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


                      MANAGEMENT'S DISCUSSION AND ANALYSIS

1.   ADVISORIES

MANAGEMENT'S  DISCUSSION  AND  ANALYSIS  ("MD&A") IS INTENDED TO PROVIDE BOTH AN
HISTORICAL AND PROSPECTIVE  VIEW OF OUR ACTIVITIES.  THE MD&A WAS PREPARED AS AT
MARCH 23, 2007, AND SHOULD BE READ IN CONJUNCTION WITH THE AUDITED  CONSOLIDATED
FINANCIAL STATEMENTS AND RELATED NOTES FOR THE YEAR ENDED DECEMBER 31, 2006. 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 20 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.

2.   CORPORATE OVERVIEW & STRATEGY

Compton Petroleum Corporation is an independent, public company actively engaged
in the exploration  for and  development and production of natural gas,  natural
gas liquids, and crude oil in western Canada. Our activities are concentrated in
three core  geographic  areas,  primarily  in the  province of  Alberta,  in the
Western  Canada   Sedimentary   Basin.  Our  growth  and  reserve  base  results
predominantly from our exploration and development drilling programs.

Our  objective  has  been  and  remains  that of  building  an  exploration  and
development  company  capable  of  delivering   sustainable  long  term  growth.
Management  has adhered to a  consistent  strategy in pursuing  this  objective,
including:

o    concentrating  activities  in a limited  number of core areas;

o    focusing on unconventional long life natural gas reserves in large resource
     plays;

o    pursuing   growth  through  the  drill  bit,   complemented   by  strategic
     acquisitions;

o    controlling infrastructure and operatorship;  and

o    maintaining financial flexibility.

3.   RESULTS OF OPERATIONS

A.   2006 SUMMARY

o    Drilled 342 gross (274 net) wells with a 94% success  rate.

o    Achieved  annual  average  production of 33,187 boe/d,  a 13% increase from
     2005.

o    Generated cash flow from operations of $256.3 million, or $1.92 per diluted
     share.

o    Operating earnings for the year were $65.2 million.

o    Net earnings for the year were $127.4 million.

B.   CASH FLOW FROM OPERATIONS AND NET EARNINGS

--------------------------------------------------------------------------------
Years ended December 31,                     2006          2005         2004
--------------------------------------------------------------------------------
Cash flow from operations (1) ($000S)       $256,305   $278,112     $177,131
Per share: basic                             $  2.01   $      2.21  $      1.51
           diluted                           $  1.92   $      2.11  $      1.43
Net earnings ($000S)                        $127,426   $  81,326    $  63,633
Per share: basic                             $  1.00   $      0.65  $      0.54
           diluted                           $  0.95   $      0.62  $      0.51
================================================================================
(1)  Cash flow from  operations  represents  net earnings  before  depletion and
     depreciation, future income taxes, and other non-cash expenses.

                                      -1-
<PAGE>

Cash flow from  operations  in 2006 was  $256.3  million as  compared  to $278.1
million in 2005,  with lower commodity  prices more than  offsetting  production
gains. The negative effect of lower commodity prices on cash flow was reduced by
realized gains of $36 million  resulting from risk management  activities during
the year.

While cash flow from  operations  in 2006  declined from the prior year's level,
net earnings of $127.4  million in 2006 actually  increased from 2005 due to the
positive  effect of future income tax recoveries  resulting  from  reductions in
statutory  corporate  income  tax  rates  and the  unrealized  gains  from  risk
management  activities.  The impact of these items is summarized in the schedule
of Operating Earnings presented below.

C.   OPERATING EARNINGS

Operating  earnings  is  a  non-GAAP  measure  that  adjusts  net  earnings  for
non-operating  items that Management  believes reduce the  comparability  of our
underlying  financial  performance  between  periods.  The following  Summary of
Operating Earnings reconciles Net Earnings,  determined in accordance with GAAP,
to Operating  Earnings and has been prepared to provide readers with information
that is more comparable between periods.

SUMMARY OF OPERATING EARNINGS

-------------------------------------------------------------------------------
  Years ended December 31, ($000s, except
    per share amounts)                            2006        2005         2004
-------------------------------------------------------------------------------
  Net earnings, as reported                   127,426     $81,326      $63,633
  Non-operational items, after tax
    Unrealized foreign exchange (gain)            (550)     (6,339)    (11,821)
    Unrealized risk management (gain)          (18,027)     6,345        1,338
      loss
    Stock-based compensation                    5,974       3,682        2,094
    Tender costs on repurchase of
       9.90% notes                                  -      14,414            -
    Future income tax recovery due to
        income tax rate reductions            (49,655)     (5,764)      (8,359)
-------------------------------------------------------------------------------
  Operating earnings                          $65,168     $93,664      $46,885
  Per share:  basic                            $ 0.51      $ 0.75       $ 0.40
              diluted                          $ 0.49      $ 0.71       $ 0.38
===============================================================================


                                      -2-
<PAGE>

D.   REVENUE

Revenue in 2006 decreased 4% as result of a 15% decrease in realized prices,
despite a 13% increase in production volumes.

-------------------------------------------------------------------------------
Years ended December 31,                2006           2005            2004
-------------------------------------------------------------------------------

AVERAGE PRODUCTION
  Natural gas (MMCF/D)                      142             131            123
  Liquids (BBLS/D)                        9,516           7,646          6,330
-------------------------------------------------------------------------------
  Total (BOE/D)                          33,187          29,424         26,876

BENCHMARK PRICES
  NYMEX (U.S.$/MMBTU)                 $    7.26       $    8.55     $     6.09
  AECO ($/GJ)                         $
     Monthly index                         6.21       $    8.04     $     6.44
     Daily index                      $               $    8.27     $     6.18
                                           6.19
  WTI (U.S.$/BBL)                     $   66.22       $   56.56     $    41.40
  Edmonton par ($/BBL)                $   72.77       $   68.72     $    52.37

REALIZED PRICES
  Natural gas ($/MCF)                 $    6.37       $     8.42    $     6.46
  Liquids ($/BBL)                         58.53            56.04         43.21
-------------------------------------------------------------------------------
  Total ($/BOE)                       $   44.05       $    51.95    $    39.82

REVENUE ($000S)
  Natural gas                         $ 330,349       $  401,468    $  291,565
  Liquids                               203,307          156,411       100,094
-------------------------------------------------------------------------------
  Total                               $ 533,656       $  557,879    $  391,659
===============================================================================


SUMMARY OF REVENUE INCREASES FROM PRODUCTION AND PRICING

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

Reported 2005 revenue                  $401,468         $156,411    $  557,879
Increase in production volumes           26,427           39,951        66,378
Change in prices                        (97,546)           6,945       (90,601)
-------------------------------------------------------------------------------
REPORTED 2006 REVENUE                  $330,349         $203,307    $  533,656
===============================================================================

Overall  production  in 2006 rose 13% from the prior  year.  Natural gas volumes
increased 8%, while  liquids  production  increased  24% over 2005 volumes.  The
growth in liquids  production is largely the result of our ongoing  conventional
crude  oil   exploration   and   development   program  at  Cecil  and  Worsley.
Unfortunately,  the year over year decline in North American  natural gas prices
overwhelmed the growth in production volumes.

