Compton Petroleum announces third quarter results



    CALGARY, Nov. 12 /CNW/ - Compton Petroleum Corporation ("Compton" or the
"Company") is pleased to announce its financial and operating results for the
quarter ended September 30, 2007.
    The third quarter of 2007 has been an exceptionally active quarter for
Compton. "As outlined in our Operational Update of November 1, 2007, we
drilled 130 wells this quarter, and since quarter end we have drilled another
60 wells," said Ernie Sapieha, President and CEO of the Company. "We were also
very active on the facilities front, adding pipelines, compression, and tying
in 70 wells. We are currently producing approximately 33,300 boe/d and with
170 wells scheduled to be on-stream by year end, we believe we are on track to
meet our targeted exit production rate of 36,000 to 37,000 boe/d."

    
    THIRD QUARTER HIGHLIGHTS

    -   Drilling success in all areas - drilled 130 wells with a 96% success
        rate.
    -   Average production of 30,440 boe/d, a 5% increase from second quarter
        2007.
    -   Closed $92 million acquisition of Stylus Energy Inc.
    -   Closed $270 million Worsley conventional oil disposition.

    FINANCIAL SUMMARY

    -------------------------------------------------------------------------
    ($000s, except          Three Months Ended          Nine Months Ended
     per share                  Sept. 30                    Sept. 30
     amounts)            2007       2006   Change    2007       2006   Change
    -------------------------------------------------------------------------
    Gross revenue     $ 107,980  $ 126,991  -15%  $ 375,028  $ 410,548   -9%
    Cash flow from
     operations(1)    $  33,133  $  60,120  -45%  $ 150,498  $ 201,042  -25%
    Per share
      - basic(1)      $    0.26  $    0.47  -45%  $    1.17  $    1.57  -25%
      - diluted(1)    $    0.25  $    0.45  -44%  $    1.13  $    1.50  -25%
    Operating
     earnings(1)      $  (1,994) $  13,150 -115%  $  23,303  $  53,342  -56%
    Net earnings      $  19,782  $  30,717  -36%  $  78,808  $ 137,463  -43%
    Per share
      - basic         $    0.15  $    0.24  -38%  $    0.61  $    1.08  -44%
      - diluted       $    0.15  $    0.23  -35%  $    0.59  $    1.03  -43%
    Capital
     expenditures
     before
     acquisitions
     and divestments  $ 115,635  $ 142,688  -19%  $ 269,441  $ 402,771  -33%
    -------------------------------------------------------------------------
    (1) See advisory statements following Management's Discussion and
        Analysis.


    OPERATING SUMMARY

    -------------------------------------------------------------------------
                            Three Months Ended          Nine Months Ended
                                Sept. 30                    Sept. 30
                         2007       2006   Change    2007       2006   Change
    -------------------------------------------------------------------------
    Average daily
     production
      Natural gas
       (mmcf/d)             135        142   -5%        138        140   -1%
      Liquids (bbls/d)    7,954      9,249  -14%      7,958      9,825  -19%
    -------------------------------------------------------------------------
      Total (boe/d)      30,440     32,843   -7%     30,881     33,168   -7%

    Realized prices
      Natural gas
       ($/mcf)        $    5.23  $    5.38   -3%  $    6.47  $    6.27    3%
      Liquids ($/bbl)     61.91      64.58   -4%      59.15      61.72   -4%
    -------------------------------------------------------------------------
      Total ($/boe)   $   38.56  $   42.03   -8%  $   44.48  $   45.34   -2%

    Field netback
     ($/boe)          $   20.51  $   22.23   -8%  $   25.38  $   25.81   -2%
    -------------------------------------------------------------------------
    

    OPERATIONS REVIEW

    During the first nine months of 2007, we drilled 214 (177 net) wells,
with a 96% success rate. In the third quarter of 2007, we drilled 130 wells,
with September being our busiest month on record.
    Seventy wells were tied in during the third quarter, adding an estimated
4,300 boe/d of production. In October we drilled 60 wells and tied in
22 wells. Currently, we have eight drilling rigs operating and 13 pipeline
and/or facility crews working to bring on new production.

    DRILLING SUMMARY

    Of the 130 (92 net) wells drilled during the quarter, 118 or 91% were
classified as development wells and 12 or 9% as exploratory wells. The
following table summarizes our drilling results in the first nine months of
the year.

    
    -------------------------------------------------------------------------
    Nine Months Ended September 30   Gas   Oil   D&A   Total    Net  Success
    -------------------------------------------------------------------------
    Southern Alberta                 146     -     1     147  130.1      99%
    Central Alberta                   27     7     6      40   27.6      85%
    Peace River Arch                   1    15     2      18   11.0      89%
    -------------------------------------------------------------------------

    Standing, cased wells                                  9    9.0
    -------------------------------------------------------------------------
    Total                                                214  177.7      96%
    -------------------------------------------------------------------------
    

    SOUTHERN ALBERTA SHALLOW GAS

    Southern Alberta remains the primary focus of our activities. We estimate
that we now hold in excess of 1,000 net sections of land in the south that are
prospective for multiple zones including Basal Quartz at Hooker, thrusted
Belly River at Callum, Wabamun/Crossfield, the Plains Belly River, and
Edmonton/CBM.

    Plains Belly River and Edmonton Horseshoe Canyon CBM

    In the third quarter, 99 Belly River wells were drilled, with all wells
encountering multiple sands and uphole Edmonton/Horseshoe Canyon sands, silts,
and coals. Year to date, we have drilled 193 Belly River wells. In October, we
drilled 55 Belly River wells and tied-in 22 wells.
    At our Southern Alberta Shallow gas project, we tied in 45 new Belly
River wells in the third quarter, with an additional 14 wells tied-in during
October. We have 132 existing wells that are scheduled for tie-in the last
months of 2007.
    At Ghost Pine, to date, we have drilled 32 of a planned 34 second half
2007 wells. We are expanding pipeline infrastructure and compression
facilities from eight mmcf/d to 12 mmcf/d in this area, as drilling continues
to show good results. We are currently in the process of licensing an
additional 25 Ghost Pine drilling locations in order to match facility
expansions in the area.
    In the Clareshome area on lands newly added through our Stylus
acquisition, we tied in five new 100% owned Belly River wells that are
currently producing approximately 2.1 mmcf/d in aggregate. We are currently in
the process of acquiring 25 new well locations that were identified using 3D
seismic attained from Stylus.

    SOUTHERN ALBERTA DEEP BASIN GAS

    Callum Thrusted Belly River

    In September, we announced our intention to purchase all of the issued
and outstanding shares of WIN Energy Inc., a junior exploration and production
company with core assets immediately adjacent to our lands at Callum. This
transaction is scheduled to close by the end of November.
    We are in the process of conducting a public consultation related to
licensing two more exploratory wells in the area, two new experimental
horizontal wells from existing production pad sites, and an extension to the
horizontal section of our existing horizontal well. We expect to commence
operations on these projects during the winter of 2007 - 2008.

    Hooker Basal Quartz

    Two wells were drilled targeting the lower Cretaceous Basal Quartz
resource play at Hooker in the third quarter. Both wells were successful. With
the success Compton has experienced drilling horizontal wells in other
geologically similar areas, we have two horizontal wells planned for the
fourth quarter of this year at Hooker. Depending on the length of the
horizontal section in each, we expect these wells will replace drilling
between three to four vertical wells each. We have identified 13 follow up
horizontal locations.

    CENTRAL ALBERTA DEEP BASIN GAS

    Central Alberta provides us with excellent exploration and development
drilling opportunities using analogous techniques gained through our
experience with unconventional gas development in southern Alberta. In the
first nine months of 2007, 40 (27.6 net) wells were drilled in central Alberta
with an 85% success rate.

