EXHIBIT 20.3
                                                                    ------------


MANAGEMENT'S DISCUSSION AND ANALYSIS

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 MARCH  15,  2006 AND  SHOULD BE READ IN  CONJUNCTION  WITH THE
AUDITED CONSOLIDATED FINANCIAL STATEMENTS AND RELATED NOTES FOR THE YEAR ENDED
DECEMBER 31, 2005. 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  19 TO THE  CONSOLIDATED
FINANCIAL STATEMENTS.

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.

CORPORATE OVERVIEW & STRATEGY

Compton  Petroleum  Corporation 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. The Company's activities
are concentrated in three core geographic areas,  primarily in Alberta, in the
Western  Canada  Sedimentary  Basin.  Compton's  growth and  reserve  base has
resulted   predominantly   from   exploration  and   development   activities,
complemented by strategic acquisitions.

Compton's  objective has been and remains that of building an exploration  and
development  company  capable of delivering and  sustaining  long term growth.
Management  has adhered to a consistent  strategy in pursuing this  objective.
Major components of Management's strategy currently include:

     o  concentrating activities in a limited number of core areas;
     o  focusing on unconventional natural gas in large resource plays;
     o  pursuing  growth through  the  drill  bit,  complemented  by  selective
        acquisitions;
     o  controlling infrastructure and operatorship; and
     o  maintaining financial flexibility.


RESULTS OF OPERATIONS

EXECUTIVE SUMMARY

o    Drilling  program  included 392 wells in 2005,  with a 96% success  rate,
     more than double the 186 wells drilled in 2004.
o    Annual  production  averaged  29,424  BOE/D, a 9% increase from the prior
     year.
o    Cash  flow  from  operations  increased  57% to  $278  million driven  by
     production growth and strong commodity prices.
o    Operating  earnings for the year rose 100% to $94 million.
o    Net earnings for the year increased 28% to $81 million.

                                     -1-
<PAGE>

CASH FLOW FROM OPERATIONS AND NET EARNINGS

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
Years ended December 31,                                                 2005          2004         2003
-----------------------------------------------------------------------------------------------------------
<S>                                                                  <C>           <C>           <C>
Cash flow from operations (1) ($000s)                                $ 278,112     $ 177,131     $ 154,893
Per share:  basic                                                    $    2.21     $    1.51     $    1.33
            diluted                                                  $    2.11     $    1.43     $    1.27
Net earnings ($000s)                                                 $  81,326     $  63,633     $ 118,880
Per share:  basic                                                    $    0.65     $    0.54     $    1.02
            diluted                                                  $    0.62     $    0.51     $    0.97
-----------------------------------------------------------------------------------------------------------
</TABLE>

(1)  Cash flow from operations  represents net earnings  before  depletion and
     depreciation, future income taxes, and other non-cash expenses.

Cash flow  from  operations  in 2005  reached a new high as a result of strong
commodity prices and increasing production levels.

Net earning in 2005 increased $18 million,  or 28%, from 2004 and were reduced
by non-recurring  one-time costs of $14.4 million ($20.8 million before taxes)
relating to the repurchase of U.S.$158.25  million of 9.90% Senior Notes.  See
discussion on Tender Costs.

The following  table  reconciles  cash flow from operating  activities to cash
flow from operations.

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
Years ended December 31,  ($000s)                                       2005          2004          2003
-----------------------------------------------------------------------------------------------------------
<S>                                                                  <C>           <C>           <C>
Cash flow from operating activities, as reported                     $ 286,553     $ 164,537     $ 156,211
Changes in non-cash operating working capital items                     (8,441)       12,594        (1,318)
-----------------------------------------------------------------------------------------------------------
Cash flow from operations                                            $ 278,112     $ 177,131     $ 154,893
-----------------------------------------------------------------------------------------------------------
</TABLE>

OPERATING EARNINGS

Operating  earnings  is a  non-GAAP  measure  that  adjusts  net  earnings  by
non-operating  items that Management  believes reduce the comparability of the
Company's  underlying  financial  performance  between periods.  The following
reconciliation  of operating  earnings has been prepared to provide  investors
with information that is more comparable between years.

SUMMARY OF OPERATING EARNINGS

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
Years ended December 31, ($000s, except per share amounts)               2005         2004          2003
-----------------------------------------------------------------------------------------------------------
<S>                                                                  <C>           <C>           <C>
  Net earnings, as reported                                          $   81,326    $  63,633     $ 118,880
  Non-operational items, after tax
    Unrealized foreign exchange (gain)                                   (6,339)     (11,821)      (37,761)
    Unrealized risk management loss                                       6,345        1,338             -
    Stock-based compensation                                              3,682        2,094           451
    Tender costs on repurchase of 9.90% notes                            14,414            -             -
    Future tax recovery due to tax rate reductions                       (5,764)      (8,359)      (37,130)
-----------------------------------------------------------------------------------------------------------
  Operating earnings                                                 $   93,664    $  46,885     $  44,440
  Per share:  basic                                                  $     0.75    $    0.40     $    0.38
              diluted                                                $     0.71    $    0.38     $    0.36
-----------------------------------------------------------------------------------------------------------
</TABLE>

                                     -2-
<PAGE>

The same factors that drove the increase in cash flow from operations - strong
commodity  prices and higher  production  volumes - resulted in 2005 operating
earnings almost doubling the prior year level.

