years ended December 31, 2007 2006 2005 ------------ ------------ ------------ Weighted average fair value of options granted $4.23 $6.90 $5.45 Risk-free interest rate 4.1% 4.0% 3.6% Expected life (years) 5.0 5.0 5.0 Expected volatility 39.0% 43.5% 43.9% The following table presents the reconciliation of contributed surplus with respect to stock-based compensation: As at December 31, 2007 2006 ----------- ----------- Contributed surplus, beginning of year $ 16,974 $ 9,173 Stock-based compensation expense 8,416 9,121 Stock options exercised (1,157) (1,320) ----------- ----------- Contributed surplus, end of year $ 24,233 $ 16,974 ----------- ----------- ----------- ----------- b) Share appreciation rights plan CICA Handbook section 3870 requires recognition of compensation costs with respect to changes in the intrinsic value for the variable component of fixed share appreciation rights ("SARs"). During the years ended December 31, 2007, 2006 and 2005, there were no significant compensation costs related to the outstanding variable component of these SARs. The liability related to the variable component of these SARs amounts to $1.0 million, which is included in accounts payable as at December 31, 2007 (2006 - $1.2 million). All outstanding SARs having a variable component expire at various times through 2011. c) Employee retention program In recognition of the shortage of qualified personnel that existed within the industry, the Company implemented an Employee Retention program in July 2006 for its existing employees at the time, excluding officers and directors. Under the program, the Company incurred additional compensation costs of $4.0 million, in July 2007, $2.6 million of which was recognized in 2007 and the balance in 2006. Amounts paid under the program were determined in relation to the market value of the Company's capital stock and accordingly have been included in stock-based compensation. No further obligation exists pursuant to this program. 14. Per share amounts The following table summarizes the common shares used in calculating net earnings per common share: Years ended December 31, 2007 2006 2005 ------------ ------------ ------------ (000s) (000s) (000s) Weighted average common shares outstanding - basic 128,993 127,820 125,627 Effect of stock options 3,546 5,806 6,040 ------------ ------------ ------------ Weighted average common shares outstanding - diluted 132,539 133,626 131,667 ------------ ------------ ------------ ------------ ------------ ------------ In calculating diluted earnings per common share for the year ended December 31, 2007, the Company excluded 5,553,700 options (2006 - 1,537,100, 2005 - 331,800) as the exercise price was greater than the average market price of its common shares in those years. 15. Defined benefit pension plan There are 35 employees of MPP currently enrolled in a co-sponsored, defined benefit pension plan. Information relating to the MPP retirement plan is outlined below: As at December 31, 2007 2006 ----------- ----------- Accrued benefit obligation Accrued benefit obligation - beginning of year $ 7,717 $ 7,562 Current service cost 401 368 Interest cost 403 387 Benefits paid (121) (392) Actuarial (gain) loss (705) (208) ----------- ----------- Accrued benefit obligation - end of year $ 7,695 $ 7,717 ----------- ----------- ----------- ----------- Fair value of plan assets Fair value of plan assets - beginning of year $ 6,635 $ 5,839 Employee contributions 87 82 Employer contributions 460 439 Benefits paid (121) (392) Actual return on plan assets (164) 667 ----------- ----------- Fair value of plan assets - end of year $ 6,897 $ 6,635 ----------- ----------- ----------- ----------- Accrued benefit asset Funded status - plan assets less than benefit obligation $ (798) $ (1,082) Unamortized net actuarial loss 352 414 Unamortized past service costs 723 793 ----------- ----------- Accrued benefit asset, included in other assets (Note 9) $ 277 $ 125 ----------- ----------- ----------- ----------- Economic assumptions used to determine benefit obligation and periodic expense were: Years ended December 31, 2007 2006 ----------- ----------- Discount rate 5.0% 5.0% Expected rate of return on assets 7.0% 7.0% Rate of compensation increase 3.5% 3.5% Average remaining service period of covered employees 16 years 16 years Actuarial evaluations are required every three years, the next evaluation being January 1, 2009. Pension expense, included in MPP operating costs, is as follows: Years ended December 31, 2007 2006 ----------- ----------- Current service cost, net of employee contributions $ 307 $ 292 Interest on accrued benefit obligation 403 387 Return on assets (479) (407) Amortization of past service cost 69 69 Amortization of net actuarial loss - 9 ----------- ----------- Pension expense, included in operating expense $ 300 $ 350 ----------- ----------- ----------- ----------- MPP expects to contribute $547 thousand to the plan in 2008. 