We market the majority of our natural gas  production  through a combination  of
daily and monthly  indexed  contracts  and  aggregator  contracts.  During 2006,
approximately  11% of our natural gas  production  remained  committed to longer
term aggregator contracts which realized a price that was, on average, $1.31/mcf
less than that received on non-aggregator volumes.

Our crude oil sales are priced based upon  Edmonton  postings and are  typically
sold on 30 day  evergreen  arrangements.  Natural  gas liquids are bid out on an
annual basis to obtain the most  favourable  pricing.  We sell our crude oil and
natural gas liquids  primarily  to  refineries  and  marketers  of crude oil and
natural gas liquids.

                                      -3-
<PAGE>

Periodically we enter into financial instrument contracts to hedge against price
volatility in funding our capital expenditure  programs.  This activity is fully
disclosed in the Risk Management and Financial Instrument sections of this MD&A.
At present  approximately  30% of our production is currently  hedged through to
October 31, 2007.  Depending on market conditions,  we may enter into additional
hedges  throughout the year with a goal of hedging  approximately  50% of future
production volumes before royalties.

E.   ROYALTIES

-------------------------------------------------------------------------------
Years ended December 31,
($000s, except where noted)               2006          2005          2004
-------------------------------------------------------------------------------
Crown royalties                            $100,230      $105,827      $75,477
Other royalties                              23,447        26,890       17,939
-------------------------------------------------------------------------------
Net royalties                              $123,677      $132,717      $93,416

Percentage of revenues                       23.2%          23.8%        23.9%
===============================================================================

Royalties  are paid to various  government  entities  and other land and mineral
rights owners. Virtually all crown royalties are paid to the province of Alberta
which has a royalty structure based upon commodity prices and well productivity,
with higher prices and well  productivity  attracting  higher royalty rates. Our
royalty rate in 2006, as a percentage of revenue,  decreased  slightly from 2005
as a result of lower commodity prices in 2006.

We anticipate  2007 royalty rates will remain  relatively  consistent with prior
years;  however,  this could  change as the  Alberta  government  has stated its
intent to review the current royalty regime.

F.   OPERATING EXPENSES

-------------------------------------------------------------------------------
Years ended December 31,                 2006          2005          2004
-------------------------------------------------------------------------------
Operating expenses ($000S)                 $95,462        $66,802      $55,655
Operating expenses per boe ($/BOE)         $  7.88        $  6.22      $  5.66
===============================================================================

Cost  pressures  associated  with an  industry  operating  at  maximum  capacity
resulted in increased  operating costs during 2006 particularly when measured on
a boe basis.  Specific  increases of note  include  salaries for field staff and
contract  operators  and  rising  electricity  prices.   Additionally,   liquids
production  increased  24% during the year as  compared  to the 8%  increase  in
natural gas volumes.  As the 2006 per unit  operating  expenses for liquids were
approximately $3.60 per boe greater than natural gas per unit costs, the overall
cost per boe rose to reflect the change in the oil/natural gas production mix.

With the current reduced level of activity in the industry, we are now beginning
to see indications that cost inflation is moderating. With an increased emphasis
on cost controls,  we anticipate  2007 operating  costs, on a unit of production
basis, will remain similar to those experienced in 2006.

G.   TRANSPORTATION EXPENSES

-------------------------------------------------------------------------------
Years ended December 31,                    2006          2005          2004
-------------------------------------------------------------------------------
Transportation costs ($000S)                 $12,564        $10,858      $8,595
Transportation costs per boe ($/BOE)         $  1.04        $  1.01      $ 0.87
===============================================================================

We incur charges for the  transportation  of our production from the wellhead to
the point of sale. Pipeline tariffs and trucking rates for liquids are primarily
dependent upon production location and distance from the sales point.  Regulated
pipelines  transport  natural  gas  within  Alberta  at  tolls  approved  by the
government.

                                      -4-
<PAGE>

While  higher  transportation  costs  in 2006  resulted  from a  combination  of
increased  trucking costs  associated with  additional  crude oil production and
surcharges associated with high fuel costs, the cost per boe remained relatively
constant to the prior year.

H.   GENERAL AND ADMINISTRATIVE EXPENSES

-------------------------------------------------------------------------------
  Years ended December 31,
 ($000s, except where noted)                   2006         2005         2004
-------------------------------------------------------------------------------
  General and administrative
    expenses                                  $38,321      $34,638      $20,182
  Capitalized general and
   administrative expenses                     (9,625)     (11,158)      (2,982)
  Operator recoveries                          (2,465)      (2,257)      (1,985)
-------------------------------------------------------------------------------
  Total general and administrative expenses   $26,231      $21,223      $15,215

  General and administrative per boe ($/BOE)  $  2.17      $  1.98      $  1.55
===============================================================================

Employee costs  associated  with  increased  personnel  levels,  together with a
general  increase in  remuneration  necessary  to attract  and retain  qualified
personnel in a very  competitive  industry,  were the main  contributors  to the
increase  in  general  and  administrative  expenses  in 2006.  Other  increases
included  insurance  and costs  associated  with ongoing  regulatory  compliance
requirements.  During 2006, we incurred  expenses totaling $1.1 million relating
to compliance  requirements pursuant to the U.S.  Sarbanes-Oxley Act of 2002 and
Canadian Multilateral Instrument 52-109.

I.   INTEREST AND FINANCE CHARGES

-------------------------------------------------------------------------------
Years ended December 31,
($000s, except where noted)                  2006          2005          2004
-------------------------------------------------------------------------------
Interest on bank debt, net                  $15,356       $11,520        $9,662
Interest on Senior Notes                     35,880        20,912        21,281
-------------------------------------------------------------------------------
Interest expense                             51,236        32,432        30,943
Finance charges                               2,839         2,519         2,790
-------------------------------------------------------------------------------
Total interest and finance charges          $54,075       $34,951       $33,733
-------------------------------------------------------------------------------
Total interest and finance
  charges per boe ($/BOE)                   $  4.47      $  3.25        $  3.44
===============================================================================

-------------------------------------------------------------------------------
Weighted average annual debt
($000s, except where noted)                             2006           2005
-------------------------------------------------------------------------------
Bank debt                                               $254,476      $228,381
Effective interest rate                                    5.60%           4.23%

Senior notes (US$)                                      $412,802       $179,583
Effective interest rate                                    7.64%           9.50%
===============================================================================

Interest expenses relating to bank debt in 2006 increased from the prior year as
a result of increased  borrowings  incurred to fund our 2006 capital program and
overall floating interest rate increases. The decrease in the effective interest
rate  incurred on the Senior Notes  resulted  from the  repurchase  of the 9.90%
Senior Notes issued in 2002 with a portion of the proceeds of the 7.625%  Senior
Notes issued in 2005. Our debt  instruments  are more fully described in Notes 5
and 6 to our consolidated financial statements.

