EXHIBIT 3
                                                                       ---------



                       MANAGEMENT DISCUSSION AND ANALYSIS


FORWARD

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 APRIL 19, 2004 AND SHOULD BE READ IN CONJUNCTION WITH THE AUDITED
CONSOLIDATED FINANCIAL STATEMENTS AND RELATED NOTES FOR THE YEAR ENDED DECEMBER
31, 2003. THE CONSOLIDATED FINANCIAL STATEMENTS HAVE BEEN PREPARED IN ACCORDANCE
WITH CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES ("GAAP"). A
RECONCILIATION TO UNITED STATES GAAP IS INCLUDED IN NOTE 20 TO THE CONSOLIDATED
FINANCIAL STATEMENTS.

MANAGEMENT'S DISCUSSION AND ANALYSIS MAY CONTAIN CERTAIN FORWARD-LOOKING
STATEMENTS UNDER THE MEANING OF APPLICABLE SECURITIES LAWS. FORWARD-LOOKING
STATEMENTS INCLUDE ESTIMATES, PLANS, EXPECTATIONS, OPINIONS, FORECASTS,
PROJECTIONS, GUIDANCE OR OTHER STATEMENTS THAT ARE NOT STATEMENTS OF FACT.
ALTHOUGH COMPTON PETROLEUM CORPORATION ("COMPTON" OR "THE COMPANY") 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, AND THE ACTIONS
OR INACTIONS OF THIRD-PARTY OPERATORS. THE COMPANY'S FORWARD-LOOKING STATEMENTS
ARE EXPRESSLY QUALIFIED IN THEIR ENTIRETY BY THIS CAUTIONARY STATEMENT.

MANAGEMENT'S DISCUSSION AND ANALYSIS CONTAINS THE TERM "CASH FLOW FROM
OPERATIONS", WHICH SHOULD NOT BE CONSIDERED AN ALTERNATIVE TO, OR MORE
MEANINGFUL THAN "CASH FLOW FROM OPERATING ACTIVITIES" AS DETERMINED IN
ACCORDANCE WITH CANADIAN GAAP AS AN INDICATOR OF THE COMPANY'S FINANCIAL
PERFORMANCE. COMPTON'S DETERMINATION OF CASH FLOW FROM OPERATIONS MAY NOT BE
COMPARABLE TO THAT REPORTED BY OTHER COMPANIES. THE OTHER ITEMS REQUIRED TO
ARRIVE AT CASH FLOW FROM OPERATING ACTIVITIES ARE CONSIDERED TO BE CORPORATE
CHARGES.

THE OIL AND NATURAL GAS INDUSTRY COMMONLY EXPRESSES PRODUCTION VOLUMES AND
RESERVES ON A BARREL OF OIL EQUIVALENT BASIS ("BOE") 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. IN SEVERAL SECTIONS THAT FOLLOW, COMPTON HAS USED THE 6:1 BOE
MEASURE WHICH IS THE APPROXIMATE ENERGY EQUIVALENCY OF THE TWO COMMODITIES AT
THE BURNER TIP. HOWEVER, BOE'S 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.


OVERVIEW

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. The Company's activities are concentrated in three core
geographic areas in the Western Canadian


<PAGE>

Sedimentary Basin, primarily in Alberta. Compton's growth and reserves base have
resulted from exploration and development activities, complemented by strategic
acquisitions.

MANAGEMENT'S STRATEGY

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    an emphasis on natural gas with a particular focus on unconventional tight
     gas reserves;

o    focus in a limited number of core areas;

o    development of technical expertise;

o    dominant land position and high working interests;

o    control of infrastructure and operatorship;

o    full-cycle exploration;

o    strategic acquisitions.

MAZEPPA PROCESSING PARTNERSHIP

Mazeppa Processing Partnership is a limited partnership organized under the laws
of the province of Alberta. In June 2003, MPP acquired certain midstream assets
in southern Alberta from an independent third party. These midstream assets
consist of major natural gas gathering and processing facilities and that are
critical to Compton's operations in the area.

Compton has minimal ownership in MPP, however, the Company controls and manages
the activities of MPP through a wholly-owned subsidiary that is the General
Partner of MPP. The consolidated financial statements include the accounts of
MPP.

The operations of MPP are considered to be a business segment separate and
distinct from the Company's exploration, exploitation, development and
production activities ("E&P activities"). Segmented information is presented in
Note 4 to the consolidated financial statements and is reflected elsewhere in
the MD&A.

PRODUCTION

-------------------------------------------------------------------------------
Years ended December 31,                              2003      2002      2001
-------------------------------------------------------------------------------

Natural gas (mmcf/d)                                   118       112       101
Liquids (light oil & ngl's) (bbls/d)                 5,924     6,503     6,546
-------------------------------------------------------------------------------
Total oil equivalent (boe/d)                        25,552    25,137    23,404
-------------------------------------------------------------------------------


<PAGE>

Average production in 2003 was 25,552 boe/d, a slight increase from 2002
production of 25,137 boe/d. Production growth in 2003 was constrained by weather
related delays, plant turnarounds, and most significantly, insufficient
processing and pipeline capacity in Southern Alberta. Several initiatives were
undertaken by the Company in 2003 to expand facilities and the production
restraints were eliminated in the second quarter of 2004.

Compton's production profile continues to reflect the Company's focus on natural
gas, which accounted for approximately 77% of the current year's production.
Natural gas production averaged 118 mmcf/d in 2003, a 5% increase from 2002,
while liquids production decreased by 9% to 5,924 bbls/d.

CASH FLOW AND NET EARNINGS

------------------------------------------------------------------------------
Years ended December 31,
($000s, except where noted)                       2003       2002        2001
------------------------------------------------------------------------------

Cash flow from operations                     $154,893    $96,072    $127,861
Per share:  basic                             $   1.33    $  0.85    $   1.16
            diluted                           $   1.27    $  0.81    $   1.11

Net earnings                                  $118,880    $18,312    $ 55,015
Per share:  basic                             $   1.02    $  0.16    $   0.50
            diluted                           $   0.97    $  0.16    $   0.48
------------------------------------------------------------------------------

Cash flow from operations in 2003 was $155 million ($1.33/share basic), a 61%
increase from the previous year. Net earnings for the year totaled $119 million
($1.02/share basic), as compared to $18 million in 2002. MPP did not have a
material impact on Compton's 2003 net earnings or cash flow from operations.