16. Income taxes a) The following table reconciles income taxes calculated at the Canadian statutory rate with actual income taxes: Years ended December 31, 2007 2006 2005 ------------ ------------ ------------ Earnings before taxes and non-controlling interest $ 108,963 $ 130,457 $ 145,247 ------------ ------------ ------------ Canadian statutory rate 32.1% 34.5% 37.6% Expected income taxes $ 34,977 $ 45,008 $ 54,613 Effect on taxes resulting from: Non-deductible Crown charges - 2,145 15,061 Resource allowance - (1,987) (11,980) Non-deductible stock-based compensation 2,704 3,147 2,221 Federal capital tax - - 1,896 Effect of tax rate changes (50,470) (49,655) (5,764) Non-taxable capital (gains) losses (11,651) (115) - Other (1,995) (2,135) 1,341 ------------ ------------ ------------ Provision for income taxes $ (26,435) $ (3,592) $ 57,388 ------------ ------------ ------------ ------------ ------------ ------------ Current Income taxes $ 17 $ 44 $ 3,175 Federal capital taxes - - 1,896 Future (26,452) (3,636) 52,317 ------------ ------------ ------------ $ (26,435) $ (3,592) $ 57,388 ------------ ------------ ------------ ------------ ------------ ------------ Effective tax rate (24.3)% (2.8)% 39.5% ------------ ------------ ------------ ------------ ------------ ------------ A significant portion of the Company's taxable income is generated by a partnership. Income taxes are incurred on the majority of the partnership's taxable income in the year following its inclusion in the Company's consolidated net earnings. Current income tax is dependent upon the amount of capital expenditures incurred and the method of deployment. The Canadian federal government, during the fourth and second quarters of 2007 and the second quarter of 2006, and the Alberta government, during the second quarter of 2006 enacted income tax rate changes. b) Future income taxes are classified on the balance sheet as: As at December 31, 2007 2006 ----------- ----------- Current asset $ (2,606) $ (1,479) Current liability 542 7,269 Non-current liability 293,494 302,690 ----------- ----------- Net future income tax liability $ 291,430 $ 308,480 ----------- ----------- ----------- ----------- The net future income tax liability is comprised of: As at December 31, 2007 2006 ----------- ----------- Future income tax liabilities Property and equipment in excess of tax values $ 252,594 $ 229,936 Timing of partnership items 43,857 83,328 Foreign exchange gain on long-term debt 18,340 8,729 Other - 2,591 Future income tax assets Non-capital losses carried forward (5,422) - Attributed Canadian royalty income (7,810) (7,462) Asset retirement obligations (9,177) (8,642) Other (952) - ----------- ----------- Net future income tax liability $ 291,430 $ 308,480 ----------- ----------- ----------- ----------- The non-capital losses available for carry forward to reduce taxable income in future years expire between 2011 and 2026. 17. Financial instruments Derivative financial instruments and risk management activities The Company is exposed to risks from fluctuations in commodity prices, interest rates, and Canada/US currency exchange rates. The Company utilizes various derivative financial instruments for non- trading purposes to manage and mitigate its exposure to these risks. Effective January 1, 2004, the Company elected to account for all derivative financial instruments using the mark-to-market method. On January 1, 2007 the Company adopted the new financial instrument recognition, measurement, presentation and disclosure requirements of the CICA as disclosed in Note 2 (b) to these consolidated financial statements. Certain items have been reclassified as a reduction to opening retained earnings, net of tax, as prescribed in the transitional provisions. Risk management activities during the year, utilizing derivative instruments, relate to commodity price economic hedges, fixed price power contracts, foreign currency contracts and cross currency