    Niton

    We drilled eight wells at Niton during the third quarter, for a total of
19 wells drilled to date this year. Compton has working interests in nine
horizontal wells in this area, of which six are Company operated. Two of these
are currently producing approximately 6 mmcf/d, while a third is currently
producing at approximately 3.5 mmcf/d. Recently, we have acquired another half
township of land in the Niton area, and we are currently completing two
horizontal wells. We have just finished one horizontal well that has set-up
eight to ten further offset wells for the company.
    Year to date at Niton we have undertaken a number of facility and
infrastructure expansions to match the success we've had with our drilling
programs in this area. We have doubled the capacity of our Edson 7-20-53-15W5
compressor station to 20 mmcf/d, and have also installed two more compressors
in the area. Additionally, we have twinned pipelines leading to the Rosevear
10-11-54-14W5 gas plant. These initiatives increase Compton's gas handling
capacity to approximately 31 mmcf/d in south west Niton.

    Caroline

    Located in the Deep Basin fairway, we control 60 sections of land at
Caroline, an area that is geologically similar to Niton. At Caroline, we
drilled five wells this quarter, four of which were successful. These wells
target equivalent zones to our main producing Niton Gething and Rock Creek
formations. Proprietary technical knowledge gained from other Deep Basin core
areas, such as Niton and Hooker, are being applied with success in the area.
Results to date show this area to be a promising developing asset for the
Company.


    MANAGEMENT'S DISCUSSION AND ANALYSIS

    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 November 9, 2007 and should be read in conjunction with the interim
unaudited consolidated financial statements for the nine months ended
September 30, 2007 and the audited consolidated financial statements for the
year ended December 31, 2006, available in printed form on request and posted
on Compton's website.
    Additional advisories with respect to forward looking statements, the use
of non-GAAP financial measures, and the use of BOE volumetric measures are set
out at the end of this MD&A.

    RECENT DEVELOPMENTS

    The following government announcements, made subsequent to September 30,
2007, will impact operations in future years.

    Corporate Income Tax Reduction

    On October 30, 2007 the Government of Canada announced significant
reductions in the general federal corporate income tax rate from the current
22.12% for 2007 to 15% by 2012. As set out in the table below, the currently
enacted rate reductions will be enhanced further between now and 2012.

    
    General Federal Corporate Income Tax Rate Reductions
    -------------------------------------------------------------------------
                        2007(1)    2008     2009     2010     2011     2012
    -------------------------------------------------------------------------
    Existing Rates       22.12%    20.5%    20.0%    19.0%    18.5%    18.5%
    Proposed Rates       22.12%    19.5%    19.0%    18.0%    16.5%    15.0%
    -------------------------------------------------------------------------
    (1) The 2007 corporate income tax rate of 22.12% includes the 1.12%
        corporate surtax, which will be eliminated in 2008.
    

    The existing rate reductions are currently reflected in our future income
tax liability. The proposed rate reductions will further reduce our future
income tax liability and will be determined once the proposed changes are
substantially enacted by parliament.

    Alberta Royalty Review

    The Government of Alberta recently announced proposed changes to the
Crown Royalty structure for the province. The changes will come into effect on
January 1, 2009 and relate to royalties payable on production from Crown
mineral rights owned by the province. Although all details relating to the new
structure are not as yet available, we have assessed their impact on Compton
based upon current publicly available information.
    In very general terms, royalties will be calculated on a sliding scale
basis giving effect to well production rates and commodity prices. At current
price levels, Compton would realize a reduction in Crown royalties on shallow
gas production from that currently assessed up to a price of approximately
$9.00 per mcf. Higher productivity wells will attract higher rates even at
current price levels. The increase in royalties for higher productivity wells
will be somewhat mitigated by a deep gas royalty reduction based upon the
measured depth of the well.
    There is no change in royalties and mineral taxes relating to production
from freehold mineral rights. This is relevant to our activities at Hooker in
southern Alberta, where approximately 50% of our production is from freehold
acreage.
    Based upon our assessment and assumptions to date, we believe the new
royalty regime will have a minimal impact on the Company both in relation to
net asset value and 2009 royalty expenses, given current projected commodity
pricing. Our assumptions include applying the deep gas royalty holiday to
existing wells as well as to new drills. As more details become available, we
will update our assessment and advise accordingly.

    
    EXECUTIVE SUMMARY

    -   Quarterly production averaged 30,440 boe/d, an increase of 5% over
        the second quarter 2007.
    -   Net earnings were $20 million.
    -   Cash flow from operations was $33 million.
    -   Closed $92 million acquisition of Stylus Energy Inc.
    -   Closed $270 million Worsley conventional oil divestment.

    RESULTS OF OPERATIONS

    Cash Flow from Operations, Operating Earnings, and Net Earnings
    -------------------------------------------------------------------------
    ($000s, except          Three Months Ended          Nine Months Ended
     per share                  Sept. 30                    Sept. 30
     amounts)            2007       2006   Change    2007       2006   Change
    -------------------------------------------------------------------------
    Cash flow from
     operations(1)    $  33,133  $  60,120  -45%  $ 150,498  $ 201,042  -25%
    Per share
      - basic         $    0.26  $    0.47  -45%  $    1.17  $    1.57  -25%
      - diluted       $    0.25  $    0.45  -44%  $    1.13  $    1.50  -25%
    Operating
     earnings         $  (1,994) $  13,150 -115%  $  23,303  $  53,342  -56%
    Net earnings      $  19,782  $  30,717  -36%  $  78,808  $ 137,463  -43%
    Per share
      - basic         $    0.15  $    0.24  -38%  $    0.61  $    1.08  -44%
      - diluted       $    0.15  $    0.23  -35%  $    0.59  $    1.03  -43%
    -------------------------------------------------------------------------
    (1) Cash flow from operations represents net income before depletion and
        depreciation, future income taxes, and other non-cash expenses.
    

    Cash flow from operations for the third quarter of 2007 decreased 45%
from the comparable period in 2006 primarily as a result of lower natural gas
prices and reduced year over year production volumes.
    Net earnings for the three months ended September 30, 2007 fell by 36%
when compared to the third quarter of 2006 due to lower realized natural gas
prices. Despite lower year over year natural gas prices, net earnings did
benefit from foreign exchange gains related to our U.S. dollar denominated
Senior Notes.

    OPERATING EARNINGS

    Operating earnings is a non-GAAP measure that adjusts net earnings by
non-operating items that we believe reduces the comparability of our
underlying financial performance between periods. The following reconciliation
of operating earnings has been prepared to provide investors with information
that is more comparable between periods.

    
    Summary of Operating Earnings
    -------------------------------------------------------------------------
                                       Three Months          Nine Months
    ($000s, except                    Ended Sept. 30        Ended Sept. 30
     per share amounts)              2007       2006       2007       2006
    -------------------------------------------------------------------------
    Net earnings, as reported     $  19,782  $  30,717  $  78,808  $ 137,463
    Non-operational items,
     after tax
      Unrealized foreign exchange
       (gain) loss                  (25,346)       104    (63,836)   (19,170)
      Unrealized risk management
       loss (gain)                    3,290    (12,888)    15,108    (22,008)
      Stock-based compensation        1,460      1,431      4,602      4,502
      Effect of tax rate changes
       on future income tax
       liabilities                   (1,180)    (6,214)   (11,379)   (47,445)
    -------------------------------------------------------------------------
    Operating earnings            $  (1,994) $  13,150  $  23,303  $  53,342
    Per share
      - basic                     $   (0.02) $    0.10  $    0.18  $    0.42
      - diluted                   $   (0.02) $    0.10  $    0.18  $    0.40
    -------------------------------------------------------------------------

    REVENUE

    -------------------------------------------------------------------------
                            Three Months Ended          Nine Months Ended
                                Sept. 30                    Sept. 30
                         2007       2006   Change    2007       2006   Change
    -------------------------------------------------------------------------
    Average production
      Natural gas
       (mmcf/d)             135        142   -5%        138        140   -1%
      Liquids (light
       oil & ngls)
       (bbls/d)           7,954      9,249  -14%      7,958      9,825  -19%
    -------------------------------------------------------------------------
      Total (boe/d)      30,440     32,843   -7%     30,881     33,168   -7%

    Benchmark prices
      AECO ($/GJ)
        Monthly index $    5.32  $    5.72   -7%  $    6.43  $    6.82   -6%
        Daily index   $    5.16  $    5.35   -4%  $    6.52  $    6.07    7%
      WTI (U.S.$/bbl) $   75.38  $   70.48    7%  $   66.18  $   68.22   -3%
      Edmonton Par
       ($/bbl)        $   79.59  $   79.08    1%  $   72.87  $   75.53   -3%