Current year cash flow and net earnings benefited from higher commodity prices.
The average price per boe received by the Company in 2003 increased 50% from
2002. In addition to higher commodity prices, net earnings in the current year
included a $39 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. Net earnings
excluding these items was $43 million, an increase of 134% over 2002.

FINANCIAL RESULTS

REVENUE AND PRICING

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------
Years ended December 31,                     2003                   2002                2001
--------------------------------------------------------------------------------------------------
                                       ($000S)       %       ($000s)     %      ($000s)       %
--------------------------------------------------------------------------------------------------
<S>                                   <C>         <C>       <C>         <C>     <C>         <C>
Natural gas revenue                   $262,203      78      $148,133     67     $174,424     71
Natural gas hedging impact              (3,947)     (1)        1,789      1        3,666      1
Crude oil and ngls revenue              76,051      23        70,297     32       66,880     28
Crude oil hedging impact                (1,548)   (0.5)         (432)    --           --     --
Processing revenue                       1,934     0.5            --     --           --     --
--------------------------------------------------------------------------------------------------
Total revenue                         $334,693     100      $219,787    100     $244,970    100
--------------------------------------------------------------------------------------------------
</TABLE>


<PAGE>

Compton realized $333 million in petroleum and natural gas revenue in 2003, up
51% from the previous year. The increase in revenue resulted primarily from
higher realized prices in 2003. Compton's average realized natural gas price
rose 66% from 2002 to $6.10/mcf in 2003 before hedge losses. The average
realized liquids price in 2003 was $35.11/bb1 before hedge losses, a 19%
increase from 2002.

Processing revenue in 2003 results from the consolidation of MPP and reflects
third party natural gas processing fees.

In 2003, the Company's average realized field prices in Canadian funds were
$6.01/mcf for natural gas and $34.39/bbl for crude oil and natural gas liquids,
compared to the 2002 average field prices of $3.67/mcf and $29.43/bbl for
natural gas and natural gas liquids respectively.

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 16% of the Company's natural gas production in 2003 was
committed to aggregators, compared to an average of 35% in 2002. The average
aggregator price realized in 2003 was approximately $1.00/mcf less than the
non-aggregator prices realized during the year.

Compton's crude oil sales are priced at Edmonton postings and are typically sold
on 30-day evergreen arrangements. Natural gas liquids are bid out on an annual
basis to establish the most competitive 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 Compton's policy, hedging programs will
not exceed 50% of non-contracted production. See Financial Instruments
discussion for outstanding hedges.

ROYALTIES
-----------------------------------------------------------------------------
Years ended December 31,
($000s, except where noted)                    2003         2002       2001
-----------------------------------------------------------------------------

Crown royalties                              $68,360      $38,902    $44,075
Other royalties                               14,706        9,095     12,344
-----------------------------------------------------------------------------
                                              83,066       47,997     56,419
Alberta royalty tax credit                      (500)        (500)      (500)
-----------------------------------------------------------------------------
Net royalties                                $82,566      $47,497    $55,919

Percentage of oil and gas revenues              24.7%        21.6%      22.8%
-----------------------------------------------------------------------------

The Company's royalty obligations for 2003, net of the Alberta royalty tax
credit, amounted to $83 million, a 74% increase from 2002 royalties. The
increase is attributable to higher prices in the current year and the effects of
the provincial sliding-scale Crown royalty structure, which imposes higher
royalty rates at higher commodity prices.


<PAGE>

OPERATING EXPENSES

-------------------------------------------------------------------------------
Years ended December 31,
($000s, except where noted)                   2003        2002        2001
-------------------------------------------------------------------------------

E&P activities                                 $52,733      $45,546    $40,222
MPP (recovery)                                    (745)          --         --
-------------------------------------------------------------------------------
Total operating expenses                       $51,988      $45,546    $40,222

E&P operating expenses per boe ($/boe)         $  5.65      %  4.96    $  4.71
-------------------------------------------------------------------------------

On a unit-of-production basis, oil and natural gas operating costs were
$5.65/boe, a 14% increase from operating costs per boe in 2002. The major
contributors to this increase were the overall rise in the cost of goods and
services in the oil and natural gas industry, additional field staff required
for expanding operations and higher energy costs.

GENERAL AND ADMINISTRATIVE EXPENSES

--------------------------------------------------------------------------------
Years ended December 31,
($000s, except where noted)                           2003       2002       2001
--------------------------------------------------------------------------------

E&P general and administrative expense              $16,820   $13,456   $10,085
Capitalized general and administrative expense       (3,321)   (2,689)   (2,543)
--------------------------------------------------------------------------------
Operating recoveries                                 (4,828)   (3,611)   (3,503)
--------------------------------------------------------------------------------
Net general and administrative expense               11,992     9,845     6,582
MPP general and administrative expense                  214        --        --
--------------------------------------------------------------------------------
Total general and administrative expense            $12,206   $ 9,845   $ 6,582

Net E&P general and administrative per boe ($/boe)  $  1.29   $  1.07   $  0.77
--------------------------------------------------------------------------------

On a boe basis, net oil and gas G&A costs were $1.29, a 21% increase from
$1.07/boe incurred in 2002. Additional full-time employees required due to the
expanded activities of the Company, additional regulatory and reporting related
costs and higher insurance costs contributed to increased G&A in 2003.

INTEREST EXPENSE

--------------------------------------------------------------------------------
Years ended December 31,
($000s)                                          2003         2002        2001
--------------------------------------------------------------------------------

Interest expense                               $ 29,230    $ 20,130    $ 12,863
Average debt outstanding                       $339,190    $265,605    $203,410
--------------------------------------------------------------------------------

Interest expense increased in 2003 due to higher overall debt levels. The
average debt outstanding rose in 2003 as the Company increased the amount drawn
on its syndicated credit facility to fund MPP's acquisition and expansion of the
Mazeppa and Gladys gas plants and related infrastructure. Additionally, debt
increased as total capital expenditures in 2003 exceeded the current year's cash
flow.


<PAGE>

NETBACKS

The following netbacks represent the financial results of the Company's E&P
segment, as summarized in Note 4 to the consolidated financial statements. MPP
activities are excluded.