interest rate swap arrangements. a) Unrealized risk management gains and losses as at December 31, 2007 i) Balance sheet classification As at December 31, 2007, the Company had outstanding financial instrument contracts for both commodity price risk management and foreign currency risk management expiring at various periods to December 2010. These contracts were valued on a mark-to-market basis as at December 31, 2007 and the unrealized gains and losses relating to these contracts are recorded on the consolidated balance sheets as follows: Commodity Foreign 2007 2006 As at December 31, 2007 Contracts Currency Total Total ---------- ---------- ---------- ---------- Unrealized gain Current asset $ 1,790 $ 45 $ 1,835 $ 22,625 Non-current asset - 14,320 14,320 - Unrealized loss Current liability - (8,832) (8,832) (4,604) Non current liability - (1,585) (1,585) (6,816) ---------- ---------- ---------- ---------- Total unrealized gains (losses) $ 1,790 $ 3,948 $ 5,738 $ 11,205 ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- The amounts relating to commodity price risk management and foreign exchange risk management, respectively, are disclosed below: ii) Commodity price risk management The Company enters into economic hedge transactions relating to crude oil and natural gas prices to mitigate volatility in commodity prices and the resulting impact on cash flow. The contracts entered into are forward transactions providing the Company with a range of prices on the commodities sold. Prices are marked to industry benchmarks specifically AECO spot for gas contracts and WTI NYMEX for oil contracts and are valued in Canadian dollars unless otherwise disclosed. Outstanding economic hedge contracts at December 31, 2007 are: Daily Mark-to- Notional Average Market Commodity Term Volume Price gain --------- ---- -------- ------- --------- Natural gas $8.27 - Collar Nov./07 - Mar./08 9,524mcf $10.50/mcf $ 1,416 Electricity Jan./06 - Dec./08 2.5MW $55.00/MWh 374 --------- $ 1,790 --------- --------- The gains and losses realized during the year on the electricity contract are included in operating expenses. Subsequent to December 31, 2007, the Company entered into the following commodity contracts: Natural gas Collar Apr./08 - Oct./08 52,381 mcf $7.33 - $8.48/mcf Fixed Apr./08 - Oct./08 19,048 mcf $7.86/mcf Collar Nov./08 - Mar./09 28,571 mcf $8.40 - $10.00/mcf Fixed Nov./08 - Mar./09 9,524 mcf $8.51/mcf Oil Fixed Mar./08 - Dec./08 1,000 bbl US$93.00/bbl iii) Foreign currency risk management The Company is exposed to fluctuations in the exchange rate between the Canadian dollar and the US dollar. Crude oil and to a certain extent natural gas prices are based upon reference prices denominated in US dollars, while the majority of the Company's expenses are denominated in Canadian dollars. When appropriate, the Company enters into agreements to fix the exchange rate of Canadian dollars to US dollars in order to manage the risk. Concurrent with the issuance of 9.90% Senior Notes in 2002, the Company entered into cross currency interest rate swap arrangements expiring May 2009 that convert fixed rate US dollar denominated interest obligations into floating rate Canadian dollar denominated interest obligations. On purchase of the majority of the 9.90% Senior Notes in November 2005, the Company elected not to collapse the cross currency interest rate swap and maintains it as a source of US funds used to settle interest obligations on the 7.625% Senior Notes. During the year the Company entered into a series of foreign exchange contracts relating to the US$450 million senior notes due December 1, 2013, effectively fixing the liability in Canadian dollars on December 1, 2010, being the second call date of the senior notes. Additionally, the Company entered into a series of foreign exchange contracts relating to the semi-annual interest settlement obligations until November 30, 2010. On December 31, 2007, the Company had the following foreign exchange contracts in place: Amount Amount Mark to Contract USD Rate CDN Term Market --------- ------ ---- ------ ---- -------- Matures on Currency December 1, Swap $450,000,000 96.9750 $436,387,500 2010 $ 14,146 Equal Payments on May 30 and Currency Nov. 30 until Swap $78,435,000 99.5500 $78,082,043 2010 219 Cross Currency Equal payments Interest on May 15 and Rate BA plus Nov. 15 until Swap $24,502,500 4.845% $34,627,785 2009 (10,417) --------- Total unrealized foreign exchange gain $ 3,948 --------- --------- b) Risk management (gain) loss Risk management gains and losses recognized in the consolidated statements of earnings and other comprehensive income during the periods relating to commodity prices and foreign currency transactions are summarized below: Commodity Foreign Year ended December 31, 2007 Contracts Currency Total ------------ ------------ ------------ Unrealized Change in fair value $ 20,834 $ (15,367) $ 5,467 ------------ ------------ ------------ Realized cash settlements (19,220) 7,739 (11,481) ------------ ------------ ------------ Total (gain) loss $ 1,614 $ (7,628) $ (6,014) ------------ ------------ ------------ ------------ ------------ ------------ Commodity Foreign Year ended December 31, 2006 Contracts Currency Total ------------ ------------ ------------ Unrealized Amortization of deferred loss $ - $ 1,642 $ 1,642 Change in fair value (25,775) (3,389) (29,164) ------------ ------------ ------------ (25,775) (1,747) (27,522) Realized cash settlements (39,217) 3,018 (36,199) ------------ ------------ ------------ Total (gain) loss $ (64,992) $ 1,271 $ (63,721) ------------ ------------ ------------ ------------ ------------ ------------ Commodity Foreign Year ended December 31, 2005 Contracts Currency Total ------------ ------------ ------------ Unrealized Amortization of deferred loss $ - $ 1,642 $ 1,642 Change in fair value 5,136 3,393 8,529 ------------ ------------ ------------ 5,136 5,035 10,171 Realized cash settlements 9,663 (532) 9,131 ------------ ------------ ------------ Total loss $ 14,799 $ 4,503 $ 19,302 ------------ ------------ ------------ ------------ ------------ ------------ c) Credit risk management Accounts receivable include amounts receivable for oil and natural gas sales which are generally made to large credit worthy purchasers and amounts receivable from joint venture partners which are generally recoverable from production. Accordingly, the Company views credit risks on these amounts as low. The Company is exposed to losses in the event of non-performance by counter-parties to financial instruments. The Company deals with major financial institutions and believes these risks are minimal. d) Fair value of financial assets and liabilities Held for trading financial assets and liabilities are carried at fair value. The carrying value of accounts receivable, accounts payable, and bank debt approximate fair value due to the short term nature of these instruments and variable rates of interest. The senior term notes trade in the US and the estimated fair value was determined using quoted market prices. As at December 31, 2007 2006 Carrying Fair Carrying Fair Amount Value Amount Value Financial Assets Held-for-trading Cash $ 8,665 $ 8,665 $ 11,876 $ 11,876 Other current assets 19,772 19,772 22,869 22,869 Loans and receivables Accounts receivable $ 80,331 $ 80,331 $ 83,535 $ 83,535 Financial Liabilities Other financial liabilities Accounts payable $147,983 $147,983 $141,443 $141,443 Bank debt 398,426 398,426 328,000 328,000 Senior term notes 433,762 415,743 524,385 503,410 The fair value of derivative financial instruments related to risk management activities, classified as held-for-trading, are disclosed elsewhere in this note. 18. Cash flow Changes in non-cash working capital items increased (decreased) cash as follows: Years ended December 31, 2007 2006 2005 ------------ ------------ ------------ Accounts receivable and other current assets $ (11,614) $ 24,395 $ (17,672) Accounts payable 6,540 (62,425) 78,385 ------------ ------------ ------------ $ (5,074) $ (38,030) $ 60,713 ------------ ------------ ------------ ------------ ------------ ------------ Net change in non-cash working capital Relating to: Operating activities $ (23,366) $ 19,823 $ 6,612 Investing activities 18,292 (57,853) 54,101 ------------ ------------ ------------ $ (5,074) $ (38,030) $ 60,713 ------------ ------------ ------------ ------------ ------------ ------------ Amounts paid during the year relating to interest expense and capital taxes were as follows: Years ended December 31, 2007 2006 2005 ------------ ------------ ------------ Interest paid $ 60,976 $ 48,857 $ 31,444 ------------ ------------ ------------ ------------ ------------ ------------ Current income taxes paid $ 41 $ 14 $ 4,101 ------------ ------------ ------------ ------------ ------------ ------------ 19. Commitments and contingent liabilities a) Commitments The Company has committed