    Realized prices
      Natural gas
       ($/mcf)        $    5.23  $    5.38   -3%  $    6.47  $    6.27    3%
      Liquids ($/bbl)     61.91      64.58   -4%      59.15      61.72   -4%
    -------------------------------------------------------------------------
      Total ($/boe)   $   38.56  $   42.03   -8%  $   44.48  $   45.34   -2%

    Revenue ($000s)
      Natural gas     $  64,891  $  70,059   -7%  $ 243,082  $ 239,712    1%
      Crude oil
       and ngls          43,089     56,932  -24%    131,946    170,836  -22%
    -------------------------------------------------------------------------
      Total           $ 107,980  $ 126,991  -15%  $ 375,028  $ 410,548   -9%
    -------------------------------------------------------------------------
    

    Production for the three and nine months ended September 30, 2007
decreased seven percent from comparable periods in 2006. However, on a quarter
over quarter basis, our production has increased by five percent from
28,918 boe/d to 30,440 boe/d.
    Total revenue for the third quarter of 2007 decreased from the
comparative period in 2006 as the result of lower realized prices and lower
year over year liquids volumes. Revenue declined 14% from the second quarter
of 2007 primarily as the result of lower natural gas prices.
    We market our natural gas through a combination of daily and monthly
indexed contracts and aggregator contracts. Approximately 10% of our natural
gas production remains committed to aggregator contracts, which realized a
price during the current quarter that was, on average, $0.70/mcf less than
prices received on non-aggregator volumes.

    
    ROYALTIES

    -------------------------------------------------------------------------
                                       Three Months          Nine Months
                                      Ended Sept. 30        Ended Sept. 30
                                     2007       2006       2007       2006
    -------------------------------------------------------------------------
    Royalties ($000s)             $  24,108  $  28,464  $  76,061  $  94,495
    Percentage of revenues            22.3%      22.4%      20.3%      23.0%
    -------------------------------------------------------------------------

    The Alberta royalty structure is based upon commodity prices and well
productivity, with higher prices and well productivity attracting higher
royalty rates. Compton's royalty rate in the three months ended September 30,
2007 was consistent with the comparative period in 2006.

    OPERATING EXPENSES

    -------------------------------------------------------------------------
                                       Three Months          Nine Months
                                      Ended Sept. 30        Ended Sept. 30
                                     2007       2006       2007       2006
    -------------------------------------------------------------------------
    Operating expenses ($000s)    $  24,425  $  28,217  $  73,929  $  72,940
    Operating expenses per boe
     ($/boe)                      $    8.72  $    9.34  $    8.77  $    8.06
    -------------------------------------------------------------------------

    Operating expenses have remained relatively consistent during the year,
ranging from $8.68/boe in the first quarter to $8.92/boe in the second quarter
to $8.72/boe in this quarter. Third quarter 2006 operating expenses were
unusually high due to a one time plant equalization charge for 2004 and 2005.
This charge related to production volumes processed through a non-operated
facility.

    TRANSPORTATION EXPENSES

    -------------------------------------------------------------------------
                                       Three Months          Nine Months
                                      Ended Sept. 30        Ended Sept. 30
                                     2007       2006       2007       2006
    -------------------------------------------------------------------------
    Transportation expenses
     ($000s)                      $   4,227  $   3,150  $  10,961  $   9,350
    Transportation expenses
     per boe ($/boe)              $    1.51  $    1.04  $    1.30  $    1.03
    -------------------------------------------------------------------------

    The year over year increase in transportation expense results from
increased trucking charges relative to oil production from Cecil and Worsley.

    GENERAL AND ADMINISTRATIVE EXPENSES

    -------------------------------------------------------------------------
                                       Three Months          Nine Months
    ($000s, except                    Ended Sept. 30        Ended Sept. 30
     where noted)                    2007       2006       2007       2006
    -------------------------------------------------------------------------
    General and administrative
     expenses                     $  11,298  $   9,194  $  32,104  $  28,184
    Capitalized general and
     administrative expenses         (1,520)    (2,378)    (5,126)    (7,513)
    Operator recoveries                (676)      (664)    (2,244)    (1,862)
    -------------------------------------------------------------------------
    Total general and
     administrative expenses      $   9,102  $   6,152  $  24,734  $  18,809

    General and administrative
     expenses per boe ($/boe)     $    3.25  $    2.04  $    2.93  $    2.08
    -------------------------------------------------------------------------

    Employee costs associated with increased personnel levels, as well as a
general increase in salaries necessary to attract and retain qualified
personnel in a very competitive industry, were the main drivers behind higher
general and administrative expenses in the three and nine months ended
September 30, 2007, when compared to prior periods. Other increases included
insurance and costs associated with the current regulatory environment and
rent associated with increased office space.
    General and administrative expenses have remained consistent with the
second quarter of 2007.

    INTEREST AND FINANCE CHARGES

    -------------------------------------------------------------------------
                                       Three Months          Nine Months
    ($000s, except                    Ended Sept. 30        Ended Sept. 30
     where noted)                    2007       2006       2007       2006
    -------------------------------------------------------------------------
    Interest on bank debt, net    $   6,891  $   3,945  $  17,643  $   9,754
    Interest on senior notes          9,328      9,620     29,571     26,106
    -------------------------------------------------------------------------
    Interest charges              $  16,219  $  13,565  $  47,214  $  35,860
    Finance charges                   1,258        682      1,785      2,289
    -------------------------------------------------------------------------
    Total interest and finance
     charges                      $  17,477  $  14,247  $  48,999  $  38,149

    Total interest and finance
     charges per boe ($/boe)      $    6.24  $    4.72  $    5.81  $    4.21
    -------------------------------------------------------------------------

    Year over year interest costs have increased as a result of an overall
increase in corporate debt. However, interest on the Company's Senior Notes,
payable in U.S. dollars, has benefited from the strong Canadian dollar.

    DEPLETION AND DEPRECIATION

    -------------------------------------------------------------------------
                                       Three Months          Nine Months
                                      Ended Sept. 30        Ended Sept. 30
                                     2007       2006       2007       2006
    -------------------------------------------------------------------------
    Depletion and depreciation
     ($000s)                      $  33,168  $  36,746  $ 107,032  $ 106,021
    Depletion and depreciation
     per boe ($/boe)              $   11.84  $   12.16  $   12.70  $   11.71
    -------------------------------------------------------------------------
    

    Depletion and depreciation on a unit of production basis has been
trending upward for the past six quarters ended June 30, 2007. This trend is
reflective of higher industry cost structures and corresponding higher finding
and development costs. In recent months, we have experienced significant
reductions in specific service costs that are beginning to show a curtailment
of this trend.

    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.

    
    CAPITAL EXPENDITURES

    -------------------------------------------------------------------------
    Nine Months Ended Sept. 30
     ($000s)                         2007            %     2006            %
    -------------------------------------------------------------------------
    Land and seismic              $  37,133         14  $  44,524         11
    Drilling and completions        155,482         58    237,034         59
    Production facilities            76,826         28    121,213         30
    -------------------------------------------------------------------------
    Sub-total, before under noted $ 269,441        100  $ 402,771        100
    Property acquisitions (net)    (205,610)               30,791
    -------------------------------------------------------------------------
    Sub-total                     $  63,831             $ 433,562
    MPP                               4,271                  (229)
    -------------------------------------------------------------------------
    Total capital expenditures    $  68,102             $ 433,333
    -------------------------------------------------------------------------
    

    Capital expenditures before acquisitions and divestitures in 2007 have
decreased from the comparable period in 2006, reflecting an over all reduction
in year over year activity, particularly drilling during the first half of
2007. Although we drilled 130 wells this quarter, versus 93 wells in the third
quarter of 2006, we have drilled fewer wells for the nine months ended
September 30, 2007 when compared to the same time period in 2006. This is
largely due to our reduced drilling during the second quarter of 2007,
occurring as a result of poor weather conditions during May and June of this
year.
    In years past, higher capital expenditures on production facilities
occurred to build up the infrastructure required to fully exploit our resource
play assets. While resource plays do by nature require extensive
infrastructure, particularly in the areas of low pressure pipelines and
compression, we do anticipate that going forward our facilities expenditures
will be slightly lower than historical numbers. Facilities expenditures
comprised 28% of total capital expenditures for the nine months ended
September 30, 2007 as compared to 30% of expenditures for the same period in
2006.
    As is consistent with our Company's overall strategy, during the nine
months ending September 30, 2007 we expanded in our core areas through a
number of acquisitions and divested of a number of non-core properties to
assist in these acquisitions as well as to fund ongoing activities. A summary
of expenditures relating to acquisitions and proceeds on the divestment during
the period is presented below.