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
YEARS ENDED DECEMBER 31,                                       2003                    2002       2001
-----------------------------------------------------------------------------------------------------------
                                                 NATURAL       CRUDE        TOTAL
                                                   GAS        OIL AND
                                                               NGLS
-----------------------------------------------------------------------------------------------------------
                                                 ($/MCF)      ($/BBL)     ($/BOE)     ($/boe)      ($/boe)
-----------------------------------------------------------------------------------------------------------
<S>                                                <C>         <C>         <C>         <C>         <C>
Realized price                                     $6.10       $35.11      $36.25      $23.95      $28.68
Royalties, net                                     (1.48)       (8.84)      (8.84)      (5.17)      (6.55)
Operating expenses                                 (0.93)       (5.65)      (5.65)      (4.96)      (4.71)
-----------------------------------------------------------------------------------------------------------
Field operating netback excluding hedge            $3.69       $20.62      $21.76      $13.82      $17.42
Financial hedge                                    (0.09)       (0.72)      (0.59)         --          --
-----------------------------------------------------------------------------------------------------------
Netback including hedge                            $3.60       $19.90      $21.17      $13.82      $17.42
-----------------------------------------------------------------------------------------------------------

General and administrative                                                  (1.29)      (1.07)      (0.77)
Interest                                                                    (3.13)      (2.19)      (1.51)
Capital taxes                                                               (0.26)      (0.17)      (0.16)
-----------------------------------------------------------------------------------------------------------
Cash flow netback                                                          $16.49      $10.39      $14.98
-----------------------------------------------------------------------------------------------------------

<CAPTION>
DEPLETION, DEPRECIATION AND ASSET RETIREMENT COSTS
-----------------------------------------------------------------------------------------------------------
Years ended December 31,
($000s, except where noted)                                                 2003        2002        2001
-----------------------------------------------------------------------------------------------------------
<S>                                                                       <C>         <C>         <C>
E&P activities                                                            $60,631     $55,473     $50,283
MPP                                                                         1,118          --          --
-----------------------------------------------------------------------------------------------------------
Total expense                                                             $61,749     $55,473     $50,283

E&P depletion and depreciation expense per boe ($/boe)                    $  6.50     $  6.05     $  5.89
-----------------------------------------------------------------------------------------------------------
</TABLE>

Capital expenditures in the current year, future capital expenditures relating
to the development of proved non-producing reserves and the adoption of the
asset retirement obligations accounting policy increased the Company's depletion
base and depletion expense in 2003.

TAXES

CURRENT TAXES

Current taxes include federal large corporations tax ("LCT"). In 2003, LCT
increased approximately $1 million over 2002 due to an increase in the Company's
capital base upon which the LCT is calculated. This tax is non-deductible and
increases as the capital resources of the Company increase. Also included in
current taxes is $800,000 resulting from reassessment of 2000 income taxes
relating to the reclassification of exploration expenses.


<PAGE>

FUTURE INCOME TAX EXPENSE

The Company's future income taxes were $20 million in 2003, comparable to $19
million in 2002. Earnings before income taxes increased significantly in 2003
over 2002, however, future income taxes in 2003 are approximately $1 million
less than 2002 as a result of a $37 million future tax recovery resulting from a
decrease in statutory income tax rates.

TAX POOLS

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

-------------------------------------------------------------------------------
                                                     AVAILABLE        MAXIMUM
                                                      BALANCE          ANNUAL
As at January 1, 2004                                 ($000s)        DEDUCTION
-------------------------------------------------------------------------------
Non-capital losses                                    $  2,708          100%
Canadian exploration expense                            26,847          100%
Canadian development expense                            98,980          30%
Canadian oil and natural gas property expense          166,895          10%
Undepreciated capital cost                              95,508        4%-100%
-------------------------------------------------------------------------------
Total                                                 $390,938
-------------------------------------------------------------------------------

The Company may be marginally cash taxable in 2004, depending upon the nature
and level of capital expenditures and commodity prices.

LIQUIDITY AND CAPITAL RESOURCES

The Company believes its existing credit facilities and capital resources are
sufficient to support its capital investment programs and future growth
prospects, in addition to enabling the Company to meet all other current and
expected financial requirements.

The capitalization of the Company at December 31, 2003 consists primarily of
$357 million of shareholders' equity, $213 million senior term notes (U.S. $165
million) and $165 million drawn on the Company's syndicated credit facility,
including the $65 million advanced to MPP to fund the purchase of the Mazeppa
and Gladys gas plants and expand the facilities. Total debt outstanding at
year-end, net of working capital, was $353 million.

Compton expects funds generated from operations, $30 million of minor
non-operated property dispositions, and funds available under the Company's
existing bank credit facilities, will be sufficient to finance operations and
planned capital expenditures of $200 million for 2004. However, the Company's
capital expenditure budget can be adjusted as required. During 2003, the Company
renewed its credit facilities with its syndicate of Canadian lenders. The
facility was set at $185 million, although a borrowing base of $240 million was
established by syndicate members.


CONTRACTUAL OBLIGATIONS

As part of normal business, the Company entered into arrangements and incurred
obligations that will impact the Company's future operations and liquidity, some
of which are reflected as


<PAGE>

liabilities in the consolidated financial statements. Principal commitments of
the Company are in the form of debt repayments, asset retirement costs, and
lease commitments relating to office space. The following table summarizes the
Company's contractual obligations.

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------
As at December 31,                                           PAYMENTS DUE BY PERIOD
($000s)                                LESS THAN 1 YEAR       1-3 YEARS   4-5 YEARS     AFTER 5 YEARS
------------------------------------------------------------------------------------------------------
<S>                                    <C>                   <C>          <C>           <C>
Capital lease obligations                        $   36          $   91      $   --          $     --
Operating leases                                  1,622           4,097          --                --
Office rent                                       1,452             481          --                --
Other long term obligations                          --              --          --           213,246
------------------------------------------------------------------------------------------------------
TOTAL                                            $3,110          $4,669      $   --          $213,246
------------------------------------------------------------------------------------------------------
</TABLE>

The Company intends to and has the ability to extend the term of its current
borrowings of $165 million on an outgoing basis under its syndicated credit
facility and therefore repayment of the facility is not included in the schedule
of contractual obligations above.

OPERATING RESULTS

In 2003, the Canadian Securities Administrators adopted National Instrument
51-101, "Standards of Disclosure for Oil and Gas Activities". These standards
require certain information to be filed on SEDAR, "System for Electronic
Disclosure Analysis and Retrieval" and are intended to ensure that all public
oil and natural gas companies disclose similar information prepared on the same
basis. Compton has filed the required Form NI 51-1O1F1 as part of its Annual
Information Form ("AIF") which is available on both the SEDAR website and
Compton's website. The AIF is very comprehensive, therefore certain information
has been extracted with respect to operations and presented in the following
sections. All such information is consistent with the Form NI 51-101F1 filing.