REVENUE

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
Years ended December 31,                                                2005           2004         2003
-----------------------------------------------------------------------------------------------------------
<S>                                                                  <C>           <C>          <C>
AVERAGE PRODUCTION
   Natural gas (MMCF/D)                                                    131           123          118
   Liquids (BBLS/D)                                                      7,646         6,330        5,924
-----------------------------------------------------------------------------------------------------------
  Total (BOE/D)                                                         29,424        26,876       25,552

BENCHMARK PRICES
  NYMEX (U.S.$/MMBTU)                                                $    8.55     $    6.09    $    5.60
  AECO ($/MCF)                                                       $    8.04     $    6.44    $    6.35
  WTI (U.S.$/BBL)                                                    $   56.56     $   41.40    $   31.04
  Edmonton par ($/BBL)                                               $   68.72     $   52.37    $   43.14

REALIZED PRICES
   Natural gas ($/MCF)                                               $    8.42     $    6.46    $    6.27
   Liquids ($/BBL)                                                       56.04         43.21        35.59
-----------------------------------------------------------------------------------------------------------
  Total ($/BOE)                                                      $   51.95     $   39.82    $   37.16
-----------------------------------------------------------------------------------------------------------

REVENUE ($000s)
  Natural gas                                                        $ 401,468     $ 291,565    $ 269,622
  Liquids                                                              156,411       100,094       76,943
-----------------------------------------------------------------------------------------------------------
  Total                                                              $ 557,879     $ 391,659    $ 346,565
-----------------------------------------------------------------------------------------------------------
</TABLE>

Revenue in 2005 increased  from the comparable  period due to a combination of
increased production volumes and higher realized prices.


SUMMARY OF REVENUE INCREASES FROM PRODUCTION AND PRICING

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
                                                                Natural Gas          Liquids        Total
($000s)                                                           Revenue            Revenue       Revenue
-----------------------------------------------------------------------------------------------------------
<S>                                                               <C>              <C>           <C>
Reported 2004 revenue                                             $ 291,565        $ 100,094     $ 391,659
Increase in production volumes                                       21,659           26,579        48,238
Increase in prices                                                   88,244           29,738       117,982
-----------------------------------------------------------------------------------------------------------
Reported 2005 revenue                                             $ 401,468        $ 156,411     $ 557,879
-----------------------------------------------------------------------------------------------------------
</TABLE>

Production volumes in 2005 increased 9% from 2004 as a result of the Company's
2005 drilling program.  Production growth in Southern Alberta,  which accounts
for 60% of Compton's  total  volumes,  was hampered by abnormally  wet weather
conditions during the summer months. Well completions, pipeline constructions,
and tie-ins  scheduled for the second and third quarters were delayed by field
conditions,  partially  offsetting  Compton's  aggressive  efforts to increase
annual production volumes.

                                     -3-

<PAGE>

Compton's  natural gas  production is sold under a combination  of longer term
contracts  with  aggregators  and  short  term  daily or 30 day  AECO  indexed
contracts.  Approximately  10% of the Company's natural gas production in 2005
was  committed  to  aggregators,  compared  to an average of 11% in 2004.  The
average  aggregator  price  realized  in 2005  was  $1.25/MCF  less  than  the
non-aggregator prices realized during the year.

Compton's  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.  The  Company
sells crude oil and natural gas liquids  primarily to refineries and marketers
of crude oil and natural gas liquids.

From time to time,  Compton may enter into  hedging  arrangements  to mitigate
commodity  price  risk.  In  accordance  with the  Company's  policy,  hedging
programs will not exceed 50% of  non-contracted  production.  Commodity  hedge
gains and losses are reflected in "Risk Management" on the consolidated income
statements.

ROYALTIES

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
Years ended December 31,  ($000s, except where noted)                   2005          2004          2003
-----------------------------------------------------------------------------------------------------------
<S>                                                                  <C>           <C>           <C>
Crown royalties                                                      $ 106,253     $  75,859     $  68,360
Other royalties                                                         26,890        17,939        14,706
-----------------------------------------------------------------------------------------------------------
Total royalties                                                        133,143        93,798        83,066
Alberta royalty tax credit                                                (426)         (382)         (500)
-----------------------------------------------------------------------------------------------------------
Net royalties                                                        $ 132,717     $  93,416     $  82,566

Percentage of revenues                                                   23.8%         23.9%         23.8%
-----------------------------------------------------------------------------------------------------------
</TABLE>

The  Alberta  royalty  structure  is  based  upon  commodity  prices  and well
productivity,  with  higher  prices and well  productivity  attracting  higher
royalty rates.  In 2005, the increased in the rate  associated  with increased
prices is offset by increased oil  production and an increase in the number of
lower productivity gas wells, both which attract lower royalty rates.

OPERATING EXPENSES

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
Years ended December 31,                                               2005           2004          2003
-----------------------------------------------------------------------------------------------------------
<S>                <C>                                               <C>           <C>           <C>
Operating expenses ($000s)                                           $  66,802     $  55,655     $  49,916
Operating expenses per boe ($/BOE)                                   $    6.22     $    5.66     $    5.35
-----------------------------------------------------------------------------------------------------------
</TABLE>

Operating  costs per boe  increased  year over year due to an overall  rise in
industry costs and the additional  lifting costs associated with increased oil
production.  High commodity prices in 2005 accelerated activity throughout the
oil and  gas  industry,  increasing  the  demand  for and  cost of  goods  and
services.  Particular  increases of note include salaries for additional field
staff and contract operators,  rising electricity prices in the latter half of
2005, salt water disposal, and emulsion processing.

                                     -4-
<PAGE>

TRANSPORTATION

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
Years ended December 31,                                               2005           2004         2003
-----------------------------------------------------------------------------------------------------------
<S>                  <C>                                             <C>            <C>          <C>
Transportation costs ($000s)                                         $ 10,858       $ 8,595      $ 8,447
Transportation costs per boe ($/BOE)                                 $   1.01       $  0.87      $  0.91
-----------------------------------------------------------------------------------------------------------
</TABLE>

Compton  incurs  charges  on the  transportation  of its  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.

Higher  transportation  costs in 2005  result from a  combination  of trucking
costs associated with increased crude oil production and surcharges associated
with rising fuel costs.