    
    -------------------------------------------------------------------------
    Acquisitions, Nine months ended September 30, 2007
      Stylus Energy Inc.                                           $  91,944
      Miscellaneous property acquisitions, net of
       closing adjustments                                             8,042
    -------------------------------------------------------------------------
                                                                   $  99,986

    Divestments, net of closing adjustments
      Worsley property                                             $ 260,773
      Nevis, Pouce Coupe operations                                   44,823
    -------------------------------------------------------------------------
                                                                   $ 305,596

    Acquisitions (Divestments), net                                $(205,610)
    -------------------------------------------------------------------------
    

    The foregoing summary does not include fair value adjustments relating to
the Stylus Energy Inc. corporate acquisition also included in property and
equipment as presented in Note 3 to the financial statements. Closing
adjustments relating to the Worsley divestment are included in the above.
    The acquisition of Stylus Energy Inc. closed on August 15, 2007 and the
Worsley asset divestiture closed September 27, 2007 with an effective date of
July 1, 2007.
    Consistent with our strategy of adding to our focus areas of operations,
on November 1, 2007 we closed a minor property acquisition in the Long Coulee
area of southern Alberta for $33 million. Strategically this acquisition
enhances our existing Long Coulee operations by accelerating the pace at which
we can develop our adjacent acreage through utilization of pipeline,
processing facilities, and proprietary 3D seismic data included in the
acquisition. In summary, the acquisition includes:

    
    -   20 producing wells,
    -   5 proven undeveloped and 7 probable locations,
    -   production of 955 boe/d,
    -   5.6 bcfe proved and 9 bcfe proved and probable reserves,
    -   24 net sections of undeveloped land,
    -   53 square miles of 3D proprietary seismic, and
    -   50.4 km of pipelines and 12.5 mmcf/d plant capacity.
    

    We have valued the land and seismic at $5.4 million and the facilities at
$1 million. On this basis the acquisition equates to $27,853 per boe/d of
production and $17.67 per boe proved and probable reserves. The 3D seismic
base includes approximately 10 sections of existing Compton lands.

    RISK MANAGEMENT

    Our financial results are impacted by external market risks associated
with fluctuations in commodity prices, interest rates, and the Canadian/U.S.
currency exchange rate. We use various financial instruments for non-trading
purposes to manage and partially mitigate our exposure to these risks.
    Financial instruments used 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 risk management gain or loss
at the time of settlement. The mark-to-market value of an instrument
outstanding at the end of a reporting period reflects the value of the
instrument based upon market conditions existing as of that date. Any change
in value from that determined at the end of the prior period is recognized as
an unrealized risk management gain or loss.
    Risk management gains and losses recognized in the quarter are summarized
in the following table.

    
    Risk Management (Gains) Losses
    -------------------------------------------------------------------------
                                       Three Months          Nine Months
                                      Ended Sept. 30        Ended Sept. 30
    ($000s)                          2007       2006       2007       2006
    -------------------------------------------------------------------------
    Commodity contracts
      Realized                    $  (5,701) $ (12,991) $ (17,484) $ (24,744)
      Unrealized                      4,296    (16,581)    17,749    (34,810)
    Cross currency interest
     rate swap
      Realized                            -          -      2,899      1,733
      Unrealized                        436     (3,758)     4,394      1,964
    Foreign currency contracts
      Realized                            -       (542)       173     (1,087)
      Unrealized loss                   114        665        114       (749)
    -------------------------------------------------------------------------
    Total risk management         $    (855) $ (33,207) $   7,845  $ (57,693)
    -------------------------------------------------------------------------

    Realized                      $  (5,701) $ (13,533) $ (14,412) $ (24,098)
    Unrealized                        4,846    (19,674)    22,257    (33,595)
    -------------------------------------------------------------------------
    Total risk management         $    (855) $ (33,207) $   7,845  $ (57,693)
    -------------------------------------------------------------------------

    Outstanding Commodity Contracts

    Approximately 14% of current production is hedged for the balance of 2007.
As natural gas prices begin to recover, we will layer in hedge contracts
relating to 2008 production. We plan to continue to expand this program with a
goal of hedging approximately 50% of future production.
    The following table outlines commodity hedge contracts which were in place
during the third quarter of 2007 and/or are currently in place.

    -------------------------------------------------------------------------
    Commodity             Term              Amount     Average Price   Index
    -------------------------------------------------------------------------
    Natural gas
      Collar     April 2007 - Oct. 2007   45,000 GJ/d   $6.61 - $8.71   AECO
      Collar     Nov. 2007 - March 2008   10,000 GJ/d  $7.88 - $10.00   AECO

    Crude oil
      Collar      Jan. 2007 - Dec. 2007  3,000 bbls/d    U.S.$75.00 -    WTI
                                                             $84.55
    -------------------------------------------------------------------------