UNDEVELOPED LAND

In 2003, Compton continued to expand its land base in its core areas. The
Company's total land position at December 31, 2003 consisted of 1,080,798 net
acres. Undeveloped land increased to 767,364 net acres, sufficient to provide
the Company with approximately five years of internal drilling prospects. Land
acquisitions during 2003 occurred primarily in the Company's core areas in
Southern and Central Alberta. The Company has an average 74% working interest in
its undeveloped land base.


<PAGE>

Compton's undeveloped land holdings are as follows.

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------
AS AT DECEMBER 31,                                  UNDEVELOPED ACRES              UNDEVELOPED SECTIONS
AREA                                              GROSS            NET             GROSS            NET
---------------------------------------------------------------------------------------------------------
<S>                                            <C>              <C>             <C>             <C>
Southern Alberta                                  480,859        399,736             751             625
Central Alberta                                   284,696        181,801             445             284
Peace River Arch                                  136,713         93,608             213             146
Northern Alberta                                   96,748         74,733             151             117
Other                                              43,786         17,486              69              27
---------------------------------------------------------------------------------------------------------
DECEMBER 31, 2003 TOTAL                         1,042,802        767,364           1,629           1,199
---------------------------------------------------------------------------------------------------------
December 31, 2002 Total                         1,042,923        742,465           1,630           1,160
December 31, 2001 Total                           962,259        700,695           1,504           1,095
---------------------------------------------------------------------------------------------------------
</TABLE>

CAPITAL EXPENDITURES

The Company continued to invest in land, production facilities and exploratory
drilling necessary for future growth. Total capital expenditures in the current
year were $220 million, excluding the MPP midstream assets, a 42% increase from
the prior year.

Drilling and completions expenditures increased 68%, as the Company drilled
almost double the number of wells in 2003 as in 2002. Spending on land and
seismic increased from the previous year. Land prices in Alberta are currently
higher than historical averages due to increased competition in the oil and
natural gas industry. Facilities expenditures more than doubled from 2002,
consistent with increased drilling activity and compression requirements
associated with the tie-in of lower pressure Belly River wells.

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------
Years ended December 31,                   2003                    2002                    2001
-------------------------------------------------------------------------------------------------------
                                      ($000S)      %          ($000s)      %          ($000s)      %
-------------------------------------------------------------------------------------------------------
<S>                                   <C>          <C>         <C>          <C>        <C>        <C>
Drilling and completions               $126,308     57         $ 75,369      48        $ 84,658    44
Land and seismic                         37,128     17           29,096      19          25,883    14
Facilities                               46,068     21           21,714      14          27,643    15
Acquisitions, net                        11,224      5           28,929      19          22,614    11
-------------------------------------------------------------------------------------------------------
Sub-total, E&P                          220,728    100          155,108     100         160,798    84
Corporate acquisitions                       --     --               --      --          29,669    16
-------------------------------------------------------------------------------------------------------
Sub-total                               220,728    100          155,108     100         190,467   100
MPP                                      64,755                      --                      --
-------------------------------------------------------------------------------------------------------
Total                                  $285,483                $155,108                $190,467
-------------------------------------------------------------------------------------------------------
</TABLE>

Compton has budgeted $200 million for capital expenditures in 2004. The areas of
spending will be similar to 2003, excluding MPP.

DRILLING ACTIVITY

Compton drilled 168 gross (134 net) wells in 2003 with an 83% success rate,
compared with 87 gross (64 net) wells drilled in 2002. Drilling activity in 2003
increased primarily in the Company's Southern and Central Alberta core areas.
The Company drilled 30 additional wells targeting Belly River sands and six
additional wells targeting the Basal Quartz zone in Southern


<PAGE>

Alberta in 2003. In Central Alberta, 14 additional wells were drilled into the
Company's Niton lands and six additional wells were drilled at Thornbury,
compared to 2002 drilling. The remaining increase in drilling was evenly
distributed across Compton's core areas.

Of the 168 wells drilled in 2003, 43% were classified as exploratory wells and
57% were classified as development wells. Seven of the wells drilled are
standing cased wells and are awaiting completion and testing. These wells are
not included in the following table.

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
YEARS ENDED DECEMBER 31,    NATURAL GAS       OIL           D&A          TOTAL          NET       SUCCESS
AREA
-----------------------------------------------------------------------------------------------------------
<S>                         <C>               <C>           <C>          <C>           <C>        <C>
Southern Alberta                82             4             13            99           84          86%
Central Alberta                 26             2             5             33           18          66%
Peace River Arch                 7             12            10            29           22          87%
-----------------------------------------------------------------------------------------------------------
2003 TOTAL                      115            18            28           161           129         83%
-----------------------------------------------------------------------------------------------------------

2002 Total                      64             14            9             87           64          90%
2001 Total                      60             12            23            95           71          76%
-----------------------------------------------------------------------------------------------------------
</TABLE>

RESERVES

Compton engaged the international, integrated petroleum engineering and
geological consulting firm of Netherland Sewell & Associates, Inc. ("Netherland
Sewell") as independent reserve evaluators for Compton's reporting period ending
on December 31, 2003. Netherland Sewell's evaluation, conducted in accordance
with the stringent new standards of National Instrument 51-101, "Standards of
Disclosure for Oil and Gas Activities" ("NI 51-101") confirmed Compton's long
life, predominately natural gas weighted reserve base.

The Company's proved reserves, after production, increased 3% to 85 million boe.
Proved plus probable reserves, after production, increased 15% to 119 million
boe, compared to 2002 established reserves.

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------
                                       CRUDE OIL(1)       NATURAL GAS(1)        NGL'S(1)           TOTAL(1)
AS AT DECEMBER 31,                   GROSS      NET       GROSS     NET     GROSS    NET       GROSS      NET
                                     (MBBL)    (MBBL)     (BCF)    (BCF)    (MBBL)  (MBBL)     (MBOE)    (MBOE)
---------------------------------------------------------------------------------------------------------------
<S>                                  <C>       <C>        <C>      <C>    <C>       <C>       <C>      <C>
PROVED:
    Developed producing               6,530     6,059      322      263    6,592     4,957     66,806   54,849
    Developed non-producing             163       159       32       24      575       375      5,996    4,534
    Undeveloped                       2,494     1,945       49       38    1,120       784     11,825    9,062
---------------------------------------------------------------------------------------------------------------
TOTAL PROVED                          9,187     8,163      403      325    8,287     6,116     84,627   68,445
PROBABLE                              2,847     2,016      165      135    3,741     2,801     34,136   27,317
---------------------------------------------------------------------------------------------------------------
TOTAL PROVED PLUS PROBABLE           12,034    10,179      568      460   12,028     8,917    118,763   95,762
---------------------------------------------------------------------------------------------------------------
</TABLE>

(1)  Does not include royalty interest equivalent barrels.