J.   TENDER COSTS

-------------------------------------------------------------------------------
Years ended December 31, ($000s)                                       2005
-------------------------------------------------------------------------------
Premium payment                                                        $  7,814
Consent solicitation fee                                                  5,883
Reduction of deferred financing charges
   on repayment of 9.90% Senior Notes                                     7,053
-------------------------------------------------------------------------------
Total tender costs                                                     $ 20,750
-------------------------------------------------------------------------------

                                      -5-
<PAGE>

In November  2005, we completed a tender offer and con purchase our 9.90% Senior
Notes  due in 2009.  96% of the  Senior  Notes  were  tendered  to the offer and
purchased by the Company.  The unamortized portion of deferred financing charges
relating to the tendered portion of the 9.90% Senior Notes is included in tender
costs. The remaining 4% of the Notes were purchased in 2006 pursuant to the call
option provisions and no additional tender costs were incurred.

K.   NETBACKS

-------------------------------------------------------------------------------
                                                   2006       2005       2004
 Years ended December 31, ($/boe)
-------------------------------------------------------------------------------
 Realized price                                    $44.05     $51.95     $39.82
 Commodity hedge gain (loss)                         3.24      (0.90)     (0.93)
 Royalties                                         (10.21)    (12.36)     (9.50)
 Operating expenses                                 (7.88)     (6.22)     (5.66)
 Transportation                                     (1.04)     (1.01)     (0.87)
-------------------------------------------------------------------------------
 FIELD OPERATING NETBACK                           $28.16     $31.46     $22.86
-------------------------------------------------------------------------------
 General and administrative                         (2.17)     (1.98)     (1.55)
 Interest                                           (4.47)     (3.25)     (3.43)
 Current taxes                                          -      (0.47)     (0.28)
-------------------------------------------------------------------------------
 CASH FLOW NETBACK                                 $21.52     $25.76     $17.60
===============================================================================

L.   RISK MANAGEMENT

Our  financial  results are impacted by external  market risks  associated  with
fluctuations in commodity prices, interest rates, and the Canadian/U.S. exchange
rate. We utilize  various  financial  instruments  for  non-trading  purposes to
manage and mitigate our exposure to these risks.  Our financial  instruments are
not designated for hedge accounting,  and accordingly are recorded at fair value
on the  consolidated  balance  sheets,  with  subsequent  changes  recognized in
consolidated net earnings.

Financial   instruments   utilized  to  manage  risk  are  subject  to  periodic
settlements throughout the term of the instruments.  Such settlements may result
in a gain or loss,  which is recognized as a realized  risk  management  gain or
loss at the time of settlement.

The mark-to-market fair values of the financial  instruments  outstanding at the
end of a  reporting  period  reflect  the values of the  instruments  based upon
market conditions existing as of that date. Any change in the fair values of the
instruments from that determined at the end of the previous  reporting period is
recognized  as an  unrealized  risk  management  gain or loss.  Unrealized  risk
management  gains or losses may or may not be  realized  in  subsequent  periods
depending upon subsequent moves in commodity prices, interest rates, or exchange
rates affecting the financial instruments.

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 into our earnings that may not be
particularly meaningful in assessing our financial performance.

                                      -6-
<PAGE>

Risk management gains and losses recognized in 2006 are outlined below.

-------------------------------------------------------------------------------
Year ended December 31,  ($000s)                   2006        2005       2004
-------------------------------------------------------------------------------
Commodity contracts
   Realized (gain) loss                         $(39,217)    $  9,663  $  9,151
   Unrealized (gain) loss                        (25,775)       5,136    (1,985)
Foreign currency contracts
   Realized (gain)                                (1,405)          -          -
Cross currency interest rate swap
   Realized loss (gain)                            4,423        (532)    (2,522)
   Unrealized (gain) loss                         (1,747)      5,035      4,164
-------------------------------------------------------------------------------
Total risk management (gain) loss              $(63,721)     $19,302   $  8,808
-------------------------------------------------------------------------------
Realized (gain) loss                           $(36,199)     $ 9,131   $  6,629
Unrealized (gain) loss                          (27,522)      10,171      2,179
--------------------------------------------- ---------   ---------- ----------
Total risk management (gain) loss              $(63,721)     $19,302   $  8,808
===============================================================================

M.   DEPLETION AND DEPRECIATION

-------------------------------------------------------------------------------
  Years ended December 31,                      2006        2005        2004
-------------------------------------------------------------------------------
  Total depletion and depreciation ($000S)      $143,057    $105,504    $82,554
  Depletion and depreciation per boe ($/BOE)    $  11.81    $   9.82     $ 8.39
===============================================================================

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

N.   FOREIGN EXCHANGE

The foreign exchange gain recognized on the consolidated  statements of earnings
results  primarily from the  translation of our U.S. dollar  denominated  Senior
Notes into Canadian dollars. The Senior Notes are translated and recorded in the
financial  statements at the year end exchange rate, with any  differences  from
prior  measurements  being recognized as an unrealized  foreign exchange gain or
loss.

The  Canadian/U.S.  exchange rate  increased  marginally to one Canadian  Dollar
being equal to  U.S.$0.8581  as at December 31, 2006,  from one Canadian  Dollar
being equal to U.S.$0.8577 at December 31, 2005, resulting in the recognition of
a $1 million foreign exchange gain in 2006.

On November  22,  2005,  pursuant to a tender  offer,  we  repurchased  U.S.$158
million of the 9.90% Senior Notes issued in 2002. As a result of the repurchase,
we crystallized $62 million of the accumulated unrealized foreign exchange gains
in 2005  that had  previously  been  recognized  with the  strengthening  of the
Canadian dollar subsequent to the note issuance.

                                      -7-
<PAGE>

O.   STOCK-BASED COMPENSATION

-------------------------------------------------------------------------------
Years ended December 31,                         2006        2005        2004
-------------------------------------------------------------------------------
Options granted (000S)                            2,228       2,930       2,549
Weighted average fair value of
  options granted ($/SHARE)                      $ 6.90       $5.45       $3.70
Stock-based compensation expense
  recognized ($000S)                            $10,488      $5,903      $3,410
===============================================================================

We have a stock option plan for employees,  Officers, and Directors. The plan is
designed to attract,  motivate, and retain outstanding  individuals and to align
their success with that of our  Shareholders.  The fair value of options granted
is estimated on the date of grant using the  Black-Scholes  option pricing model
and the associated compensation expense is recognized over the vesting period.