    LIQUIDITY AND CAPITAL RE

SOURCES ------------------------------------------------------------------------- ($000s, except where noted) As at As at Sept. 30, Dec. 31, 2007 2006 ------------------------------------------------------------------------- Working capital deficiency(1) $ 46,196 $ 23,163 Senior secured credit facilities 224,105 328,000 Senior term notes 437,004 524,385 ------------------------------------------------------------------------- Total indebtedness $ 707,305 $ 875,548 Shareholders' equity $ 818,585 $ 734,124 Debt to cash flow from operations(2) 3.4 3.4 Debt to book capitalization 36% 54% Debt to market capitalization 52% 39% ------------------------------------------------------------------------- (1) Excludes unrealized risk management items net of related future income taxes. (2) Based on trailing 12 month cash flow from operations. Our total corporate debt as at September 30, 2007 has been reduced by $181 million from December 31, 2006. The syndicated credit facility has been reduced by $105 million as a result of proceeds from property divestments and the Canadian dollar value of our US$ denominated senior notes has decreased by $76 million as a result of the strengthening of the Canadian dollar against that of the US dollar. Subsequent to quarter end, Compton entered into foreign currency exchange contracts related to our $450 million of US 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 US, has resulted in the Company recognizing an unrealized foreign exchange gain in relation to the US dollar denominated notes. On October 26 and 31, 2007 we entered into foreign exchange forward contracts to purchase US$450 million for C$436 million, effectively crystallizing a total foreign exchange gain of approximately $91.7 million. The foreign exchange contract effectively fixes the Canadian dollar amount on the Senior Notes at $436 million as outlined in Note 17 to the financial statements. Our corporate debt is structured to provide Compton with financial flexibility. Sixty-seven percent of our existing debt 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 2007 capital program. Our authorized syndicated credit facility remains at $500 million. The facility is a borrowing based facility and, reflective of the quality of our assets, has not been reduced as a result of the Worsley divestment. We have drawn $245 million on the facility as at October 31, 2007. We believe internally generated cash flow from operations, proceeds from property dispositions, and funds available through our renewed credit facilities will be more than sufficient to fund the balance of our planned 2007 capital program, while still maintaining an appropriate capital structure. We have reviewed the sale of Cecil in light of the recent announced royalty changes, and we believe these changes will have minimal impact on the value of this asset. We expect to close a divestiture transaction by year end or early in the new year. In addition to the Cecil divestment we are proceeding with two additional dispositions that are expected to yield approximately $40 to $50 million in proceeds. OUTLOOK We have continued to execute on our business plan and are satisfied with our progress to date. Our plans, as set out in July 2007, anticipated a strengthening of natural gas prices. Although we remain bullish on the longer-term outlook for natural gas, the current protracted weakness in prices has negatively affected returns. This is particularly the case with our lower productivity shallow Belly River play. As a result, we are taking a more prudent approach to our drilling program for the fourth quarter of the year. We are reducing our drilling program by approximately 75 wells, 70% of which are Plains Belly River wells. While this is a very promising development area for the Company with years of low cost, low risk drilling opportunities, it offers only marginal returns at current prices. During the fourth quarter of 2007, we will focus on very low risk, higher productivity development wells in areas where returns are the most favourable. Additionally, building on recent success, we plan to expand our horizontal drilling plans at Niton and Hooker which will replace a number of vertical wells with fewer horizontal wells. Our revised plans will result in total expenditures for the year, before acquisitions and divestments, being reduced to $375 million from $450 million, as previously announced in our November 1 Operational Update press release. Importantly, our focus on higher productivity drilling and the tie-in of behind pipe production should enable us to meet our December 2007 exit guidance rate of 36,000 to 37,000 boe/d. This exit guidance rate does not include production from our conventional light oil asset, Cecil, which we are in the process of selling. The exit number does include production from the recent property acquisition in the Long Coulee area of southern Alberta, as discussed in the capital expenditures section. Our revised drilling program will allow us to move forward with the development of our resource plays and position Compton for the future, while concurrently protecting the Company's balance sheet. We are focused on developing our resource base in a manner that will position Compton for the future and allow us to capitalize on higher natural gas prices when this commodity market recovers. Changes in Internal Control over Financial Reporting There were no changes during the quarter ended September 30, 2007 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. QUARTERLY INFORMATION The following table sets forth certain quarterly financial information of the Company for the eight most recent quarters. ------------------------------------------------------------------------- 2007 2006 Q3 Q2 Q1 Q4 ------------------------------------------------------------------------- Total revenue (millions) $ 108 $ 126 $ 141 $ 130 Cash flow from operations (millions) $ 33 $ 45 $ 69 $ 55 Per share - basic $ 0.26 $ 0.35 $ 0.53 $ 0.43 - diluted $ 0.25 $ 0.34 $ 0.52 $ 0.42 Net earnings (millions) $ 19 $ 45 $ 14 $ (10) Per share - basic $ 0.15 $ 0.35 $ 0.11 $ (0.08) - diluted $ 0.15 $ 0.34 $ 0.10 $ (0.08) Operating earnings (millions) $ (2) $ 7 $ 18 $ 12 Production Natural gas (mmcf/d) 135 130 148 148 Liquids (bbls/d) 7,954 7,199 8,729 8,600 ------------------------------------------------------------------------- Total (boe/d) 30,440 28,918 33,316 33,245 Average price Natural gas (mmcf/d) $ 5.23 $ 6.92 $ 7.24 $ 6.48 Liquids (bbls/d) $ 61.91 60.49 54.20 48.44 ------------------------------------------------------------------------- Total ($/boe) $ 38.56 $ 47.94 $ 46.98 $ 42.60 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 2006 2005 Q3 Q2 Q1 Q4 ------------------------------------------------------------------------- Total revenue (millions) $ 127 $ 135 $ 149 $ 185 Cash flow from operations (millions) $ 60 $ 67 $ 74 $ 90 Per share - basic $ 0.47 $ 0.53 $ 0.58 $ 0.71 - diluted $ 0.45 $ 0.50 $ 0.55 $ 0.67 Net earnings (millions) $ 31 $ 69 $ 38 $ 38 Per share - basic $ 0.24 $ 0.54 $ 0.30 $ 0.30 - diluted $ 0.23 $ 0.51 $ 0.28 $ 0.28 Operating earnings (millions) $ 13 $ 18 $ 22 $ 33 Production Natural gas (mmcf/d) 142 137 142 133 Liquids (bbls/d) 9,249 9,821 10,418 8,879 ------------------------------------------------------------------------- Total (boe/d) 32,843 32,645 34,029 31,042 Average price Natural gas (mmcf/d) $ 5.38 $ 5.86 $ 7.58 $ 11.12 Liquids (bbls/d) 57.53 67.09 48.70 58.39 ------------------------------------------------------------------------- Total ($/boe) $ 42.03 $ 45.37 $ 48.58 $ 64.86 ------------------------------------------------------------------------- Revenue and cash flow for the third quarter of 2007 decreased relative to the second quarter of 2007 due to lower natural gas prices. Production grew by five percent on a quarter over quarter basis. In the second quarter of 2007, revenue declined slightly due to reduced production. Net earnings, however, increased compared to the first quarter of 2007, largely due to an unrealized foreign exchange gain. In the first quarter of 2007, revenue and cash flow from operations increased from the fourth quarter of 2006 due primarily to higher commodity prices. On a quarter over quarter basis, net earnings increased significantly as fourth quarter of 2006 net earnings were negatively impacted by the reversal of unrealized foreign exchange gains recorded in prior quarters as a result of the weakening Canadian dollar relative to the U.S. dollar. ADVISORIES Management's Discussion and Analysis ("MD&A") is intended to provide both an historical and prospective view of the Company's activities. The MD&A was prepared as at November 9, 2007 and should be read in conjunction with the interim unaudited consolidated financial statements for the nine months ended September 30, 2007 and the audited consolidated financial statements and MD&A for the year ended December 31, 2006, available in printed form on request and posted on the Company's website. Forward Looking Statements Certain information regarding the Company contained herein constitutes forward looking statements under the meaning of applicable securities laws, including 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, production, capital expenditures, and planned wells in 2007, and (ii) 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 expectations reflected in such forward looking statements are reasonable, it can give no assurance that such 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 Compton'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 and mechanical failures, uncertainties in the estimates of reserves and in projections of future rates of production and timing of development expenditures, general economic conditions, the actions or inactions of third party operators and regulatory pronouncements. Compton may, as considered necessary in the circumstances, update or revise forward looking information, whether as a result of new information, future events, or otherwise. Compton'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 terms used in the oil and gas industry such as cash flow from operations, cash flow per share and operating earnings. These terms are not defined by GAAP in Canada and consequently are referred to as non-GAAP measures. Non-GAAP measures do not have any standardized meaning and therefore reported amounts may not be comparable to similarly titled measures reported by other companies. 