<PAGE>

<TABLE>
<CAPTION>
RESERVE RECONCILIATION (NET AFTER ROYALTIES)
---------------------------------------------------------------------------------------------------------------
                                 CRUDE OIL AND NGL'S (1)                       NATURAL GAS (1)
---------------------------------------------------------------------------------------------------------------
                           NET PROVED  NET PROBABLE     NET PROVED     NET PROVED  NET PROBABLE     NET PROVED
                             (MBBL)       (MBBL)      PLUS PROBABLE     (MMCF)       (MMCF)       PLUS PROBABLE
                                                         (MBBL)                                        (MMCF)
---------------------------------------------------------------------------------------------------------------
<S>                        <C>         <C>            <C>             <C>          <C>            <C>
December 31, 2002             11,884        4,116        16,000         310,419       72,512         382,931
Extensions                     1,397           --         1,397           9,940          226          10,166
Improved recovery                810          139           949           6,595         (293)          6,302
Technical revisions              604         (923)         (319)        (10,443)         861          (9,582)
Discoveries                      661        1,180         1,841          37,593       62,670         100,263
Acquisitions                     404           --           404           2,333           --           2,333
Economic factors                 344          304           648              86         (629)           (543)
Production                    (1,824)          --        (1,824)        (31,568)          --         (31,568)
-------------------------------------------------------------------------------------------------------------
December 31, 2003             14,280        4,816        19,096         324,955      135,347         460,302
-------------------------------------------------------------------------------------------------------------
</TABLE>

(1)  Does not include royalty interest equivalent barrels.

Compton's proved plus probable reserves were evaluated at over $1 billion,
8% DCF or $895 million, 10% DCF.

<TABLE>
<CAPTION>
NET PRESENT VALUE OF RESERVES, FORECAST PRICES AND COSTS

--------------------------------------------------------------------------------------
                                          FUTURE NET REVENUE BEFORE INCOME TAXES (1)
As at December 31, 2003                             DISCOUNTED AT A RATE OF
                                       -----------------------------------------------
($000's)                                       0%                8%            10%
--------------------------------------------------------------------------------------
<S>                                        <C>              <C>              <C>
PROVED
    Producing                              $1,193,296       $ 622,778        $564,889
    Non-producing                             102,776          58,159          52,574
    Undeveloped                               218,206          88,995          75,136
--------------------------------------------------------------------------------------
                                           $1,514,278       $ 769,932        $692,599
TOTAL PROVED
Probable                                      612,247         241,515         202,551
--------------------------------------------------------------------------------------
TOTAL PROVED PLUS PROBABLE                 $2,126,525      $1,011,447        $895,150
--------------------------------------------------------------------------------------
</TABLE>

(1)  As an independent reserves evaluator, Netherland Sewell does not provide
     price forecasts. April 1, 2004 pricing forecasts prepared by McDaniel &
     Associates Consultants Ltd. were utilized in determining the future net
     revenues presented above. These forecasts are below current forward prices.


The net present value should not be considered the current market value of the
Company's reserves or the costs that would be incurred to obtain equivalent
reserves.


<PAGE>

FINDING & DEVELOPMENT COSTS

Finding, development and acquisition ("FD&A") costs associated with the 2003
exploration and development program, calculated in accordance with NI 51-101 and
including revisions and changes in future capital were $20.91/boe on a proved
basis and $14.11/boe on a proved plus probable basis. Excluding acquisitions,
finding and development ("F&D") costs were $21.71/boe proved and $14.20/boe
proved plus probable.

It should be noted that the aggregate of the exploration and development costs
incurred in 2003 and the change during the year in estimated future development
costs, generally will not reflect total F&D costs related to reserves additions
for the year.

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------
($/boe)                                                 2003        2002        2001       3 year      5 year
                                                                                          Average     Average
--------------------------------------------------------------------------------------------------------------
<S>                                                    <C>          <C>        <C>         <C>         <C>
F&D costs, proved                                      $21.71       $8.16      $10.78      $12.53      $12.18
F&D costs, proved plus probable (1)                    $14.20       $5.79      $11.76      $10.22      $ 9.86

FD&A costs, proved                                     $20.91       $8.15      $ 9.92      $11.80      $10.94
FD&A costs, proved plus probable (1)                   $14.11       $6.08      $10.18      $ 9.87      $ 9.21
--------------------------------------------------------------------------------------------------------------
</TABLE>

(1)  Calculated using proved plus risked probable (established) reserves for
     2002 and 2001.

ADDITIONAL DISCLOSURES

CRITICAL ACCOUNTING ESTIMATES

Critical accounting estimates require Management to make assumptions regarding
matters that are highly uncertain at the time the estimate is made and have a
material impact on the financial condition of the Company. A comprehensive
discussion of the Company's significant accounting policies may be found in
Notes 1 and 2 to the consolidated financial statements.


OIL AND NATURAL GAS RESERVES

Compton's oil and natural gas reserves were evaluated and reported on by the
independent petroleum engineering and geological consulting firm of Netherland
Sewell, which evaluated 100% of the Company's 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 depletion and depreciation expense, asset
retirement costs and impairment expense, which could possibly have a material
impact on consolidated net income.

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


<PAGE>

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 2003, Compton incurred $62 million of depletion and depreciation. If the
proved reserves of the Company were to vary by 5%, the depletion and
depreciation expense would change by approximately $800,000 and consolidated net
income after tax would change by approximately $480,000.

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 balance sheet. 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. 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 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.

Assumptions about reserves and future prices are required to calculate future
net cash flows. The assumptions made to estimate reserves have been previously
discussed above. There is significant uncertainty regarding forecasting future
commodity prices due to economic and political uncertainty. 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

Compton is required to remove production equipment, batteries, pipelines, gas
plants and restore land at the end of oil and natural gas operations. The
Company estimates these costs in accordance with existing laws, contracts and
other policies. These obligations are initially measured at fair value, which is
the discounted future value of the liability. This fair value is also
capitalized as part of the cost of the related assets and amortized over the
useful life of the assets.