GENERAL AND ADMINISTRATIVE EXPENSES

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
Years ended December 31,  ($000s, except where noted)                   2005           2004        2003
-----------------------------------------------------------------------------------------------------------
<S>                                                                  <C>           <C>           <C>
General and administrative expenses                                  $  31,451     $  24,663     $  20,355
Capitalized general and administrative expenses                         (3,647)       (2,683)       (3,321)
Operator recoveries                                                     (6,581)       (6,765)       (4,828)
-----------------------------------------------------------------------------------------------------------
Total general and administrative expenses                            $  21,223     $  15,215     $  12,206

General and administrative per boe  ($/BOE)                          $    1.98     $    1.55     $    1.31
-----------------------------------------------------------------------------------------------------------
</TABLE>

As budgeted,  general and administrative costs increased 39% in the last year.
The major  component in this year over year  increase,  contributing  32%, was
additional  employee costs  associated with increased  personnel  levels and a
general  increase  in  salaries  necessary  to attract  and  retain  qualified
personnel in a very  competitive  industry.  Other  increases  result from the
current  regulatory  environment  including  Sarbanes Oxley compliance and the
resulting increase in legal, audit, and reserve evaluation costs.

INTEREST EXPENSE

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
Years ended December 31, ($000s)                                        2005           2004          2003
-----------------------------------------------------------------------------------------------------------
<S>                                                                  <C>           <C>           <C>
Interest on bank debt, net                                           $  11,520     $   9,662     $   6,611
Interest on Senior Notes                                                20,912        21,281        21,711
-----------------------------------------------------------------------------------------------------------
Interest expense                                                        32,432        30,943        28,322
Finance charges                                                          2,519         2,790         2,273
-----------------------------------------------------------------------------------------------------------
Total interest and finance charges                                   $  34,951     $  33,733     $  30,595
-----------------------------------------------------------------------------------------------------------
</TABLE>

Interest  costs in 2005  increased  from the prior  period  due to higher  debt
levels,  precipitated  by capital  expenditures  exceeding cash flow throughout
2005.  Interest  costs have also been affected by rising  interest  rates.  The
impact on interest  expense of issuing  U.S.$300 million of 7 5/8% Senior Notes
late in the year was minimal.

                                     -5-
<PAGE>

TENDER COSTS

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
Years ended December 31, ($000s)                                                                   2005
-----------------------------------------------------------------------------------------------------------
<S>                                                                                              <C>
Premium payment                                                                                  $  7,814
Consent solicitation fee                                                                            5,883
Pro-forma reduction of deferred financing charges on repayment of 9.90% Senior Notes                7,053
-----------------------------------------------------------------------------------------------------------
Total tender costs                                                                               $ 20,750
-----------------------------------------------------------------------------------------------------------
</TABLE>

In November  2005,  the Company and a wholly owned  subsidiary  of the Company
completed a tender offer and consent  solicitation to purchase Compton's 9.90%
Senior Notes due in 2009. Holders of U.S.$158.25  million  (approximately 96%)
of the  outstanding  9.90% Notes tendered the notes and delivered  consents to
amend the Indenture.  The premium payment for notes tendered was 104.195% plus
accrued and unpaid  interest,  and the note  holders that  delivered  consents
received 103% for a total consideration of 107.195%.

The unamortized  portion of deferred financing charges related to the tendered
portion of the 9.90% Senior Notes of $7.1 million was also  included in tender
costs.

NETBACKS

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------
YEARS ENDED DECEMBER 31, ($/BOE)                                     2005           2004         2003
----------------------------------------------------------------------------------------------------------
<S>                                                                  <C>           <C>           <C>
Realized price                                                       $  51.95      $  39.82      $  37.16
Royalties, net                                                         (12.36)        (9.50)        (8.85)
Operating expenses                                                      (6.22)        (5.66)        (5.35)
Transportation                                                          (1.01)        (0.87)        (0.91)
----------------------------------------------------------------------------------------------------------
Field operating netback                                              $  32.36      $  23.79      $  22.05
----------------------------------------------------------------------------------------------------------

General and administrative                                              (1.98)        (1.55)        (1.31)
Interest                                                                (3.25)        (3.43)        (3.28)
Current taxes                                                           (0.47)        (0.28)        (0.35)
----------------------------------------------------------------------------------------------------------
Cash flow netback                                                    $  26.66      $  18.53      $  17.11
----------------------------------------------------------------------------------------------------------
</TABLE>

RISK MANAGEMENT

Compton's  financial  results are impacted by external market risks associated
with fluctuations in commodity  prices,  interest rates, and the Canadian/U.S.
exchange  rate.  The  Company  utilizes  various  financial   instruments  for
non-trading  purposes to manage and mitigate its exposure to these risks.  The
Company records  financial  instruments,  not designated or not qualifying for
hedge  accounting,  at fair value on the  consolidated  balance  sheets,  with
subsequent changes recognized in consolidated net earnings.

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 to the Company which is recognized as a realized Risk
Management gain or loss at the time of settlement.

The mark-to-market fair value of a financial instrument outstanding at the end
of a reporting  period,  reflects the value of the  instrument  based upon the
market  conditions  existing as of that date.  Any change in the fair value of
the  instrument  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 so recognized  may or may not be realized in
subsequent  periods  depending  upon  subsequent  moves in  commodity  prices,
interest rates, or exchange rates affecting the financial instrument.

                                     -6-
<PAGE>

The mark-to-market  fair value method of accounting for financial  instruments
and the recognition of unrealized gains and losses in determining earnings has
introduced  an  additional  element of  volatility in earnings that may not be
particularly  meaningful  in assessing  the  Company's  financial  performance
between periods.

Risk management gains and losses recognized in 2005 are outlined below.