During 2006, in recognition of the shortage of, and competition  for,  qualified
personnel that currently exists within the industry,  we implemented an Employee
Retention Program in July 2006 for our existing  employees,  excluding  Officers
and  Directors.  Under the  program,  and  contingent  upon  various  conditions
existing on July 1, 2007, including the market value of the Company's shares, we
may incur additional  compensation  expense to a maximum amount of $4.2 million.
For  the  year  ended  December  31,  2006,  we have  accrued  $1.4  million  in
stock-based compensation in relation to this program.

P.   INCOME TAXES

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

i.   CURRENT INCOME TAXES

Current  taxes  decreased  to nil in 2006  from $5  million  in 2005  (2004 - $3
million)  due  partially to the  elimination  of federal  capital tax  effective
January 1, 2006.  Current taxes in 2005 also included $3 million  related to the
resolution of a Notice of Objection with respect to a corporate acquisition in a
prior tax period.  As a result of the reassessment  resulting from resolution of
the  Notice of  Objection,  $7 million of tax  deductible  exploration  expenses
denied to the  acquired  corporation  were  added to our  income  tax pools as a
positive  offset to incurring  the current  liability.  The  resolution  of this
matter did not impact our total future income tax expense for 2006.

ii.  FUTURE INCOME TAXES

Future taxes in 2006  included a $50 million  recovery as a result of reductions
in the federal and Alberta corporate tax rates, which were enacted in the second
quarter of 2006.  The federal tax rate is to be reduced from 22.1% to 19% over a
3 year period starting January 1, 2008 and the Alberta tax rate was reduced from
11.5% to 10.0% effective April 1, 2006.

iii. CORPORATE TAX RATES

-------------------------------------------------------------------------------
Years ended December 31,                        2006        2005         2004
-------------------------------------------------------------------------------
Statutory rate                                     34.5%       37.6%       38.6%
Effective rate                                    (2.8)%       39.5%       35.0%
===============================================================================

A reconciliation of our effective tax rate to the statutory rate may be found in
Note 15a to the consolidated financial statements.

iv.  TAX POOLS

                                      -8-
<PAGE>

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

-------------------------------------------------------------------------------
                                                     AVAILABLE       MAXIMUM
                                                      BALANCE         ANNUAL
As at January 1, 2007                                 ($000S)       DEDUCTION
-------------------------------------------------------------------------------
Canadian exploration expense                           $169,735         100%
Canadian development expense                            421,500          30%
Canadian oil and natural gas property expense           260,146          10%
Undepreciated capital cost and financing costs          318,105         ~25%
-------------------------------------------------------------------------------
Total                                                $1,169,486
===============================================================================

A  significant  portion of our taxable  income is  generated  by a wholly  owned
partnership.  Consolidated  earnings  before  income taxes  include $259 million
(2005 - $263  million)  of  partnership  earnings  that will be  included in the
following year's income for income tax purposes. Future income taxes include $83
million  (2005 - $94  million)  as a  result  of this  deferral  of  partnership
earnings.

Based upon planned  capital  expenditure  programs and current  commodity  price
assumptions,  it appears we will not incur  current  income taxes until at least
2010.

Q.   CAPITAL EXPENDITURES

SUMMARY OF CAPITAL EXPENDITURES
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
Years ended December 31,                      2006                    2005                    2004
-----------------------------------------------------------------------------------------------------------
                                         ($000S)         %       ($000s)      %          ($000s)      %
-----------------------------------------------------------------------------------------------------------
<S>                                       <C>          <C>        <C>         <C>         <C>          <C>
Drilling and completions                  $294,197      60        $318,502     66         $175,003      62
Land and seismic                            59,905      12          55,469     11           38,326      14
Facilities                                 137,409      28         109,729     23           68,861      24
-----------------------------------------------------------------------------------------------------------
Sub-total                                  491,511      100        483,700    100          282,190     100
Acquisitions and divestments, net           34,394                  28,575                  22,825
-----------------------------------------------------------------------------------------------------------
Sub-total                                  525,905                 512,275                 305,015
MPP                                            (31)                  1,261                  11,386
-----------------------------------------------------------------------------------------------------------
Total capital expenditures                $525,874                $513,536                $316,401
===========================================================================================================
</TABLE>

Capital spending in 2006 was directed  towards the continued  development of our
core  natural  gas  resource  plays in  southern  and  central  Alberta  and our
conventional oil play in the Peace River Arch.

Capital  expenditures,  before acquisitions and divestitures,  in 2006 increased
only  marginally  from  2005;  however,  they  reflect  overall  cost  inflation
experienced in the industry during the year. We drilled a total of 274 net wells
in 2006 at an average cost, to drill and  complete,  of $1,074,000  per well. In
contrast,  we drilled 334 net wells  during 2005 at an average  cost of $954,000
per well. Although not an entirely comparable  analysis,  as the mix of shallow,
deep, and oil wells will also affect this  comparison,  this  represents a 12.6%
increase in  drilling  and  completion  costs,  on a per well basis,  in 2006 as
compared to 2005.

Spending on production facilities increased $27.7 over 2005 and comprised 28% of
our total capital  program,  before  acquisitions and divestments as compared to
23% in 2005. Although we deferred a portion of our initial 2006 drilling program
in deference to lower commodity prices and the inflationary cost environment, we
continued  with the majority of our planned  expenditures  relating to equipment
and facilities.  This spending should allow us to place new production on-stream
more quickly in 2007.

Consistent  with the focus on our natural gas  resource  plays,  we expanded our
land  position  and  working  interests  in  core  areas  through  a  number  of
acquisitions at a total cost of $34.4 million.

                                      -9-
<PAGE>

To assist in funding our capital  programs,  we entered into  agreements for the
divestment of two minor non-operated  properties prior to year end. Net proceeds
of $45.9  million  relating to these  divestments  were  received  subsequent to
December  31,  2006 and have not been  recognized  in 2006 net  acquisition  and
divestment.  Thesefunds  were  redeployed  in  the  ongoing  development  of our
resource plays and we plan to continue this strategy of capital  redeployment in
the future.

With the  current  slow-down  in  industry  activity,  we are  beginning  to see
evidence of a reduction  in the cost of certain  goods and  services.  Costs are
expected  to moderate  over the year in select  areas  which  combined  with our
increased emphasis on capital discipline and cost control should have an overall
positive affect on 2007 capital efficiencies.