An annual increase to the liability will be recorded to recognize the passage of
time and the impending settlement of the obligation. The liability will be
impacted by any changes in the assumptions used in the asset retirement
obligation ("ARO") calculation. Adjustments to the estimate will be recorded as
an accretion expense on the consolidated statements of earnings.

In the future, the Company's depletion expense will be reduced since the
discounted future statements value of the liability will be depleted rather than
the undiscounted value previously depleted. The lower depletion expense will be
offset, by the addition of the accretion expense.


<PAGE>

An independent environmental consulting firm was hired to assist management in
the estimation of asset removal costs. The ARO cost calculations were derived
from a combination of actual third party cost quotes, Alberta Energy and Utility
Board cost models and typical industry experience and practices. The deemed ARO
liability for wells and facilities is the sum of the calculated abandonment and
reclamation liabilities adjusted for designated status as active, inactive,
abandoned, or problem site. Information regarding environmental remediation
costs and other liability issues for site-specific concerns were derived from a
review of historical audits and assessment reports for sites and facilities. An
inflation rate of 2.0% and a credit adjusted risk free rate of 10.6% was used in
Compton's fair value calculation.

Estimating future asset removal costs is difficult and requires Management to
make estimates and judgments because most of the removal obligations are many
years in the future and contracts and regulations often have vague descriptions
of what constitutes removal. Asset removal technologies and costs are constantly
changing, as well as regulatory, political, environmental, safety and public
relations considerations. As a result, it is not possible to provide a
reasonable analysis of the impact that changes in removal costs would have on
the asset retirement obligation. If the inflation rate assumed in the ARO
calculation changed by 1%, the ARO obligation would vary by $3 million.
Additionally, a 1% change in the credit adjusted risk free interest discount
rate would result in a $2 million change to the ARO liability.

CHANGES IN ACCOUNTING POLICY

STOCK BASED COMPENSATION

In November 2003, Canadian Institute of Chartered Accountants ("CICA") amended
Handbook Section 3870, "Stock Based Compensation" requiring companies to use the
fair value method of accounting for stock based payments. Under this method the
fair value of stock based compensation, such as stock options, is recognized as
a compensation expense over the vesting period. Adoption of the amended section
was required on or after January 1, 2004, however Compton chose to early adopt
effective January 1, 2003.

Section 3870 provides alternative methods of transition to the fair value
method, including:

   o  retroactive application, with prior period restatement;
   o  retroactive application, with adjustment of opening retained earnings; or
   o  prospective application, with no restatement of prior years.

The difference of the impact on the financial condition of the Company in 2003
between the alternative adoption methods was immaterial. Compton elected to
apply the amended standard prospectively and recognized $1 million of
compensation expense for options granted during 2003. Had the fair value method
been adopted retroactively, it would have resulted in an impact on net income as
outlined in Note 10 to the consolidated financial statements.

ASSET RETIREMENT OBLIGATIONS

In December 2002, the CICA approved Handbook Section 3110, "Asset Retirement
Obligations," requiring recognition for asset retirement obligations and costs
associated with the Company's oil and gas properties, plants and equipment.
Adoption of the new Section is required on or after January 1, 2004, however
Compton chose to early adopt effective January 1, 2003.


<PAGE>

Compton estimates the undiscounted amount of cash flow required to settle the
asset retirement obligation is approximately $135 million. A credit-adjusted
risk free rate of 10.6% was used to calculate the carrying value of the asset
retirement obligation.

As the result of adopting this Section, all prior periods have been restated.
The change results in a decrease in net earnings of $1 million for the year
ended December 31, 2003 (2002 - $1 million, 2001 - $1 million). The effect of
this change on the December 31, 2003 consolidated balance sheet is an increase
in net capital assets of $7 million (2002 - $7 million), recognition of the
asset retirement obligation of $17 million (2002 - $17 million), elimination of
the site restoration provision of $1 million (2002 - $2 million), decrease in
future income taxes of $3 million (2002 - $3 million) and a decrease in
consolidated retained earnings of $6 million (2002 - $5 million, 2001 - $5
million).

HEDGE ACCOUNTING

In December 2001, the CICA modified Accounting Guideline 13, "Hedging
Relationships" ("AcG-13"). The Guideline establishes certain conditions where
hedge accounting may be applied, effective for fiscal years beginning on or
after July 1, 2003. Additionally, the CICA's Emerging Issues Committee ("EIC")
amended their guidance in EIC 128, "Accounting for Trading, Speculative or Non
Trading Derivative Financial Instruments," to require that all derivative
instruments that do not qualify for hedge accounting or are not designated as
hedges, be recorded on the balance sheet with changes in fair value recognized
in earnings.

Compton adopted the modified Guideline effective January 1, 2004 and elected not
to designate any of its current risk management activities as accounting hedges
under AcG-13. The Company will account for all derivatives using the
mark-to-market accounting method. The impact on the Company's consolidated
financial statements at January 1, 2004 is an increase in liabilities of $11
million and a deferred loss of $11 million which will be recognized as the
contracts expire.

IMPAIRMENT TEST

In September 2003, the CICA approved Accounting Guideline 16, "Oil and Gas
Accounting - Full Cost." The new Guideline modifies the way the impairment test
is performed and requires that costs centers be tested for recoverability using
undiscounted future cash flows from proved reserves plus the cost of undeveloped
properties. When the carrying amount of the asset is not recoverable, the asset
would be written down to its fair value.

The Guideline is effective for fiscal years beginning on or after January 1,
2004; and Compton chose to early adopt in the fourth quarter of 2003. There is
no impact on the carrying value of the Company's assets as a result of applying
the new guideline.

VARIABLE INTEREST ENTITIES

 In December 2003, the Financial Accounting Standards Board in the United States
issued Interpretation 46 (revised December 2003) "Consolidation of Variable
Interest Entities, an interpretation of Accounting Research Bulletin No. 51"
("FIN 46R"). The standard requires that variable interest entities be
consolidated by their primary beneficiary. The standard is effective for the
first period ending after December 15, 2003. In Canada, the Accounting Standards
Board issued a draft guideline proposing amendments to Accounting Guideline
AcG-15, "Consolidation of Variable Interest Entities" which is expected to be
substantially in accordance with the United States standard. Once finalized, the
amendments would harmonize the guideline with the


<PAGE>

corresponding United States standard. The amended guideline remains effective
for annual and interim periods beginning on or after November 1, 2004.

The Company adopted the provisions of FIN 46R as of December 31, 2003. The
effects of adopting FIN 46R on the consolidated financial statements are
summarized in Note 4.