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------
Year ended December 31,  ($000s)                                          2005        2004         2003
----------------------------------------------------------------------------------------------------------
<S>                                                                  <C>           <C>           <C>
Commodity contracts
               Realized loss                                         $   9,663     $  9,151      $  5,497
               Unrealized loss (gain)                                    5,136       (1,985)            -
Cross currency interest rate swap
               Realized (gain)                                            (532)      (2,522)       (1,365)
               Unrealized loss                                           5,035        4,164            -
----------------------------------------------------------------------------------------------------------
Total risk management loss                                           $  19,302     $  8,808      $  4,132
----------------------------------------------------------------------------------------------------------

Realized loss                                                        $   9,131     $  6,629      $  4,132
Unrealized loss                                                         10,171        2,179             -
----------------------------------------------------------------------------------------------------------
Total risk management loss                                           $  19,302     $  8,808      $  4,132
----------------------------------------------------------------------------------------------------------
</TABLE>


DEPLETION AND DEPRECIATION

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------
Years ended December 31,                                               2005           2004         2003
----------------------------------------------------------------------------------------------------------
<S>                              <C>                                 <C>           <C>           <C>
Total depletion and depreciation ($000s)                             $ 105,504     $ 82,554      $  61,749
Depletion and depreciation per boe ($/BOE)                           $    9.82     $   8.39      $    6.62
----------------------------------------------------------------------------------------------------------
</TABLE>

The Company's  2005  provision for  depletion and  depreciation  increased $23
million or 28% over 2004.  Approximately one third of this increase was due to
the increase in 2005  production  over that of 2004 with the balance being the
result of an  overall  increase  in the  depletion  and  depreciation  rate as
determined on a boe basis. The depletion and depreciation  rate on a boe basis
reflects increased costs relating to exploration and development activities as
discussed in capital expenditures.

FOREIGN EXCHANGE

The  foreign  exchange  gain  recognized  on the  consolidated  statements  of
earnings  results  primarily from the translation of the Company's 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  recorded as unrealized
foreign exchange gain or loss.

                                     -7-
<PAGE>

The  Canadian/U.S.  exchange rate increased to one Canadian Dollar being equal
to  U.S.$0.8577  on December 31, 2005 from one Canadian  Dollar being equal to
U.S.$0.8308  at December  31, 2004,  resulting  in the Company  recording a $7
million foreign exchange gain in 2005.

On November  22, 2005,  pursuant to a tender  offer,  the Company  repurchased
U.S.$158.25  million of the 9.90% Senior Notes issued in 2002.  As a result of
the  repurchase,  the Company  crystallized  $62.2 million of the  accumulated
unrealized foreign exchange gains that had been previously recognized with the
strengthening of the Canadian dollar subsequent to the note issuance.


STOCK-BASED COMPENSATION

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
Years ended December 31,                                                2005          2004         2003
-----------------------------------------------------------------------------------------------------------
<S>                                                                  <C>           <C>           <C>
Options granted (000s)                                                  2,930         2,549         1,503
Weighted average fair value of options granted ($/share)             $   5.45      $   3.70      $   3.01
Stock-based compensation expense recognized ($000s)                  $  5,903      $  3,410      $    760
-----------------------------------------------------------------------------------------------------------
</TABLE>

Compton has a stock option plan for Directors,  Officers,  and employees.  The
plan is designed to attract,  motivate, and retain outstanding individuals and
to  align  their  success  with  that of the  Shareholders  through  achieving
corporate  objectives.  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.

TAXES

CURRENT TAXES

Current taxes include  federal  capital tax which decreased to $1.9 million in
2005 from $2.5 million in 2004 (2003 - $2.5  million) due mainly to a tax rate
reduction from 0.200% to 0.175%, as part of the phased  elimination of federal
capital tax by 2008.

Current taxes in 2005 also include $3.2 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 have been added to Compton's tax pools.

FUTURE INCOME TAXES

The  Company's  future  income taxes were $52.3  million in 2005,  compared to
$33.4  million  in 2004  and  $20.0  million  in  2003.  Future  taxes in 2004
benefited  from an $8 million  recovery  due to a reduction in the Alberta tax
rate from 12.5% to 11.5%.  Future  taxes in 2003  reflected  a recovery of $37
million due to reductions in Canadian federal and Alberta  corporate tax rates
and  related  changes  to  the  Canadian   federal   resource   allowance  and
deductibility of provincial crown charges paid.

                                     -8-
<PAGE>


CORPORATE TAX RATES

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
Years ended December 31,                                                 2005         2004        2003
-----------------------------------------------------------------------------------------------------------
<S>                                                                    <C>          <C>         <C>
Statutory rate                                                           37.6%        38.6%       40.6%
Effective rate                                                           39.5%        35.0%       16.4%
-----------------------------------------------------------------------------------------------------------
</TABLE>

A reconciliation of the Company's effective tax rate to the statutory rate may
be found in Note 15(a) to the consolidated financial statements.

TAX POOLS

The  following  table  summarizes  Compton's  estimated  tax pool  balances by
classification.

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
                                                                               AVAILABLE       MAXIMUM
                                                                                BALANCE         ANNUAL
As at January 1, 2006                                                           ($000S)       DEDUCTION
-----------------------------------------------------------------------------------------------------------
<S>                                                                            <C>            <C>
Canadian exploration expense                                                   $  87,748         100%
Canadian development expense                                                     322,165          30%
Canadian oil and natural gas property expense                                    217,203          10%
Undepreciated capital cost and financing costs                                   222,540         ~25%
-----------------------------------------------------------------------------------------------------------
Total                                                                          $ 849,656
-----------------------------------------------------------------------------------------------------------
</TABLE>

A significant portion of the Company's taxable income is generated by a wholly
owned  partnership.  Consolidated  earnings  before  income taxes include $263
million (2004 - $178 million) of partnership earnings that will be included in
the  following  year's  income for income tax  purposes.  Future  income taxes
include  $94  million  (2004 - $67  million)  as a result of this  deferral of
partnership earnings.

Based upon planned capital  expenditure  programs and current  commodity price
assumptions, it appears the Company will not be cash taxable until 2009.