4.   LIQUIDITY AND CAPITAL RESOURCES
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
As at December 31,  ($000s, except where noted)      2006           2006            2005           2004
                                                  PRO FORMA (3)
-----------------------------------------------------------------------------------------------------------
<S>                                                 <C>              <C>             <C>          <C>
Working capital deficiency (1)                      $(24,706)        $21,163         $62,116      $    603
Bank debt                                             330,000        330,000         177,900       220,000
Senior term notes                                     524,385        524,385         357,640       198,594
-----------------------------------------------------------------------------------------------------------
Total indebtedness                                   $829,679       $875,548        $597,656      $419,197

Capital stock                                        $231,992       $231,992        $226,444      $135,526
Contributed surplus                                    16,974         16,974           9,173         3,840
Retained earnings                                     485,158        485,158         360,719       284,712
-----------------------------------------------------------------------------------------------------------
Shareholders' equity                                                $734,124        $596,336      $424,078

Debt to cash flow from operations (2)                     3.2            3.4             2.2           2.4
Debt to book capitalization                               53%            54%             50%           50%
Debt to market capitalization                             38%            39%             22%           25%
===========================================================================================================
</TABLE>
(1)  Excludes  unrealized  risk  management  items net of related  future income
     taxes.
(2)  Based on trailing 12 month cash flow from operations
(3)  In December  2006,  Compton  entered  into  agreements  for the sale of two
     minor,  non-core  properties  that generated net proceeds of $45.9 million,
     all of which were  received  in the first  quarter of 2007.  The  effective
     dates of these sales were as of year end.  Accordingly,  we excluded  these
     properties from the December 31, 2006 reserve report,  the details of which
     are set out in the  Annual  Information  Form and  elsewhere  in the Annual
     Report.  Canadian Generally Accepted Accounting  Principles require that we
     recognize the  transactions  as at dates of closing in 2007.  The pro forma
     numbers  presented  above  reflect  the  effect of the  receipt  of the net
     proceeds of $45.9  million as at December  31,  2006,  consistent  with the
     presentation of reserves data as set out in the Annual Information Form.

In November 2006, we expanded our banking syndicate adding four additional banks
including several U.S. based banking institutions.  Concurrent with the increase
in syndicate  members,  we increased our authorized senior secured facilities to
$500  million  consistent  with the  Company's  borrowing  base.  The  terms and
conditions of the increased facilities remain the same as those established upon
renewal of the facilities in July 2006.  Our borrowing base is determined  based
upon year end  reserves.  With the  increase  in 2006  reserves  over  2005,  we
anticipate  the borrowing  base will  increase.  We do not,  however,  expect to
request an increase in our authorized credit facilities at this time.

Our corporate  debt is structured to provide us with financial  flexibility.  Of
our  existing  debt,  61%  consists of Senior Notes that are not due until 2013,
giving us the ability to draw on our senior secured credit  facilities to assist
in funding our planned 2007 capital program.

During the fourth  quarter of 2006, we entered into  agreements  for the sale of
two minor,  non-core  properties.  The sale of these properties were recorded in
2007 concurrent with the closing of sales. We are also pursuing the monetization
of $25  million of  production  facilities  that are  expected to close in early
April  2007.  The sale of  additional  non-core  properties  and  certain  major
conventional  oil  properties

                                     -10-
<PAGE>

remains  a  potential  source  of funds for the  continued  development  of our
overall natural gas resource play strategy.

We  believe  internally  generated  cash flow  from  operations,  proceeds  from
property   dispositions,   and  funds  available  through  our  expanded  credit
facilities  will be more  than  sufficient  to fund  our  planned  2007  capital
program, while still maintaining an appropriate capital structure.

A.   CONTRACTUAL OBLIGATIONS

As part of normal  business,  we have  entered  into  arrangements  and incurred
obligations that will impact our future operations and liquidity,  some of which
are reflected as  liabilities  in the  consolidated  financial  statements.  The
following table summarizes our contractual obligations as at December 31, 2006.
<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>
Operating leases                              $  3,737         $ 6,211            -                -
Office facilities                               $3,509         $14,523       $9,600          $24,000
MPP partnership distributions                   $9,172         $12,229            -                -
----------------------------------------------------------------------------------------------------
Total                                          $16,418         $32,963       $9,600          $24,000
====================================================================================================
</TABLE>

We have the ability and the intention to extend the term of our bank  borrowings
and  therefore  repayment  of the  facility is not  included in the  schedule of
contractual obligations above.

5.   OUTLOOK AND GUIDANCE FOR 2007

Consistent with general  industry  thinking,  we are of the opinion that natural
gas prices will strengthen significantly during 2007. We are also of the opinion
that the cost of specific goods and services will moderate during the year.

In the interim, we believe it prudent to move forward with a relatively moderate
capital spending program. During 2007, the majority of our activities will focus
on the continued  development and delineation of our natural gas resource plays.
We will  concentrate on development  drilling and the  acceleration of on-stream
timing with a view to production  growth. At the same time,  increased  emphasis
will be placed on capital  discipline and efficiency.  Equally  important is our
need to increase our  complement  of qualified  personnel  for the  expansion of
operations  necessary to realize on our opportunities in an efficient manner. We
view the current  reduction in industry  activity as an  opportunity  to attract
additional staff in preparation for increased drilling programs in the last half
of 2007 and into 2008.

The following section summarizes our plans and guidance for 2007.

SUMMARY OF 2007 GUIDANCE

-------------------------------------------------------------------------------
                                                            2007 BUDGET RANGE
-------------------------------------------------------------------------------
Capital expenditures ($MILLIONS)                                     $375
Gross wells                                                           330
Average production - total boe/d                               37,000 to 38,000
Cash flow from operations ($MILLIONS)                            $310 to $320
===============================================================================

Our 2007 projected cash flow from operations is based upon the following pricing
assumptions:

-------------------------------------------------------------------------------
                                      BENCHMARK                  REALIZED
-------------------------------------------------------------------------------
Natural gas                            AECO Cdn $7.30/GJ          Cdn $7.50/mcf
Crude oil ($/bbl)                    WTI U.S. $62.00/bbl         Cdn $60.00/bbl
===============================================================================

                                     -11-
<PAGE>

The average Canadian/U.S. exchange rate is budgeted at $0.89 U.S. = $1.00 Cdn.

A.   CASH FLOW SENSITIVITIES FOR 2007

-------------------------------------------------------------------------------
($millions) Change in Cash Flow
-------------------------------------------------------------------------------
Change of Cdn $0.25/mcf in the benchmark
  AECO natural gas price                                                    $12
Change of U.S. $1.00/bbl in the benchmark
  WTI oil price                                                              $2
===============================================================================

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

ADDITIONAL DISCLOSURES

A.   CONTROLS AND PROCEDURES

With respect to disclosure  controls and  procedures  and internal  control over
financial reporting,  we are required to comply with the U.S. Sarbanes-Oxley Act
of 2002 and Canadian Multilateral Instrument 52-109, Certification of Disclosure
in Issuers' Annual and Interim Filings.  These regulations are substantially the
same. However,  the most significant  difference is the U.S. requirement for the
registered public accounting firm that audits our financial statements, included
in our  annual  report,  to issue an  attestation  report on our  assessment  of
internal control over financial  reporting.  There is no corresponding  Canadian
attestation requirement.