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 the Company's performance or liquidity. Cash flow from operations is used by Compton to evaluate operating results and the Company's ability to generate cash to fund capital expenditures and repay debt. Operating earnings 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. Operating earnings is used by the Company 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. Compton has used the 6:1 boe measure which is the approximate energy equivalency of the two commodities at the burner tip. However, boe does not represent a value equivalency at the plant gate where Compton sells its production volumes and therefore may be a misleading measure if used in isolation. Compton is an independent, public company actively engaged in the exploration, development, and production of natural gas, natural gas liquids, and crude oil in Western Canada. Compton also controls and manages the operations of the Mazeppa Processing Partnership ("MPP"), which owns significant midstream assets critical to the Company's activities in Southern Alberta. The accounts of MPP are consolidated in the Company's financial statements. ------------------------------------------------------------------------- Compton Petroleum Corporation Consolidated Balance Sheets (thousands of dollars) ------------------------------------------------------------------------- September 30, December 31, 2007 2006 ------------- ------------- (unaudited) Assets Current Cash $ 10,004 $ 11,876 Accounts receivable and other 70,371 83,535 Other current assets 25,247 22,869 Unrealized risk management gain (Note 13a) 4,875 22,625 Future income taxes 2,585 1,479 ------------- ------------- 113,082 142,384 Property and equipment 1,950,837 1,977,062 Goodwill 9,626 7,914 Deferred financing charges and other (Note 15) 236 14,144 Deferred risk management loss (Note 13c) - 3,968 ------------- ------------- $ 2,073,781 $ 2,145,472 ------------- ------------- ------------- ------------- Liabilities Current Accounts payable $ 151,818 $ 141,443 Unrealized risk management loss (Note 13d) 8,474 4,604 Future income taxes 1,487 7,269 ------------- ------------- 161,779 153,316 Bank debt (Note 4) 224,105 328,000 Senior term notes (Note 5) 437,004 524,385 Asset retirement obligations (Note 7) 34,380 29,791 Unrealized risk management loss (Note 13d) 7,454 6,816 Future income taxes 326,293 302,690 Non-controlling interest (Note 8) 64,181 66,350 ------------- ------------- 1,255,196 1,411,348 ------------- ------------- Shareholders' equity Capital stock (Note 9) 235,323 231,992 Contributed surplus (Note 10a) 22,798 16,974 Retained earnings 560,464 485,158 ------------- ------------- 818,585 734,124 ------------- ------------- $ 2,073,781 $ 2,145,472 ------------- ------------- ------------- ------------- See accompanying notes to the consolidated financial statements. ------------------------------------------------------------------------- Compton Petroleum Corporation Consolidated Statements of Earnings (unaudited) (thousands of dollars, except per share amounts) ------------------------------------------------------------------------- Three months ended Nine months ended September 30, September 30, ----------------------- ----------------------- 2007 2006 2007 2006 ----------- ----------- ----------- ----------- Revenue Oil and natural gas revenues $ 107,980 $ 126,991 $ 375,028 $ 410,548 Royalties (24,108) (28,464) (76,061) (94,495) ----------- ----------- ----------- ----------- 83,872 98,527 298,967 316,053 ----------- ----------- ----------- ----------- Expenses Operating 24,425 28,217 73,929 72,940 Transportation 4,227 3,150 10,961 9,350 General and administrative 9,102 6,152 24,734 18,809 Interest and finance charges (Note 6) 17,477 14,247 48,999 38,149 Depletion and depreciation 33,168 36,746 107,032 106,021 Foreign exchange (gain) loss (Note 14) (30,044) 102 (75,257) (23,599) Accretion of asset retirement obligations 686 597 1,949 1,625 Stock-based compensation 2,150 2,184 9,398 6,872 Risk management (gain) loss (Note 13e) (855) (33,207) 7,845 (57,693) ----------- ----------- ----------- ----------- 60,336 58,188 209,590 172,474 ----------- ----------- ----------- ----------- Earnings before taxes and non-controlling interest 23,536 40,339 89,377 143,579 ----------- ----------- ----------- ----------- Income taxes (Note 12) Current 11 11 8 23 Future 2,608 8,430 5,837 1,894 ----------- ----------- ----------- ----------- 2,619 8,441 5,845 1,917 ----------- ----------- ----------- ----------- Earnings before non- controlling interest 20,917 31,898 83,532 141,662 Non-controlling interest 1,135 1,181 4,724 4,199 ----------- ----------- ----------- ----------- Net earnings $ 19,782 $ 30,717 $ 78,808 $ 137,463 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- Net earnings per share (Note 11) Basic $ 0.15 $ 0.24 $ 0.61 $ 1.08 ----------- ----------- ----------- ---------- ----------- ----------- ----------- ----------- Diluted $ 0.15 $ 0.23 $ 0.59 $ 1.03 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ------------------------------------------------------------------------- Compton Petroleum Corporation Consolidated Statements of Retained Earnings (unaudited) (thousands of dollars) ------------------------------------------------------------------------- Three months ended Nine months ended September 30, September 30, ----------------------- ----------------------- 2007 2006 2007 2006 ----------- ----------- ----------- ----------- Retained earnings, beginning of period As previously reported $ 541,082 $ 465,501 $ 485,158 $ 360,719 Accounting policy adjustments (Note 2) - - (1,320) - ----------- ----------- ----------- ----------- As restated 541,082 465,501 483,838 360,719 Net earnings 19,782 30,717 78,808 137,463 Premium on redemption of shares (Note 9) (400) (491) (2,182) (2,455) ----------- ----------- ----------- ----------- Retained earnings, end of period $ 560,464 $ 495,727 $ 560,464 $ 495,727 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- See accompanying notes to the consolidated financial statements. ------------------------------------------------------------------------- Compton Petroleum Corporation Consolidated Statements of Cash Flow (unaudited) (thousands of dollars) ------------------------------------------------------------------------- Three months ended Nine months ended September 30, September 30, ----------------------- ----------------------- 2007 2006 2007 2006 ----------- ----------- ----------- ----------- Operating activities Net earnings $ 19,782 $ 30,717 $ 78,808 $ 137,463 Amortization and other 1,098 498 3,024 1,595 Depletion and depreciation 33,168 36,746 107,032 106,021 Accretion of asset retirement obligations 686 597 1,949 1,625 Unrealized foreign exchange (gain) loss (30,195) 127 (76,050) (23,165) Future income taxes 2,608 8,430 5,837 1,894 Unrealized risk management (gain) loss 4,846 (19,674) 22,257 (33,595) Stock-based compensation 2,151 2,184 6,780 6,872 Asset retirement expenditures (2,146) (686) (3,863) (1,867) Non-controlling interest 1,135 1,181 4,724 4,199 ----------- ----------- ----------- ----------- 33,133 60,120 150,498 201,042 Change in non-cash working capital (12,510) 10,353 (14,165) 5,184 ----------- ----------- ----------- ----------- 20,623 70,473 136,333 206,226 ----------- ----------- ----------- ----------- Financing activities Issuance (repayment) of bank debt (144,509) 45,000 (103,894) 102,100 Proceeds from share issuances 195 1,667 2,797 4,074 Distributions to partner (2,307) (2,292) (6,893) (6,878) Redemption of common shares (484) (571) (2,603) (2,798) Issue costs on senior notes - - - (3,408) Issuance of senior notes - - - 174,930 Redemption of senior notes - - - (7,520) ----------- ----------- ----------- ----------- (147,105) 43,804 (110,593) 260,500 ----------- ----------- ----------- ----------- Investing activities Property and equipment additions (113,824) (142,480) (269,849) (401,976) Corporate acquisitions (Note 3) (74,965) - (74,965) - Property acquisitions (7,450) (700) (8,042) (30,891) Property dispositions 259,763 - 305,596 1,400 Change in non-cash working capital 58,683 34,243 19,648 (22,217) ----------- ----------- ----------- ----------- 122,207 (108,937) (27,612) (453,684) ----------- ----------- ----------- ----------- Change in cash (4,275) 5,340 (1,872) 13,042 Cash, beginning of period 14,279 16,656 11,876 8,954 ----------- ----------- ----------- ----------- Cash, end of period $ 10,004 $ 21,996 $ 10,004 $ 21,996 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- See accompanying notes to the consolidated financial statements. ------------------------------------------------------------------------- Compton Petroleum Corporation Notes to the Consolidated Financial Statements (unaudited) (Tabular amounts in thousands of dollars, unless otherwise stated) September 30, 2007 ------------------------------------------------------------------------- 1. Basis of presentation Compton Petroleum Corporation (the "Company") explores for and produces petroleum and natural gas reserves in the Western Canadian Sedimentary Basin. These 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 8. These consolidated interim financial statements have been prepared by Management in accordance with accounting principles generally accepted in Canada. Certain information and disclosure normally required to be included in notes to annual consolidated financial statements have been condensed or omitted. The consolidated interim financial statements should be read in conjunction with the audited consolidated financial statements and the notes thereto contained in the Company's annual report for the year ended December 31, 2006. The consolidated interim financial statements have been prepared following the same accounting policies and methods of computation as the audited consolidated financial statements for the year ended December 31, 2006 except as disclosed in Note 2 below. All amounts are presented in Canadian dollars unless otherwise stated. 