CAPITAL EXPENDITURES

SUMMARY OF CAPITAL EXPENDITURE ALLOCATION

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
Years ended December 31,                          2005                    2004                    2003
-----------------------------------------------------------------------------------------------------------
                                           ($000S)      %          ($000s)     %           ($000s)      %
-----------------------------------------------------------------------------------------------------------
<S>                                       <C>           <C>       <C>          <C>        <C>           <C>
Drilling and completions                  $318,502      62        $175,003     57         $126,308      57
Land and seismic                            55,469      11          38,326     12           37,128      17
Facilities                                 109,729      21          68,861     23           46,068      21
Acquisitions, net                           28,575       6          22,825      8           11,224       5
-----------------------------------------------------------------------------------------------------------
Sub-total                                  512,275     100         305,015    100          220,728     100
MPP                                          1,261                  11,386                  64,755
-----------------------------------------------------------------------------------------------------------
Total capital expenditures                $513,536                $316,401                $285,483
-----------------------------------------------------------------------------------------------------------
</TABLE>

                                     -9-

<PAGE>

In 2005,  Compton  significantly  increased its drilling  program over that of
previous  years  with the  express  objective  of  realizing  on its  unbooked
resource  potential.  The Company drilled 334 net wells (392 gross) in 2005 as
compared to 146 net wells (186 gross) in 2004. The number of net wells drilled
in 2005  increased  129%  over  the  number  of net  wells  drilled  in  2004.
Reflecting this growth in activity, total 2005 capital expenditures, excluding
MPP related expenditures, increased $207 million, or 68%, from $305 million in
2004 to $512 million in 2005.

As would be expected  with the  increased  well count,  70% of the increase in
capital  expenditures relates to drilling and completion costs which increased
$143 million from $175 million in 2004 to $319 million in 2005.  On a per well
basis,  drilling and completion costs actually  decreased 21% to an average of
$0.95  million  per net well in 2005 from an average of $1.2  million  per net
well in 2004. The decrease in the average cost per well reflects the Company's
drilling  focus during 2005.  The  Company's  2005 drill  program  included an
additional  80 wells  targeting  Charlie  Lake oil at Cecil and Worsley and an
additional 110 wells targeting  shallower Belly River gas in Southern  Alberta
as compared to 2004.  These wells, and particularly the Belly River wells, are
lower  cost  as  compared  to the  deeper  targets  that  comprise  a  greater
percentage of the 2004 drill count.

Facility  expenditures,   which  included  processing  facilities,   gathering
systems,  compression  and well  equipment,  comprised  21% of  total  capital
expenditures  and  increased in relation to the Company's  increased  level of
activity.

Strong  commodity  prices have  accelerated  capital  programs and competition
throughout  the oil and gas  industry,  raising  the demand and costs of land,
drilling  rigs,  completion  services,  and  supplies.  During  2005,  Compton
experienced  cost increases  ranging as high as 20% for certain  services over
2004 levels.  In addition to the increased level of activity in 2005,  capital
expenditures  for the year reflect this overall  increase in the cost of goods
and services.

LIQUIDITY AND CAPITAL RESOURCES

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
As at December 31,  ($000s, except where noted)                         2005          2004           2003
-----------------------------------------------------------------------------------------------------------
<S>                                                                  <C>           <C>           <C>
Working capital (1)                                                  $  62,431     $     603     $  (21,843)
Bank debt                                                              177,900       220,000        164,500
Senior term notes                                                      357,640       198,594        213,246
-----------------------------------------------------------------------------------------------------------
Total indebtedness                                                   $ 597,971     $ 419,197     $  355,903

Capital stock                                                        $ 226,444     $ 135,526     $  131,577
Contributed surplus                                                      9,173         3,840            760
Retained earnings                                                      360,719       284,712        224,569
-----------------------------------------------------------------------------------------------------------
Shareholders' equity                                                 $ 596,336     $ 424,078     $  356,906

Debt to cash flow from operations (2) (3)                                 1.93          2.36           2.44
Debt to book capitalization (2)                                            47%           50%            51%
Debt to market capitalization (2)                                          20%           25%            35%
-----------------------------------------------------------------------------------------------------------
</TABLE>

(1)  Working capital excludes unrealized risk management items.
(2)  Debt includes current and long term portion and excludes  unrealized risk
     management items.
(3)  Based on trailing 12 month cash flow from operations.

Working  capital at December 31, 2005 decreased from the prior year due to the
Company's  extremely active fourth quarter and the resulting increase in trade
payables.  At year end,  Compton had drawn $178 million on its available  $289
million syndicated credit facility.

                                     -10-
<PAGE>

In November  2005, a wholly owned  subsidiary  of the Company  issued  U.S.$300
million of 7 5/8% Senior Notes due in 2013.  The proceeds  were used to repay a
portion of the Company's debt under its senior secured credit facilities and to
fund the  purchase  of a portion of the 9.90%  Senior  Notes due in 2009,  by a
wholly owned subsidiary of the Company. At December 31, 2005, U.S.$6.75 million
of the 9.90% Notes remain outstanding but can be called, at a premium,  anytime
after May 15, 2006. The purchase of the 9.90% Notes  eliminated the restrictive
covenants of the Indenture agreement and have provided the Company with greater
financial flexibility.

The  principal  amount of the Senior Notes  remains fixed at U.S. $300 million.
The value of the  notes  shown on the  consolidated  balance  sheets  varies in
response to movement in the  Canadian/U.S.  dollar  exchange rate.  Standards &
Poor's Rating Services ("S&P") and Moody's  Corporation  ("Moody's") have rated
the Company as B+ stable and B1 stable  respectively,  as at December 31, 2005.
The U.S. $300 million 7 5/8% Senior Notes are rated as B stable and B2 stable.

The Company  expects  internally  generated  operating cash flow together with
other  available   financing  options,   including  debt  financing,   readily
accessible equity markets, and potential minor non-core property dispositions,
will  fund  its  planned  2006  capital  program  while   maintaining   fiscal
responsibility.