There are certain  procedural  and  wording  differences  between  the U.S.  and
Canadian  certifications.  We have  chosen  to file  the  form of  certification
pursuant to Section 302 of the Sarbanes-Oxley  Act with the U.S.  Securities and
Exchange Commission ("SEC") and Form 52-109 F1, Certification of Annual Filings,
with the Ontario Securities Commission ("OSC").

We have  complied  with both the U.S.  and Canadian  requirements  in respect of
disclosure controls and procedures and internal control over financial reporting
and our report is below.

i.   MANAGEMENT'S EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

The term "disclosure  controls and procedures" is defined,  under Rule 13a-15(d)
of the  Exchange  Act, as controls  and other  procedures  that are  designed to
ensure both non-financial and financial  information required to be disclosed by
us in our periodic  reports is  recorded,  processed,  summarized,  and reported
within  the  time  periods   required.   This  information  is  accumulated  and
communicated  to  management  as  appropriate  to  allow  for  timely  decisions
regarding  required  disclosures.  The  definition  of  disclosure  controls and
procedures  with  respect  to  Canadian   Multilateral   Instrument   52-109  is
substantially the same.

As indicated in our  certifications  filed with the SEC and OSC, we completed an
evaluation of the  effectiveness  of the design and operation of our  disclosure
controls and procedures as of December 31, 2006,  under the supervision and with
the  participation  of our  Management,  including  our  President  & CEO and VP
Finance & CFO. Based upon our evaluation,  we concluded our disclosure  controls
and procedures were effective in all material respects.

ii.  MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management,  including our President & CEO and VP Finance & CFO, is  responsible
for  establishing  and  maintaining  adequate  internal  control over  financial
reporting.  The term  "internal  control over  financial  reporting" is defined,
under  both  Rule  13a-15(f)  of the  Exchange  Act  and  Canadian  Multilateral
Instrument  52-109,  as processes  designed by, or under the supervision of, our
principal executive and principal financial officers,  and effected by our board
of directors,  management,  and other personnel to provide reasonable  assurance
regarding the reliability of our financial  reporting and the preparation of our
financial  statements  for  external  purposes in  accordance  with GAAP.  These
controls include policies and procedures

                                     -12-
<PAGE>

that:

     1.   Pertain to the maintenance of our records,  that accurately and fairly
          reflect the transactions and dispositions of our assets;

     2.   Provide reasonable assurance that transactions are recorded to be able
          to prepare our financial  statements in accordance with GAAP, and that
          our  receipts  and  expenditures  are  made  only in  accordance  with
          authorizations of our management and directors; and

     3.   Provide reasonable  assurance regarding prevention or timely detection
          of unauthorized acquisition,  use, or disposition of our assets, which
          could have a material effect on our financial statements.

We completed an evaluation of the  effectiveness  of the design and operation of
our internal control over financial  reporting under the  supervision,  and with
the  participation,  of our  Management,  including  our  President & CEO and VP
Finance & CFO. We conducted our evaluation of the  effectiveness of our internal
control over  financial  reporting  based on the  Internal  Control - Integrated
Framework,  issued by the Committee of Sponsoring  Organizations of the Treadway
Commission,  also known as COSO.  Based upon our  evaluation,  we have concluded
that, as of December 31, 2006,  the internal  control over  financial  reporting
were effective in all material respects.

Our  assessment  of the  effectiveness  of our internal  control over  financial
reporting  as of December 31, 2006 was audited by Grant  Thornton LLP  Chartered
Accountants, the independent registered public accounting firm which also audits
our financial statements.

iii. CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There were no changes during the last fiscal quarter that  materially  affected,
or are  reasonably  likely to  materially  affect,  our  internal  control  over
financial reporting.

B.   CRITICAL ACCOUNTING ESTIMATES

Accounting  estimates require us to make assumptions  regarding matters that are
uncertain at the time the estimate is made and may have a material impact on our
financial condition.  A comprehensive  discussion of our significant  accounting
policies may be found in Note 1 to the consolidated financial statements.

i.   OIL AND NATURAL GAS RESERVES

The  independent   petroleum  engineering  and  geological  consulting  firm  of
Netherland,  Sewell & Associates,  Inc. evaluated and reported on 94% of our oil
and natural gas reserves and audited the  Company's  internal  evaluation of the
remainder.

The  estimation  of reserves is a  subjective  process.  Forecasts  are based on
engineering data, projected future rates of production, and the timing of future
expenditures,  all of which are  subject to numerous  uncertainties  and various
interpretations.  We expect  that our  estimates  of  reserves  will change with
updated information from the results of future drilling,  testing, or production
levels.  Such revisions could be upwards or downwards.  Reserve estimates have a
material impact on depletion and depreciation, asset retirement obligations, and
impairment  costs,  all of which could  possibly  have a material  impact on our
consolidated net earnings.

ii.  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

                                     -13-
<PAGE>

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 2006, we incurred $143 million of depletion and  depreciation.  If our proved
reserves were to increase by 5%, our depletion  and  depreciation  expense would
decrease by $1.6 million and  consolidated net earnings after tax would increase
by $1.1  million.  If our proved  reserves were to decrease by 5%, our depletion
and  depreciation  expense would increase by $1.9 million and  consolidated  net
earnings after tax would decrease by $1.2 million.

iii. IMPAIRMENT

In applying  the full cost method of  accounting,  we  periodically  calculate a
ceiling or  limitation  on the amount that property and equipment may be carried
for on the consolidated balance sheets. An impairment exists if the undiscounted
future net cash flows from proved reserves at future  commodity  prices plus the
cost  of  undeveloped  properties  is  less  than  the  carrying  value  of  the
capitalized  costs.  As at December 31, 2006, the ceiling amount  calculated was
$2.7 billion (2005 - $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 our reserves are
anticipated.

iv.  ASSET RETIREMENT OBLIGATION

We recognize the fair value of estimated asset retirement obligations on the
consolidated balance sheet when a reasonable estimate of fair value can be made.
Asset retirement obligations include those legal obligations where we will be
required to retire tangible long term assets such as well sites, pipelines, and
facilities. The asset retirement cost, equal to the initially estimated fair
value of the asset retirement obligation, is capitalized as part of the cost of
the related long term assets. Increases in the asset retirement obligations
resulting from the passage of time are recorded as accretion of asset retirement
obligations in the consolidated statement of earnings. Amounts recorded for
asset retirement obligations are subject to uncertainty associated with the
method, timing, and extent of future retirement activities. Actual payments to
settle the obligations may differ from estimated amounts.