IMPACT ON NET INCOME OF CHANGE IN ACCOUNTING POLICIES

The implementation of new accounting polices relating to asset retirement
obligations in 2003, resulted in the restatement of previously reported net
earnings.

The following table shows the impact of the new accounting policies on net
income.

------------------------------------------------------------------------------
Years ended December 31,                      2003          2002        2001
($000s)
------------------------------------------------------------------------------

(Decrease) in net earnings, related to:
   Stock based compensation                $   (800)      $   --      $    --
   Asset retirement obligations                (700)        (500)        (600)
   Hedge accounting                              --           --           --
   Ceiling test                                  --           --           --
------------------------------------------------------------------------------
Total impact on net earnings               $ (1,500)      $ (500)     $  (600)
------------------------------------------------------------------------------

FINANCIAL CONDITIONS AND RISKS

Compton's operations are subject to risks normally associated with the oil and
natural gas industry. The Company is exposed to financial risks including
commodity prices and expenditure costs shifting due to changes in market
conditions. Commodity prices are driven by supply, demand and market forces
outside the Company's influence. However, the Company's product mix is
diversified to minimize exposure to any one commodity's price movements. Sales
of oil and natural gas are aimed at various markets to avoid undue exposure to
any one market. When appropriate, Compton ensures that parental guarantees or
letter of credit are in place to minimize the impact in the event of default.

Compton monitors and focuses its expenditures to reflect price and production
changes. Compton continuously scrutinizes market conditions and opportunities.
From time to time the Company will employ financial instruments to manage
exposure related to Canada/U.S. exchange rates and commodity prices.

The Company has commodity and fixed-price contracts outstanding as outlined in
the Financial Instruments section of this discussion and analysis. The Company
considers longer-term contracts with suppliers, where appropriate, to mitigate
shifts in costs resulting from changes in industry and market conditions.
Compton has no control over government intervention or taxation levels on the
industry.

It is likely that in the future the Company will be required to raise additional
capital via debt and/or equity financings in order to fully realize its
strategic goals and business plans. Compton's ability to raise additional
capital will depend upon a number of factors, such as general economic and
market conditions that are beyond its control. If Compton is unable to obtain
additional financing or to obtain it on favorable terms, the Company might be
required to forego attractive business opportunities. Compton is committed to
maintaining a strong balance sheet, combined


<PAGE>

with a flexible capital expenditure program that can be adjusted to capitalize
on or reflect acquisition opportunities or a tightening of liquidity sources.

FINANCIAL INSTRUMENTS

From time to time, Compton enters into hedge transactions to manage fluctuations
in commodity prices and foreign currency. The Company does not participate in
derivative or other financial instruments for trading purposes and commodity
price contracts may not exceed 50% of non-contracted production. Management
considers an abundance of information from a variety of sources before entering
into a financial transaction. However, the inherent risk of an erroneous
decision remains. The Audit, Risk and Committee of the Board of Directors
regularly reviews the Company's hedging strategies and transactions to mitigate
this risk.

INTEREST RATE RISK MANAGEMENT

The Company entered into an interest rate swap arrangement upon the closing of
its U.S. senior notes offering in May 2002. The arrangement converts fixed rate
U.S. dollar denominated debt to floating rate Canadian dollar denominated debt
and protects Compton against fluctuations in the Canadian U.S. exchange rate.
The terms of the swaps correlate with the terms of the debt agreement and has
resulted in an effective interest rate of 7.85% (2002 - 7.65%). At December 31,
2003 there was an unrealized hedge loss of $9 million (2002 - $15 million gain),
as calculated on a mark-to-market basis by the issuer of the instrument.

FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT

The Company is exposed to fluctuations in the exchange rate between the Canadian
dollar and the U.S. dollar. Crude oil and to a large extent natural gas prices
are based upon reference prices denominated in U.S. dollars, while the majority
of the Company's expenses are denominated in Canadian dollars. When appropriate,
the Company enters into agreements to fix the exchange rate of Canadian dollars
to U.S. dollars in order to manage the risk. During the year a gain of $2
million was realized and included in revenue (2002 - $nil). At December 31,
2003, all swaps had expired and the Company has not entered into any
arrangements for 2004.

COMMODITY PRICE RISK MANAGEMENT

The Company enters into commodity price contracts to hedge anticipated sales of
oil and natural gas production to protect cash flows for its capital expenditure
programs. 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. However, net open positions may exist, or
may be established to take advantage of market conditions. Oil and gas revenues
for the year ended December 31, 2003 include losses of $8 million (2002 - $1
million gain; 2001 - $4 million gain) on these transactions. At December 31,
2003 there was an unrealized gain of $2 million on commodity hedges, as
calculated on a mark-to-market basis by the issuer of the instrument.

As at March 31, 2004, the Company had incurred a realized loss of $1 million and
an unrealized mark-to-market loss of $5 million on commodity hedges.


<PAGE>

<TABLE>
<CAPTION>
Hedging transactions in 2004 are as follows:

---------------------------------------------------------------------------------------------------------------
   COMMODITY       TYPE            TERM                        AMOUNT            AVERAGE PRICE         INDEX
---------------------------------------------------------------------------------------------------------------
<S>                           <C>                           <C>                <C>                     <C>
NATURAL GAS
                 Collars      Jan - Mar '04                 30,000 GJ          Cdn.$5.34 - $7.56       AECO
                 Collars      Apr  - June '04               30,000 GJ          Cdn.$4.88 - $6.48       AECO
                 Collars      July - Oct '04                20,000 GJ          Cdn.$4.88 - $6.50       AECO
                 Collars      Nov - Dec `04                  5,000 GJ          Cdn.$5.00 - $7.10       AECO
CRUDE OIL
                 Collars      Jan 2003 - Dec 2004            1,500 bbls/d      U.S.$25.83 - $29.37     WTI
---------------------------------------------------------------------------------------------------------------
</TABLE>

SELECTED QUARTERLY INFORMATION

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

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 2003                             THREE MONTHS ENDED                   YEAR ENDED
----------------------------------------------------------------------------------------------------------------------
($000s, except where noted)                  MARCH 31         JUNE 30        SEPT 30          DEC 31        DEC 31
----------------------------------------------------------------------------------------------------------------------
<S>                                        <C>             <C>             <C>             <C>             <C>
Total revenue                              $   92,444      $   83,305      $   76,762      $   82,182      $   334,693
Cash flow                                  $   48,160      $   39,888      $   34,220      $   32,625      $   154,893
Cash flow/share (basic)                    $     0.41      $     0.34      $     0.29      $     0.28      $      1.33
Cash flow/share (diluted)                  $     0.39      $     0.33      $     0.28      $     0.27      $      1.27
Net income                                 $   31,894      $   64,750      $   10,455      $   11,781      $   118,880
Net income/share (basic)                   $     0.27      $     0.56      $     0.09      $     0.10      $      1.02
Net income/share (diluted)                 $     0.26      $     0.53      $     0.09      $     0.10      $      0.97
Average production (boe/d)                     25,853          25,659          24,219          26,484           25,552
Average pricing ($/boe)                    $    39.73      $    35.68      $    34.02      $    33.28      $     35.66
----------------------------------------------------------------------------------------------------------------------
</TABLE>

(1)  Restated for inclusion of Mazeppa Processing Partnership.