CONTRACTUAL OBLIGATIONS

As part of normal business, Compton has 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 the Company's  contractual  obligations as at
December 31, 2005.

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
                                                          PAYMENTS DUE BY PERIOD
($000s)                                  LESS THAN 1 YEAR       1-3 YEARS    4-5 YEARS     AFTER 5 YEARS
-----------------------------------------------------------------------------------------------------------
<S>                                      <C>                  <C>            <C>           <C>
Partnership distributions                     $  9,172          $ 21,401      $   -         $       -
Operating leases                                11,277             7,418          -                 -
Office rent                                      1,356               249          -                 -
Senior Notes                                         -             7,870          -           349,770
Other                                               52                 -          -                 -
-----------------------------------------------------------------------------------------------------------
Total                                         $ 21,857          $ 36,938      $   -         $ 349,770
-----------------------------------------------------------------------------------------------------------
</TABLE>

The  Company  has the  ability  and  intends to extend the term of its current
borrowings  of $178 million on an ongoing  basis under its  syndicated  credit
facility  and  therefore  repayment  of the  facility  is not  included in the
schedule of contractual obligations above.

COMMITMENTS

To prevent the expiration of undeveloped  lands,  the Company  anticipates $65
million of work commitments  will be required in 2006. These  commitments have
been included in our 2006 capital expenditure budget.

                                     -11-
<PAGE>

GUIDANCE FOR 2006

Compton's 2006 budget was prepared in December  2005, and reflected  commodity
price  forecasts at that time.  With the recent decline in natural gas prices,
the Company has reassessed its budget in relation to current  prices.  Current
lower  prices  will  reduce  cash flow by $80  million  from  that  originally
projected if sustained over the remainder of the year. At this  juncture,  the
Company has not revised its drilling and capital programs.

In 2006, Compton will continue to focus on the development of its five natural
gas resource  plays and  conventional  crude oil property to maximize  reserve
recognition and production growth.

SUMMARY OF 2006 GUIDANCE

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------
                                                                        2006 BUDGET RANGE
-----------------------------------------------------------------------------------------------
<S>                                                                     <C>
Capital expenditures ($MILLIONS)                                               $575
Gross wells                                                                     480
Average production
   Natural gas (MMCF/D)                                                     155 to 160
   Liquids (BBLS/D)                                                      11,000 to 11,300
-----------------------------------------------------------------------------------------------
  Total (BOE/D)                                                          37,000 to 38,000
Cash flow from operations ($MILLIONS)                                      $375 to $390
-----------------------------------------------------------------------------------------------
</TABLE>

The Company's  revised 2006 projected cash flow from operations  projection is
based upon the following pricing assumptions:

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------
                                                             BENCHMARK            REALIZED
-----------------------------------------------------------------------------------------------
<S>                                                       <C>                  <C>
Natural gas                                               AECO Cdn $7.90/GJ    Cdn $8.15/MCF
Crude oil ($/BBL)                                           WTI U.S. $62.00       Cdn $65.00
-----------------------------------------------------------------------------------------------
</TABLE>

The average Canadian/U.S. exchange rate is budgeted at $0.85 U.S. = $1.00 Cdn.


CASH FLOW SENSITIVITIES FOR 2006

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------
($millions)
-----------------------------------------------------------------------------------------------
<S>                                                                                 <C>
Change of Cdn $0.10/MCF in the benchmark AECO natural gas price                      $4.5
Change of U.S. $1.00/barrel in the benchmark WTI oil price                           $3.0
-----------------------------------------------------------------------------------------------
</TABLE>

In the event of  significant  decreases  in  commodity  prices,  increases  in
exploration  costs, or an overall  economic  downturn,  the Company's  capital
expenditure program can be readily modified.

ADDITIONAL DISCLOSURES

EFFECTIVENESS OF DISCLOSURE CONTROLS AND PROCEDURES

Compton has  carried  out an  evaluation  under the  supervision  and with the
participation of its Management,  including its President & CEO and VP Finance
& CFO,  of the  effectiveness  of the design and  operation  of the  Company's
disclosure  controls and procedures.  Based upon its  evaluation,  Compton has
concluded  that,  as  of  December  31,  2005,  the  disclosure  controls  and
procedures  were  effective in all  material  respects.  The term  "disclosure
controls  and   procedures"   is  defined  under  the  Security  and  Exchange
Commission's Exchange Act Rule 13a-15(d) as controls and other procedures of a
public  company that are designed to ensure both  non-financial  and financial
information required to be disclosed by the company in its periodic reports is
recorded, processed, summarized, and reported in a timely fashion.

                                     -12-
<PAGE>

SARBANES OXLEY SECTION 404 UPDATE

Compton is required to comply with  Section 404 of the  Sarbanes  Oxley Act of
2002.  Section 404,  together  with the  Security  and  Exchange  Commission's
Exchange Act and other Rules and Regulations, requires Compton to evaluate and
certify its  internal  controls  over  financial  reporting as at December 31,
2006, and have its evaluation  and report thereto  audited by its  independent
external auditors.

Compton has  developed a plan for meeting  these  requirements  and is working
toward the  execution  of that plan.  The Company is currently in the controls
remediation  phase  of  the  plan  and is  confident  it  will  meet  all  the
requirements of Section 404 in the time required.

ACCOUNTING ESTIMATES

Accounting estimates require Management to make assumptions  regarding matters
that are  uncertain  at the time the  estimate is made and may have a material
impact on the financial  condition of the Company. A comprehensive  discussion
of  Compton's  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 evaluated and reported on 100% of Compton's oil and natural
gas reserves.

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.  The Company  expects that its 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 the depletion and  depreciation,
asset  retirement  obligations,  and  impairment  costs,  all of  which  could
possibly have a material impact on consolidated net earnings.