C.   RECENT ACCOUNTING PRONOUNCEMENTS

In 2005, the Canadian Institute of Chartered Accountants (CICA) issued three new
accounting  standards:  Handbook Section 1530,  COMPREHENSIVE  INCOME,  Handbook
Section 3855, FINANCIAL INSTRUMENTS - RECOGNITION AND MEASUREMENT,  and Handbook
Section 3865, HEDGES. The new standards introduce the Consolidated  Statement of
Comprehensive  Income which is used to temporarily  provide for gains and losses
including  foreign  currency  translation  adjustments and other amounts arising
from  changes in fair value until they are  realized and recorded in net income.
As well, all financial instruments, including

                                     -14-
<PAGE>

derivatives,  are to be included in our Consolidated Balance Sheet and measured
at fair value.  In certain  situations  assets that are  classified  as held to
maturity will continue to be measured at cost.  The new standards  also include
further clarification on the application of hedge accounting which will have no
impact  on  our  financial   statements  which  currently  use   mark-to-market
accounting  for derivative  instruments.  These new standards are effective for
fiscal  years  beginning  on or after  October  1, 2006 and early  adoption  is
permitted. We have assessed the impact of these new accounting standards on the
consolidated  financial statements at January 1, 2007 and have determined that:

o    The  balance in  deferred  financing  charges  will no longer be  disclosed
     separately but will be netted against the corresponding Senior Notes.

o    The deferred  risk  management  loss will become an  adjustment  to opening
     retained earnings.

o    The presentation of accumulated other comprehensive  income will be similar
     to the  presentation of United States  accounting  principles and reporting
     included in Note 20 to the Consolidated Financial Statements.

o    The measurement  and recording of financial  instruments at fair value will
     not have a material impact on our Consolidated Financial Statements.

In July 2006, the CICA replaced Handbook Section 1506, "ACCOUNTING CHANGES" with
a new  Section  1506,  "ACCOUNTING  CHANGES"  to  harmonize  with  International
Accounting  Standards for the accounting and disclosure of changes in accounting
estimates  and errors.  Under the new  standard,  accounting  changes  should be
applied  retrospectively  unless otherwise  permitted or where  impracticable to
determine. In addition,  voluntary changes in accounting policy are made only if
they result in the  financial  statements  providing  reliable and more relevant
information.  New  disclosure  is required for changes in  accounting  policies,
changes in  accounting  estimates  and  correction  of errors.  The  standard is
effective  for fiscal years  beginning on or after January 1, 2007 and we do not
expect the application of this revised standard to have a material impact on our
consolidated financial statements.

In December 2006, the CICA issued two new accounting standards: Handbook Section
3862,  "FINANCIAL  INSTRUMENTS  -  DISCLOSURES"  and  Section  3863,  "FINANCIAL
INSTRUMENTS - PRESENTATION". The new standards will require increased disclosure
of financial  instruments with particular  emphasis on the risks associated with
recognized  and  unrecognized  financial  instruments  and how  those  risks are
managed.  The standards  are  effective  for fiscal years  beginning on or after
October 1, 2007 and we are currently  assessing  the impact on the  consolidated
financial statements.

In December 2006, the CICA issued a new accounting  standard:  Handbook  Section
1535,  "CAPITAL  DISCLOSURES",  requiring  disclosure  of  information  about an
entity's  capital and the  objectives,  policies,  and  processes  for  managing
capital.  The  standard is  effective  for fiscal  years  beginning  on or after
October 1, 2007 and we are currently  assessing  the impact on the  consolidated
financial statements.

D.   RISK MANAGEMENT

Our  operations  are  subject  to  risks  inherent  to the oil and  natural  gas
industry. We are exposed to financial risks including  fluctuations in commodity
prices,  currency exchange rates,  interest rates, credit ratings,  and changing
expenditure costs due to shifts in market conditions.  We take specific measures
to manage these risks, particularly those impacting cash flow from operations.

A more  detailed  discussion  of risk  factors is  presented  in our most recent
Annual  Information  Form,  filed with securities  regulatory  authorities on or
before March 30, 2007 on WWW.SEDAR.COM.

i.   COMMODITY PRICE RISK MANAGEMENT

We enter into commodity  price contracts to actively manage risk associated with
price  volatility  to protect  cash flow from  operations  required  to fund our
capital  program.  We use  costless  collars as well as  balancing  physical and
financial  contracts in terms of volumes,  timing of  performance,  and delivery
obligations  to manage risk.  Net open positions may exist or may be established
to take advantage of market conditions. Net earnings for the year ended December
31, 2006,  include  realized  and  unrealized  gains of $65 million  (2005 - $15
million loss) on these transactions.

                                     -15-
<PAGE>

The following table outlines  commodity hedge  transactions in place at December
31, 2006 together with transactions entered into subsequent to the year end:
<TABLE>
<CAPTION>

-----------------------------------------------------------------------------------------------------------
COMMODITY                     TERM                   AMOUNT               AVERAGE PRICE           INDEX
-----------------------------------------------------------------------------------------------------------
<S>               <C>                         <C>                  <C>                        <C>
Natural gas
  Collar          Nov. 2006 - Mar. 2007             40,000 GJ/d        Cdn$8.03 - $10.62          AECO
  Collar          Apr. 2007 - Oct. 2007             45,000 GJ/d         Cdn$6.61 - $8.77          AECO

Crude oil

  Collar          Jan. 2007 - Dec. 2007            3,000 bbls/d        U.S.$75.00 - $84.55        WTI
===========================================================================================================
</TABLE>

ii.  FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT

We are exposed to  fluctuations in the exchange rate between the Canadian dollar
and the U.S. dollar.  Commodity prices are based on U.S. dollar  benchmarks that
result in our realized  price being  influenced  by the  Canadian/U.S.  currency
exchange  rate.  Should the  Canadian  dollar  strengthen  compared  to the U.S.
dollar, the negative effect on net earnings would be partially offset by foreign
exchange gains on our 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 our U.S.
dollar  denominated  Senior Notes.  Cash flow from operations is not impacted by
the effects of  currency  fluctuations  on our U.S.  dollar  denominated  Senior
Notes.

iii. INTEREST RATE RISK MANAGEMENT

Concurrent  with the closing of our 9.90% Senior Notes  offering in May of 2002,
we entered into a cross currency  interest rate swap. The swap,  which converted
fixed rate U.S. dollar interest  obligations  into floating rate Canadian dollar
interest  obligations,  was entered  into to fix the  exchange  rate on interest
payments and take advantage of lower floating  interest  rates. On repurchase of
the majority of 9.90% Senior Notes in November  2005, we elected not to collapse
the  swap and  incur  the  associated  costs of $12  million.  The swap  remains
outstanding and at December 31, 2006, we valued the liability relating to future
unrealized losses on the swap arrangement to be $11 million (2005 - $15 million)
determined on a  mark-to-market  basis.  The loss  associated  with the swap has
resulted  primarily from the  strengthening of the Canadian  dollar.  Should the
Canadian dollar  continue to increase  against the U.S.  dollar,  the loss could
increase  further;  alternatively if the Canadian dollar were to weaken the loss
would be reduced.  Cash settlements of the swap positions are made semi-annually
and  losses  realized  will be  recorded  over  the  remaining  term of the swap
agreement which expires in May 2009.