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 2003                             THREE MONTHS ENDED                   YEAR ENDED
----------------------------------------------------------------------------------------------------------------------
($000s, except where noted)                  MARCH 31         JUNE 30        SEPT 30(1)       DEC 31        DEC 31
----------------------------------------------------------------------------------------------------------------------
<S>                                        <C>             <C>             <C>             <C>             <C>
                                           $   42,548      $   54,018      $   50,889      $   72,332      $   219,787
Total revenue
Cash flow                                  $   18,393      $   23,513      $   19,624      $   34,542      $    96,072
Cash flow/share (basic)                    $     0.16      $     0.21      $     0.17      $     0.30      $      0.85
Cash flow/share (diluted)                  $     0.16      $     0.20      $     0.17      $     0.29      $      0.81
Net income (1)                             $    3,317      $   10,872      $    1,292      $    2,831      $    18,312
Net income(1)/share (basic)                $     0.03      $     0.10      $     0.01      $     0.03      $      0.16
Net income(1)/share (diluted)              $     0.03      $     0.09      $     0.01      $     0.02      $      0.16
Average production (boe/d)                     24,443          24,737          24,782          26,567           25,137
Average pricing ($/boe)                    $    19.34      $    24.00      $    22.32      $    29.59      $     23.95
----------------------------------------------------------------------------------------------------------------------
</TABLE>

(1)  Restated for changes in accounting policies adopted in 2003. See
     consolidated financial statements.

In 2003, strong overall commodity prices and the decline of the Company's
portion of natural gas production dedicated to aggregators to 16%, resulted in
higher realized prices and increased total revenue. Additionally, an unrealized
foreign exchange gain on the translation of the Company's U.S. denominated debt
in the first and second quarters of 2003 and a recovery of future income taxes
in the second quarter due to a reduction in federal and provincial income tax
rates on income earned from resource activities, significantly increased
quarterly net income when


<PAGE>

compared to the same quarters in 2002. The Consolidation of MPP did not have a
material impact on total revenue or net income in 2003.

Revenue in 2002 fluctuated on a quarterly basis largely due to average realized
prices. Overall commodity prices rose throughout 2002, however, approximately
35% of Compton's natural gas production was marketed through aggregator
contracts. These contracts received a price that was on average $0.94/mcf less
than prices received on non-aggregator volumes. Quarterly net income in 2002
followed the trend set by revenue, with the exception of the fourth quarter. An
$18 million future tax expense recorded in the fourth quarter decreased net
income to $3 million for the three months ended December 31, 2002.

FOURTH QUARTER 2003

Fourth quarter 2003 production increased approximately 9% from that of the
preceding 2003 quarter. This increase resulted from new production being placed
on-stream and gas plants shut-in during the third quarter for regularly
scheduled maintenance coming back on-stream.

Net income increased by 12% from the third quarter of 2003. Higher net income in
the fourth quarter of 2003 resulted from increased production volumes and
revenue. The consolidation of MPP did not have a material impact on the fourth
quarter results.

SELECTED ANNUAL INFORMATION

--------------------------------------------------------------------------------
Years ended December 31, ($000s)           2003         2002          2001
--------------------------------------------------------------------------------
Total revenue                           $  334,693   $  219,787   $  244,970
Net income                              $  118,880   $   18,312   $   55,015
Net income/share (basic)                $     1.02   $     0.16   $     0.50
Net income/share (diluted)              $     0.97   $     0.16   $     0.48
Total assets                            $1,064,320   $  823,859   $  700,622
Total long term financial liabilities   $  213,246   $  260,634   $  230,000
--------------------------------------------------------------------------------

Total assets were $1.1 billion at December 31, 2003, an increase of 29% from the
prior year, due primarily to a 31% increase in the carrying value of property
and equipment. In addition to capital expenditures of $221 million, the carrying
value of property and equipment before accumulated depletion and depreciation,
increased by $65 million relating to midstream facilities owned by MPP and an
$11 million charge for future asset retirement costs.

Total assets at December 31, 2002 were $824 million, a 19% increase from 2001
largely due to capital spending on exploration and development activities which
increased the carrying value of property and equipment.

In May 2002, the Company completed an offering of U.S. $165 million senior
notes. The proceeds were used to repay outstanding bank debt and resulted in a
net increase in total long term financial liabilities from 2001 to 2002. At
December 31, 2003, total long term debt was $213 million, down 18% from 2002 due
to a stronger year end Canadian U.S. dollar exchange rate. The amount of the
outstanding notes is restated in Canadian dollars using the year end exchange
rate.


<PAGE>

<TABLE>
<CAPTION>
TRADING AND SHARE STATISTICS

As at April 19, 2004, there were 117,217,353 common shares outstanding.
------------------------------------------------------------------------------------------------------------
                                          MAR 31,     JUNE 30,    SEPT 30,    DEC 31,      2003       2002
                                            2003        2003        2003       2003       TOTAL       Total
------------------------------------------------------------------------------------------------------------
<S>                                       <C>         <C>         <C>        <C>         <C>        <C>
Average daily trading volume (000s)       687,068     804,989     654,060    598,300     686,100    324,865
Share price ($/share)
     High                                   $5.90       $6.35       $6.35      $6.23       $6.35      $5.35
     Low                                    $4.70       $4.40       $5.48      $5.38       $4.40      $3.20
     Close                                  $4.90       $5.88       $5.70      $6.00       $6.00      $5.09
Market capitalization at December 31
($000s)                                                                                 $698,535   $591,819
Shares outstanding (000s)                                                                116,423    116,271
------------------------------------------------------------------------------------------------------------
</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.

--------------------------------------------------------------------------------