DEPLETION

Capitalized  costs  and  estimated  future   expenditures  to  develop  proved
reserves, including abandonment costs, are depleted based on the proportion of
estimated  proved  oil and  natural  gas  reserves  produced  during  the year
compared to 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 2005,  Compton incurred $106 million of depletion and depreciation.  If the
proved  reserves of the Company  were to  increase  by 5%, the  depletion  and
depreciation  expense  would  decrease by $0.8  million and  consolidated  net
earnings after tax would increase by $0.5 million.  If the proved  reserves of
the Company were to decrease by 5%, the  depletion  and  depreciation  expense
would increase by $1.9 million and  consolidated  net earnings after tax would
decrease by $1.2 million.

                                     -13-
<PAGE>

IMPAIRMENT

In  applying  the  full  cost  method  of  accounting,   Compton  periodically
calculates 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, 2005 the ceiling
amount  calculated  was $2.5  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 the  Company's
reserves are anticipated.

ASSET RETIREMENT OBLIGATION

The  Company   recognizes  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 the Company 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.

RISK MANAGEMENT

Compton's  operations are subject to risks inherent to the oil and natural gas
industry.  The Company is 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.  The Company
takes specific measures to manage these risks,  particularly those that impact
cash flow from operations.

A more detailed  discussion of risk factors is presented in the Company's most
recent Annual Information Form, filed with securities  regulatory  authorities
on www.sedar.com.

                                     -14-
<PAGE>

COMMODITY PRICE RISK MANAGEMENT

Compton enters into commodity  price  contracts to manage risk associated with
price  volatility  to protect cash flow from  operations  required to fund the
Company's  capital program.  Commodity price risk is actively managed by using
costless collars and by balancing physical and financial contracts in terms of
volumes, timing of performance,  and delivery obligations.  Net open positions
may exist or may be established to take  advantage of market  conditions.  Net
earnings for the year ended December 31, 2005 include  realized and unrealized
losses of $15 million (2004 - $7 million loss) on these transactions.

The following table outlines  commodity hedge transactions which are currently
outstanding.

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
COMMODITY                      TERM                     AMOUNT              AVERAGE PRICE           INDEX
-----------------------------------------------------------------------------------------------------------
<S>               <C>                                <C>                 <C>                      <C>
Natural gas
   Collar         Nov. 2005 - Mar. 2006               40,000 GJ/d        Cdn$8.56 - $12.79          AECO
   Fixed          Nov. 2005 - Mar. 2006               10,000 GJ/d              Cdn$8.60             AECO
   Collar         Apr. 2006 - Oct. 2006               45,000 GJ/d        Cdn$8.33 - $12.23          AECO

Crude oil
   Collar         Jan. 2006 - Dec. 2006              3,000 bbls/d        U.S.$55.00 - $75.17        WTI
-----------------------------------------------------------------------------------------------------------
</TABLE>

FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT

Compton is 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 Compton's  realized  price being  influenced by the
Canadian/U.S.  currency  exchange rate.  Should the Canadian dollar strengthen
compared to the U.S.  dollar,  the negative  effect on net  earnings  would be
partially  offset by  foreign  exchange  gains on the  Company's  U.S.  dollar
denominated  Senior  Notes.  Conversely,  should the  Canadian  dollar  weaken
compared to the U.S.  dollar,  the positive  effect on net  earnings  would be
partially  offset by foreign  exchange  losses on the  Company's  U.S.  dollar
denominated  Senior  Notes.  Cash flow from  operations is not impacted by the
effects of currency  fluctuations  on the Company's  U.S.  dollar  denominated
Senior Notes.

INTEREST RATE RISK MANAGEMENT

Concurrent  with the closing of the Company's  9.90% Senior Notes  offering in
May of 2002,  Compton  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,  the Company  elected  not to collapse  the swap and incur the
associated  costs  of  $12.2  million.  The swap  remains  outstanding  and at
December  31,  2005 the  Company  valued  the  liability  relating  to  future
unrealized  losses on the swap  arrangement  to be $14.8 million (2004 - $11.4
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-annual and losses realized will be recorded over the remaining term
of the swap agreement which expires in May 2009.

                                     -15-
<PAGE>

SELECTED QUARTERLY INFORMATION

The following tables set out selected quarterly  financial  information of the
Company for the last two fiscal years.

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------
                                                   THREE MONTHS ENDED                          YEAR ENDED
----------------------------------------------------------------------------------------------------------
                                        MARCH 31,       JUNE 30,     SEPT. 30,      DEC. 31,      DEC. 31,
($000s, except where noted)                2005           2005          2005          2005          2005
----------------------------------------------------------------------------------------------------------
<S>                                    <C>            <C>           <C>           <C>           <C>
Average production (BOE/D)                28,714         28,877        29,041        31,042        29,424
Average pricing ($/BOE)                $   41.25      $   46.33     $   54.31     $   64.58     $   51.95

Total revenue                          $ 106,589      $ 121,748     $ 145,114     $ 184,428     $ 557,879
Cash flow from operations              $  52,277      $  62,006     $  74,189     $  89,640     $ 278,112
Per share:  basic                      $    0.43      $    0.49     $    0.58     $    0.71     $    2.21
            diluted                    $    0.41      $    0.47     $    0.56     $    0.67     $    2.11

Operating earnings                     $  15,534      $  18,923     $  25,794     $  33,413     $  93,664

Net earnings                           $  10,059      $  22,034     $  11,127     $  38,106     $  81,326
Per share:  basic                      $    0.08      $    0.17     $    0.09     $    0.30     $    0.65
            diluted                    $    0.08      $    0.17     $    0.08     $    0.28     $    0.62
----------------------------------------------------------------------------------------------------------
</TABLE>

Total revenue increased throughout 2005 as the result of high commodity prices
and increasing  production volumes.  Average production increased in the third
and fourth  quarters,  after  abnormally wet weather in the summer  restricted
access in Southern Alberta resulting in flat production  volumes in the second
quarter.  Quarterly net earnings fluctuated due to non-operational  items such
as unrealized risk management gains and losses and unrealized foreign exchange
losses.