                                     -16-
<PAGE>

E.   SELECTED QUARTERLY INFORMATION

The following tables set out selected  quarterly  financial  information for the
last two fiscal years.
<TABLE>
<CAPTION>

------------------------------------------------------------------------------------------------------------
                                                            THREE MONTHS ENDED                  YEAR ENDED
------------------------------------------------------------------------------------------------------------
                                             MARCH 31,      JUNE 30,     SEPT. 30,  DEC. 31,     DEC. 31,
($000s, except where noted)                     2006          2006          2006       2006        2006
------------------------------------------------------------------------------------------------------------
<S>                                          <C>           <C>           <C>         <C>        <C>
Average production (BOE/D)                       34,029        32,645       32,843      33,245        33,187
Average pricing ($/BOE)                       $   48.21     $   44.85    $   41.33    $  41.82     $   44.05

Total revenue                                 $ 147,644     $ 133,224     $124,886    $ 127,902    $ 533,656
Cash flow from operations                     $  73,596     $  67,326     $ 60,120    $  55,263    $ 256,305

Per share: basic                              $    0.58     $    0.53     $   0.47    $   0.43     $   2.01
           diluted                            $    0.55     $    0.50     $   0.45    $   0.42     $   1.92

Operating earnings                            $  22,249     $  17,947     $ 13,150    $ 11,822     $ 65,168

Net earnings (loss)                           $  38,002     $  68,744     $ 30,717    $(10,037)    $ 127,426

Per share: basic                              $    0.30     $    0.54     $   0.24    $  (0.08)    $   1.00
           diluted                            $    0.28     $    0.51         0.23    $  (0.08)    $   0.95
============================================================================================================
</TABLE>

During the second  half of 2006,  lower  realized  commodity  prices from those
experienced during the first half of the year resulted in reduced revenue, cash
flow,  and  operating  earnings.  Production  increases in the third and fourth
quarter  were more than  offset  by the  reduction  in  commodity  prices.  The
negative effect of lower commodity  prices on cash flow was reduced by realized
gains of $36 million from risk management activities. Net earnings for the nine
months ended September 30, 2006 benefited from an unrealized  foreign  exchange
gain of $19.1  million,  after tax,  and an income tax recovery of $35 million.
Net  earnings  in the fourth  quarter  were  negative  due to the  reversal  of
unrealized foreign exchange gains recorded in prior quarters,  as the result of
the weakening of the Canadian dollar compared to the U.S. dollar.

<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       $   0.18      $   0.09   $    0.30     $    0.65
           diluted                              $   0.08       $   0.17      $   0.08   $    0.29     $    0.62
===============================================================================================================
</TABLE>

                                     -17-
<PAGE>

As compared to 2004,  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.

F.   SELECTED ANNUAL INFORMATION

-------------------------------------------------------------------------------
Years ended December 31, ($000s)       2006            2005            2004
-------------------------------------------------------------------------------
Total revenue                         $  533,656       $   557,879   $  391,659
Net earnings                          $  127,426       $   81,326    $   63,633
Per share: basic                      $     1.00       $     0.65    $     0.54
           diluted                    $     0.95       $     0.62    $     0.51
Total assets                          $2,147,472       $1,758,098    $1,330,611
Total long term financial
   liabilities                        $  854,385       $  535,540    $  198,594
===============================================================================

Total  revenue  in 2006 was  marginally  lower  than  2005  with  increases  in
production being more than offset by reduced commodity prices.  Net earnings in
2006 increased $46.1 million over 2005 primarily as a result of risk management
gains that offset the reduction in revenue and increases in expenses. Long term
financial  obligation  in 2006  increased  over 2005 as a result  of  increased
borrowings to fund the capital programs.

Total revenue in 2005 was higher than in the previous year due to a combination
of increased production and higher commodity prices. Net earnings in 2005
increased 28% from 2004, but was reduced by non-recurring costs of $14 million
($21 million before taxes) relating to the repurchase of U.S.$158 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 issuing U.S.$300 million Senior
Notes and reclassifying bank debt as long term.

G.   TRADING AND SHARE STATISTICS

As at March 19, 2007 there were 128,569,676 common shares outstanding as well as
12,430,677 stock options.

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------
                                                          2006                  2005(1)            2004
                                                     TSX         NYSE       TSX         NYSE        TSX
------------------------------------------------------------------------------------------------------------
<S>                                                <C>        <C>          <C>         <C>         <C>
Average daily trading volume (000S)                 545,489     115,450    736,416     138,288      674,764
Share price ($/SHARE)
  High                                               $19.24    US$16.74     $18.66    US$16.11       $11.43
  Low                                                $10.20    US$ 9.04      $9.80    US$14.15        $5.89
  Close                                              $10.65    US$ 9.12     $17.10    US$14.65       $10.85

Market capitalization at December 31 ($000S)             $1,368,557            $2,176,197        $1,273,290
Shares outstanding (000S)                                   128,503               127,263           117,354
============================================================================================================
</TABLE>
(1)  Trading on the New York Stock Exchange commenced on December 5, 2005.

6.   FURTHER INFORMATION

Additional  information,  including our Annual Information Form, is available on
the Canadian Securities  Administrators' System for Electronic Document Analysis
and Retrieval ("SEDAR") at WWW.SEDAR.COM.

                                     -18-
<PAGE>

A.   FORWARD LOOKING STATEMENTS

Certain  information  contained herein  constitutes  forward looking  statements
under the meaning of  applicable  securities  laws,  including the United States
Private  Securities  Litigation Reform Act of 1995.  Forward looking  statements
include  estimates,  plans,  expectations,   opinions,  forecasts,  projections,
guidance  or  other  statements  that  are not  statements  of  fact,  including
statements regarding (i) cash flow, production, capital expenditures and planned
wells in 2007,  and (ii) other risks and  uncertainties  described  from time to
time  in  the  reports  and  filings  made  by  us  with  securities  regulatory
authorities. Although we believe that the expectations reflected in such forward
looking  statements  are  reasonable,   we  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 our 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. We may, as considered necessary in the circumstances,
update  or  revise  forward  looking  information,  whether  as a result  of new
information,  future events,  or otherwise.  Our forward looking  statements are
expressly qualified in their entirety by this cautionary statement.

B.   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 our  performance  or  liquidity.  Cash flow from  operations is used by us to
evaluate  operating  results and our 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 us to facilitate  comparability of
earnings between periods.

C.   USE OF BOE EQUIVALENTS

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


                                     -19-