2. Changes in accounting policies and procedures On January 1, 2007, the Company adopted the Canadian Institute of Chartered Accountants ("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 significant impact on the Company's net earnings or cash flows. The impact of the new standards are: 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 had no other comprehensive income nor accumulated other comprehensive income for the nine month period ended September 30, 2007. b) Financial instruments The financial instruments standard establishes recognition and measurement criteria for financial assets, financial liabilities and derivatives. All financial instruments are required to be 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 standard. 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 assets "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". Transitional provisions are outlined in the financial instrument standard and require retroactive adjustment without restatement of prior periods. In addition, the provisions require that, upon adoption at January 1, 2007, transitional adjustments, net of tax, are recognized in the opening balance of retained earnings. At January 1, 2007, the following transitional adjustments were required. - $14.0 million of deferred financing charges were reclassified 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. 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) January 1, 2007 fair value of investments 1,105 ------------ Total adjustment to opening retained earnings $ (1,320) ------------ ------------ c) Hedges At January 1, 2007, the Company did not designate any of its risk management activities as accounting hedges and as a result, the adoption of this standard had no impact on the current period consolidated financial statements. d) Accounting changes The adoption of Handbook Section 1506, "Accounting Changes" has had no impact on the September 30, 2007 consolidated financial statements. 3. Acquisition On August 15, 2007, the Company acquired 100 percent of the issued and outstanding shares of Stylus Energy Inc. ("Stylus"), a public company involved in the exploration, development and production of oil and natural gas primarily in southern Alberta. The acquisition has been accounted for by the purchase method of accounting and the consolidated financial statements include the results of operations from date of acquisition. 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 values and therefore, the allocation of the purchase price is subject to refinement. Net assets acquired Working capital $ (16,981) Petroleum and natural gas properties 107,282 ------------ $ 90,301 Future income taxes (11,775) Asset retirement obligations (5,274) Goodwill 1,713 ------------ $ 74,965 ------------ ------------ Consideration Cash $ 73,782 Transaction costs 1,183 ------------ $ 74,965 ------------ ------------ 4. Credit facilities September 30, December 31, 2007 2006 ------------- ------------- Authorized $ 500,000 $ 500,000 ------------- ------------- ------------- ------------- Prime rate $ 25,000 $ 35,000 Bankers' acceptance 200,000 295,000 Discount to maturity (895) (2,000) ------------- ------------- Utilized $ 224,105 $ 328,000 ------------- ------------- ------------- ------------- As at September 30, 2007, the Company had arranged authorized senior credit facilities with a syndicate of banks in the amount of $500 million. 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% 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. 5. Senior term notes September 30, December 31, 2007 2006 ------------- ------------- Senior term notes U.S.$450 million, 7.625% due December 1, 2013 $ 448,335 $ 524,385 Unamortized transaction costs (11,331) - ------------- ------------- Carrying value $ 437,004 $ 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% and are subordinate to the Company's bank credit facilities. The yield to maturity, using the effective interest rate, was 8.15% as at September 30, 2007. 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% Pursuant to the adoption of Handbook Section 3861, "Financial Instruments - Disclosure and Presentation", transaction costs relating to the issue of the senior term notes reduce the face value of the notes as discussed in Note 2. 6. Interest and finance charges Amounts charged to interest expense during the period ended are: Three months ended Nine months ended September 30, September 30, ----------------------- ----------------------- 2007 2006 2007 2006 ----------- ----------- ----------- ----------- Interest on bank debt $ 6,891 $ 3,945 $ 17,643 $ 9,754 Interest on senior term notes 9,328 9,620 29,571 26,106 Finance charges 1,258 682 1,785 2,289 ----------- ----------- ----------- ----------- $ 17,477 $ 14,247 $ 48,999 $ 38,149 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- Finance charges include other interest expense net of interest revenue from cash management activities. 7. Asset retirement obligations The following table presents a reconciliation of the beginning and ending aggregate carrying amount of the obligations associated with the retirement of oil and gas assets: September 30, December 31, 2007 2006 ------------- ------------- Asset retirement obligations, beginning of period $ 29,791 $ 20,770 Liabilities incurred 7,028 7,031 Liabilities settled and disposed (4,388) (267) Accretion expense 1,949 2,257 ------------- ------------- Asset retirement obligations, end of period $ 34,380 $ 29,791 ------------- ------------- ------------- ------------- 8. 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: September 30, December 31, 2007 2006 ------------- ------------- Non-controlling interest, beginning of period $ 66,350 $ 68,898 Earnings attributable to non-controlling interest 4,724 6,623 Distributions to limited partner (6,893) (9,171) ------------- ------------- Non-controlling interest, end of period $ 64,181 $ 66,350 ------------- ------------- ------------- ------------- 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 processing agreement has a five year term ending April 1, 2009, at which time Compton may renew the agreement, purchase the Partnership units or allow the sale of the Partnership units to a third party. The maximum liability at September 30, 2007 is $14.5 million. The Company has determined that its exposure to loss under these arrangements is minimal, if any. 9. Capital stock Issued and outstanding September 30, 2007 December 31, 2006 ----------------------- ----------------------- Number of Number of shares Amount shares Amount ----------- ----------- ----------- ----------- (000s) (000s) Common shares outstanding, beginning of period 128,503 $ 231,992 127,263 $ 226,444 Shares issued under stock option plan 869 3,753 1,489 5,993 Shares repurchased (233) (422) (249) (445) ----------- ----------- ----------- ----------- Common shares outstanding, end of period 129,139 $ 235,323 128,503 $ 231,992 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- The Company maintains a Normal Course Issuer Bid program on an annual basis. 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 nine months ended September 30, 2007, the Company purchased for cancellation 232,600 common shares at an average price of $11.19 per share (December 31, 2006 - 248,900 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. 10. 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 will expire five years after the grant date. The following tables summarize the information relating to stock options: September 30, 2007 December 31, 2006 ----------------------- ----------------------- Weighted Weighted average average Stock exercise Stock exercise Options price options price ----------- ----------- ----------- ----------- (000s) (000s) Outstanding, beginning of period 11,611 $7.79 11,446 $6.13 Granted 1,800 $11.39 2,228 $13.99 Exercised (869) $3.22 (1,489) $3.14 Forfeited (446) $11.95 (574) $10.92 ----------- ----------- ----------- ----------- Outstanding, end of period 12,096 $8.50 11,611 $7.79 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- Exercisable, end of period 7,308 $6.21 6,593 $4.82 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- The range of exercise prices of stock options outstanding and exercisable at September 30, 2007 is as follows: Outstanding Options Exercisable Options ---------------------------------- ------------------------ Weighted average Weighted Weighted Range of Number of remaining average Number of average exercise options contractual exercise options exercise prices outstanding life (years) price outstanding price ------------------------ ----------- ----------- ----------- ------------ (000s) (000s) $1.45 - $3.99 2,665 2.9 $2.72 2,665 $2.72 $4.00 - $6.99 2,108 3.0 $4.92 2,029 $4.89 $7.00 - $9.99 1,325 2.0 $7.86 898 $7.59 $10.00 - $11.99 2,779 3.7 $11.20 608 $10.95 $12.00 - $13.99 1,785 3.0 $12.65 739 $12.61 $14.00 - $18.39 1,434 3.4 $14.69 369 $14.69 ----------- ----------- ----------- ----------- ------------ 12,096 3.1 $8.50 7,308 $6.21 ----------- ----------- ----------- ----------- ------------ ----------- ----------- ----------- ----------- ------------ The Company has recorded stock-based compensation expense in the consolidated statements of earnings 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: Three months ended Nine months ended September 30, September 30, ----------------------- ----------------------- 2007 2006 2007 2006 ----------- ----------- ----------- ----------- Weighted average fair value of options granted $4.14 $5.44 $4.35 $7.11 Risk-free interest rate 4.4% 4.1% 4.1% 4.1% Expected life (years) 5.0 5.0 5.0 5.0 Expected volatility 38.6% 42.8% 39.2% 43.8% The following table presents the reconciliation of contributed surplus with respect to stock-based compensation: September 30, December 31, 2007 2006 ------------- ------------- Contributed surplus, beginning of year $ 16,974 $ 9,173 Stock-based compensation 6,780 9,121 Stock options exercised (956) (1,320) ------------- ------------- Contributed surplus, end of period $ 22,798 $ 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 periods ended September 30, 2007 and 2006, 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 $1.1 million, which is included in accounts payable as at September 30, 2007 (December 31, 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 currently exists within the industry, the Company implemented an Employee Retention program in July 2006 for its existing employees, excluding Officers and Directors. Under the program, the Company incurred additional compensation costs of $4.0 million of which $2.6 million was recognized during 2007. 