FOURTH QUARTER 2005

Average fourth quarter 2005 production  increased 7% from the third quarter of
2005,  with production in December 2005 reaching  approximately  35,500 boe/d.
Due to the  abnormally  wet  weather  in  Southern  Alberta  during the summer
months, well completions,  tie-ins, and pipeline  constructions were postponed
until the fourth quarter.  Revenue and net earnings for the quarter  benefited
from increased production and high commodity prices.


                                     -16-
<PAGE>

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------
                                                   THREE MONTHS ENDED                       YEAR ENDED
-------------------------------------------------------------------------------------------------------
                                       MARCH 31,      JUNE 30,    SEPT. 30,    DEC. 31,       DEC. 31,
($000s, except where noted)               2004          2004         2004        2004           2004
-------------------------------------------------------------------------------------------------------
<S>                                    <C>            <C>         <C>          <C>           <C>
Average production (BOE/D)               25,717        26,295        27,268       28,204        26,876
Average pricing ($/BOE)                $  38.04      $  41.43     $   40.78    $   39.00     $   39.82

Total revenue                          $ 89,031      $ 99,140     $ 102,299    $ 101,189     $ 391,659
Cash flow from operations              $ 40,860      $ 47,698     $  46,844    $  41,729     $ 177,131
Per share:  basic                      $   0.35      $   0.41     $    0.40    $    0.35     $    1.51
            diluted                    $   0.33      $   0.39     $    0.38    $    0.33     $    1.43

Operating earnings                     $ 14,235      $ 15,428     $  10,863    $   6,359     $  46,885

Net earnings                           $ 22,301      $  2,978     $  21,977    $  16,377     $  63,633
Per share:  basic                      $   0.19      $   0.03     $    0.19    $    0.14     $    0.54
            diluted                    $   0.18      $   0.02     $    0.18    $    0.13     $    0.51
-------------------------------------------------------------------------------------------------------
</TABLE>

In 2004,  strong overall commodity prices and increasing  production  improved
total  revenue on a  quarterly  basis.  Average  production  in 2004 grew as a
result  of the  Company's  ongoing  drilling  program  and the  resolution  of
facility and pipeline  restrictions in Southern  Alberta.  Net earnings in the
second quarter of 2004 was impacted by an unrealized  risk  management loss of
$7 million  after tax and an  unrealized  foreign  exchange loss of $4 million
after tax.  Net  earnings  in the first,  third,  and fourth  quarters in 2004
benefited from unrealized risk management gains.


SELECTED ANNUAL INFORMATION

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------
Years ended December 31, ($000s)                                     2005             2004           2003
------------------------------------------------------------------------------------------------------------
<S>                                                              <C>              <C>            <C>
Total revenue                                                    $   557,879      $   391,659    $   346,565
Net earnings                                                     $    81,326      $    63,633    $   118,880
Per share:  basic                                                $      0.65      $      0.54    $      1.02
            diluted                                              $      0.62      $      0.51    $      0.97
Total assets                                                     $ 1,755,489      $ 1,330,611    $ 1,064,320
Total long term financial liabilities                            $   535,540      $   198,594    $   213,246
------------------------------------------------------------------------------------------------------------
</TABLE>

Total  revenue  in 2005 was  higher  than in the two  previous  years due to a
combination of increased  production and higher commodity prices. Net earnings
in  2005   increased  $18  million,   28%,  from  2004  and  were  reduced  by
non-recurring  one-time  costs of $14.4 million  ($20.8  million before taxes)
relating to the repurchase of U.S.$158.25 million of 9.90% Senior Notes.

Total  assets   increased  from  the  prior  year  primarily  due  to  capital
expenditures of $514 million. The change in long term financial liabilities at
December 31, 2005 resulted from the Company  issuing  U.S.$300  million Senior
Notes and reclassifying bank debt as long term.

                                     -17-
<PAGE>

Net earnings in 2004  decreased  from the prior year as 2003  benefited from a
$38 million after tax unrealized  foreign  exchange gain on the Company's U.S.
dollar  denominated  debt and a $37 million  recovery of future  income  taxes
relating to statutory income tax rate changes.

Total assets were $1.3  billion at December 31, 2004,  an increase of 25% from
the prior year due to capital expenditures of $316 million. The change in long
term  financial  liabilities  at December 31, 2004 resulted from an unrealized
gain due to the translation of the Company's U.S. $165 million Senior Notes.

TRADING AND SHARE STATISTICS

As at March  15,  2006  there  were  127,272,451  common  shares  outstanding,
including 12,505,627 stock options outstanding.

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
                                                                    2005           2004           2003
-----------------------------------------------------------------------------------------------------------
<S>                                                             <C>             <C>              <C>
Average daily trading volume (000s)                                 736,416         674,764        686,100
Share price ($/share)
     High                                                       $     18.66     $     11.43      $    6.35
     Low                                                        $      9.80     $      5.89      $    4.40
     Close                                                      $     17.10     $     10.85      $    6.00
Market capitalization at December 31 ($000s)                    $ 2,176,205     $ 1,273,282      $ 698,535
Shares outstanding (000s)                                           127,263         117,354        116,423
-----------------------------------------------------------------------------------------------------------
</TABLE>

FURTHER INFORMATION

Additional   information   about  Compton,   including  the  Company's  Annual
Information  Form,  is available on the  Canadian  Securities  Administrators'
System  for   Electronic   Document   Analysis  and  Retrieval   ("SEDAR")  at
www.sedar.com.


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 2006, 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 THE COMPANY 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. THE COMPANY'S FORWARD LOOKING STATEMENTS ARE EXPRESSLY QUALIFIED IN
THEIR ENTIRETY BY THIS CAUTIONARY STATEMENT.

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<PAGE>


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,  BOES DO
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.


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