to certain payments over the next five years, as follows: 2008 2009 2010 2011 2012 ---------- ---------- ---------- ---------- ---------- Operating leases $ 3,811 $ 3,325 $ 505 $ - $ - Office facilities 4,351 4,921 6,160 5,484 5,569 MPP partnership distributions 9,172 3,057 - - - ---------- ---------- ---------- ---------- ---------- $ 17,334 $ 11,303 $ 6,665 $ 5,484 $ 5,569 ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- The Company has entered into a lease agreement for new office facilities commencing 2009. Annual commitments under the lease agreement are approximately $5.6 million per year for the 10 year term. The commitment remaining on the office facilities subsequent to 2012 is $33.6 million and the total of all commitments, to expiry, is $80 million. b) Legal proceedings The Company is involved in various legal claims associated with normal operations. These claims, although unresolved at the current time, in management's opinion, are not significant and are not expected to have a material impact on the financial position or results of operations of the Company. 20. Subsequent events On January 23, 2008, Compton announced its budget for 2008 and the Company's longer term plans for 2009 and 2010. On January 29, 2008, the Company received a letter from Centennial Energy Partners LLC, a major shareholder of the Company, wherein they restated comments contained in a letter to the Company dated December 14, 2007, that in their opinion, a major discount had developed between the underlying value of the Company's asset base and its share price. Additionally, they expressed concerns that the Company's plans, as announced, would not eliminate the discount and require Compton shareholders' to assume significant execution risk, commodity price risk and stock market risk for minimal per-share return and requested that the Company be put up for sale. In response to Centennial's concerns, the Board of Directors, in a news release dated February 28, 2008, announced that it would conduct a formal review of the Company's business plans and alternatives for enhancing shareholder value, and had appointed independent financial advisors to assist the Company in the conduct of this review. The Company has estimated that during 2008, Compton will incur direct costs associated with, and costs resulting from, the process that could total approximately $22 million. These expenses will be recognized throughout the year as they occur. In addition to the above, cash outlays associated with change of control provisions relating to the Company's senior notes, Mazeppa Processing Partnership arrangements, and employee contracts could result depending upon the outcome of the review. Further Information Additional information, including our Annual Information Form, will be available by month end on the Canadian Securities Administrators' System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com. CONFERENCE CALL Compton will be conducting a conference call and audio webcast Wednesday, March 26, 2008 at 9:30 a.m. Mountain Standard Time (11:30 a.m. EST) to discuss the Company's 2007 fourth quarter and 2007 annual financial and operating results. To participate in the conference call, please contact the Conference Operator at 9:20 a.m. (MST), ten minutes prior to the call. Conference Operator Dial-in Number: Toll-Free 1-800-732-9307 Local Toronto: 1-416-644-3418 Webcast URL: http://phx.corporate-ir.net/phoenix.zhtml?p=irol-eventDetails&c=69018&eve ntID=1766299 The audio replay will be available two hours after the conclusion of the conference call and will be accessible until Tuesday, April 3, 2007. Callers may dial toll-free 1-877-289-8525 and enter access code 21263872 (followed by the pound key). Compton Petroleum Corporation is a Calgary-based public company actively engaged in the exploration, development, and production of natural gas, natural gas liquids, and crude oil in the Western Canada Sedimentary Basin. Compton's shares are listed on the Toronto Stock Exchange under the symbol CMT and on the New York Stock Exchange under the symbol CMZ. %SEDAR: 00003803E %CIK: 0001043572

For further information:

For further information: E.G. Sapieha, President & CEO, N.G. Knecht, VP
Finance & CFO, or Lorna Klose, Manager, Investor Relations, Telephone: (403)
237-9400, Fax (403) 237-9410; Website: www.comptonpetroleum.com, Email:
investorinfo@comptonpetroleum.com

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