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. 11. Per share amounts The following table summarizes the common shares used in calculating net earnings per common share: Three months ended Nine months ended September 30, September 30, ----------------------- ----------------------- 2007 2006 2007 2006 ----------- ----------- ----------- ----------- (000s) (000s) (000s) (000s) Weighted average common shares outstanding - basic 129,131 127,947 128,952 127,660 Effect of stock options 3,376 5,384 3,797 6,240 ----------- ----------- ----------- ----------- Weighted average common shares outstanding - diluted 132,507 133,331 132,749 133,900 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- 12. Income taxes The following table reconciles income taxes calculated at the Canadian statutory rates with actual income taxes: Three months ended Nine months ended September 30, September 30, ----------------------- ----------------------- 2007 2006 2007 2006 ----------- ----------- ----------- ----------- Earnings before taxes and non-controlling interest $ 23,536 $ 40,339 $ 89,377 $ 143,579 ----------- ----------- ----------- ----------- Canadian statutory rate 32.1% 34.5% 32.1% 34.5% Expected income taxes $ 7,555 $ 13,917 $ 28,690 $ 49,534 Effect on taxes resulting from: Non-deductible crown charges - 384 - 946 Resource allowance - (455) - (661) Non-deductible stock- based compensation 691 753 2,178 2,371 Effect of tax rate changes (1,180) (6,214) (11,379) (47,445) Non-taxable capital (gains) losses (4,267) 24 (11,587) (3,993) Other (180) 32 (2,057) 1,165 ----------- ----------- ----------- ----------- Provision for income taxes $ 2,619 $ 8,441 $ 5,845 $ 1,917 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- Current $ 11 $ 11 $ 8 $ 23 Future 2,608 8,430 5,837 1,894 ----------- ----------- ----------- ----------- $ 2,619 $ 8,441 $ 5,845 $ 1,917 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- Effective tax rate 11.1% 20.9% 6.5% 1.3% ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- The Canadian federal government, during the second quarters of 2007 and 2006, and the Alberta government, during the second quarter of 2006 enacted income tax rate changes. 13. 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. Risk management activities during the period, utilizing derivative instruments, relate to commodity price hedges, foreign currency swaps and cross currency interest rate swap arrangements and are summarized below: a) Commodity price hedges The commodity hedge contracts entered into are forward transactions providing the Company with a range of prices on the commodities sold. Outstanding hedge contracts and the associated unrealized, mark-to- market, gains or losses, at September 30, 2007 are: Mark-to- Daily Market Notional Gain Commodity Term Volume Prices Received (Loss) --------- ---- -------- --------------- -------- Natural gas Apr. 07 - Collar Oct. 07 42,857 mcf $6.94/mcf - $9.14/mcf $ 2,269 Nov. 07 - Collar Mar. 08 9,524 mcf $8.27/mcf - $10.50/mcf 2,625 Crude oil Jan. 07 - Collar Dec. 07 3,000 bbls US$75.00/bbl - US$84.55/bbl (19) -------- Unrealized risk management gain $ 4,875 -------- -------- At December 31, 2006, the unrealized risk management gain on outstanding commodity contracts was $22.6 million. b) Foreign currency risk management The Company is exposed to fluctuations in the exchange rate between the Canadian dollar and U.S. dollar and when appropriate, enters into agreements to fix the exchange rate in order to manage the risk. Subsequent to September 30, 2007 the Company entered into agreements to fix the repayment, in Canadian dollars, of its US dollar denominated senior term notes as disclosed in note 17. c) Deferred risk management loss As at January 1, 2004, the Company recorded a liability and a deferred risk management loss of $10.9 million relating to then outstanding commodity hedges and the interest rate swap. The deferred loss was amortized to earnings until December 31, 2006. Upon adoption of Handbook Section 3855, "Financial Instruments - Recognition and Measurement" the balance of the deferred risk management loss, net of tax, was charged to opening retained earnings as at January 1, 2007. d) Cross currency interest rate swap In 2002, the Company entered into interest rate swap arrangements, expiring May 2009 that convert fixed rate U.S. dollar denominated interest obligations into floating rate Canadian dollar denominated interest obligations. At September 30, 2007, the Company valued the liability relating to unrealized losses on the swap arrangements to be $15.9 million (December 31, 2006 - $11.4 million) on a mark-to- market basis. The current portion of this amount at September 30, 2007 is $8.5 million (December 31, 2006 - $4.6 million). e) Risk management (gain) loss The following table summarizes (gains) and losses recognized during the year relating to the foregoing: Three months ended September 30, ------------------------------------------------------ Commodity Foreign Interest 2007 2006 Contracts Currency Rate Swap Total Total ---------- ---------- ---------- ---------- ---------- Unrealized Amortization of deferred loss $ - $ - $ - $ - $ 411 Change in fair value 4,296 114 436 4,846 (20,085) ---------- ---------- ---------- ---------- ---------- 4,296 114 436 4,846 (19,674) Realized Cash settlements (5,701) - - (5,701) (13,533) ---------- ---------- ---------- ---------- ---------- Total $ (1,405) $ 114 $ 436 $ (855) $ (33,207) ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- Nine months ended September 30, ------------------------------------------------------ Commodity Foreign Interest 2007 2006 Contracts Currency Rate Swap Total Total ---------- ---------- ---------- ---------- ---------- Unrealized Amortization of deferred loss $ - $ - $ - $ - $ 1,232 Change in fair value 17,749 114 4,394 22,257 (34,827) ---------- ---------- ---------- ---------- ---------- 17,749 114 4,394 22,257 (33,595) Realized Cash settlements (17,484) 173 2,899 (14,412) (24,098) ---------- ---------- ---------- ---------- ---------- Total $ 265 $ 287 $ 7,293 $ 7,845 $ (57,693) ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- 14. Foreign exchange (gain) loss Amounts charged to foreign exchange (gain) loss during the period ended were as follows: Three months ended Nine months ended September 30, September 30, ----------------------- ----------------------- 2007 2006 2007 2006 ----------- ----------- ----------- ----------- Foreign exchange on translation of U.S.$ debt $ (30,195) $ 127 $ (76,050) $ (23,165) Other foreign exchange 151 (25) 793 (434) ----------- ----------- ----------- ----------- Total $ (30,044) $ 102 $ (75,257) $ (23,599) ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- 15. Deferred financing charges and other September 30, December 31, 2007 2006 ------------- ------------- Deferred financing charges $ - $ 14,008 Other 236 136 ------------- ------------- $ 236 $ 14,144 ------------- ------------- ------------- ------------- At January 1, 2007, the balance in deferred financing charges has been re-classified as a reduction of senior term notes according to the new accounting standards outlined in Handbook Section 3855 "Financial Instruments - Recognition and Measurement" and discussed in Note 2. Prior periods have not been restated as permitted in the transitional provisions. 16. Supplemental cash flow information Amounts actually paid during the period relating to interest expense and capital taxes are as follows: Three months ended Nine months ended September 30, September 30, ----------------------- ----------------------- 2007 2006 2007 2006 ----------- ----------- ----------- ----------- Interest paid $ 7,334 $ 6,014 $ 38,320 $ 24,422 Taxes paid $ - $ - $ - $ 180 17. Subsequent events Subsequent to September 30, 2007 the Company entered into foreign exchange forward contracts with certain members of its banking syndicate, to purchase US$450 million for C$436 million. The contracts expire on December 1, 2010. 18. Reclassification Certain amounts disclosed for prior periods have been reclassified to conform with current period presentation. CONFERENCE CALL Compton will be conducting a conference call and audio webcast November 12, 2007 at 11:00 a.m. (MT) or 1:00 pm. (ET) to discuss the Company's 2007 third quarter financial and operating results. To participate in the conference call, please contact the Conference Operator at 11:20 a.m. (MT), ten minutes prior to the call. Conference Operator Dial-in Number: Toll-Free 1-800-733-7560 Local Toronto: 1-416-644-3415 Audio webcast URL: http://phx.corporate-ir.net/phoenix.zhtml?c=69018&p=irol-EventDetails&EventId= 1621617 The audio replay will be available two hours after the conclusion of the conference call and will be accessible until November 19, 2007. Callers may dial toll-free 877-289-8525 and enter access code 21250260 (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: Compton Petroleum Corporation, 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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