Compton reports 2006 year end results



    CALGARY, March 26 /CNW/ - Compton Petroleum Corporation (TSX - CMT, NYSE
- CMZ) is pleased to report its financial and operating results for the year
and quarter ended December 31, 2006.

    
    2006 HIGHLIGHTS

      -  Reserve additions                     42.2 million boe
                                               (net of production),
                                               20% increase

      -  Reserve value                         $3.3 billion, 8% DCF

      -  FD&A costs, $/boe
           Excluding change in future capital  $8.84 proved plus probable
                                               $14.36 proved
           Including change in future capital  $13.56 proved plus probable
                                               $18.45 proved

      -  2006 Average Production (boe/d)       33,187 - 13% increase

      -  Production replacement                4.5 times

      -  Cash flow                             $256 million, $1.92/share F.D.
    

    Strong Reserve and Production Growth

    Total proved plus probable reserves rose 20% from the prior year to
249 million boe and were valued at $3.3 billion, 8% DCF. Total proved reserves
at year end were 147 million boe, an increase of 17% from 2005. Proved
producing reserves comprise 67% of total proved reserves. Total proved
reserves account for 59% of the proved plus probable reserves.
    Our 2006 production grew 13% to average 33,187 boe/day versus 29,424
boe/day in 2005. Ernie Sapieha, President and CEO, commented that "Compton's
increase in low cost reserves and production growth are largely as a result of
our continued successful drilling program and capital investment in facilities
and infrastructure expansion. Our ten year compound annual growth rate on
reserves is 35%, and we have never had any material revisions to our reserve
reports."

    Drilling Results

    During 2006 Compton achieved reserve additions of 54.3 MMboe, before
production, of reserve additions, primarily through the drill bit, at highly
competitive finding and development costs. We successfully completed our 342
well drilling program, with a 94% success rate. We replaced 448% of our 2006
production at an all-in Finding, Development, and Acquisition cost ("FD&A") of
$8.84/boe, excluding the change in future capital, or $13.56/boe, including
change in future capital.
    Of the 342 wells drilled in 2006, 86% were classified as development
wells and 14% were classified as exploratory wells, compared to 80% and 20%
respectively in 2005. The higher percentage of development wells in the
current year reflects the increasing success of our oil and gas plays.

    Revenue and Cash Flow

    Although Compton experienced significant production gains, both revenue
and cash flow declined by 4% and 8%, respectively, due to lower commodity
prices, particularly natural gas. The negative effect of lower commodity
prices on cash flow was reduced by realized gains of $36 million from risk
management activities.

    Property Dispositions

    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 the year end, and accordingly, these properties are excluded
from our December 31, 2006 reserve evaluation and report. Canadian GAAP
requires we recognize the sales as at their closing dates in 2007 and
Compton's 2006 financial results do not include these transactions. The
following Financial Summary and The Liquidity and Capital Resources section of
this Release reflect the pro forma effect of the receipt of the proceeds of
$45.9 million as at December 31, 2006 consistent with the presentation of
reserve information.
    Additionally, the Company is pursuing the monetization of $25 million of
production facilities that is expected to close in April 2007.


    
    FINANCIAL SUMMARY

    -------------------------------------------------------------------------
                     Three Months Ended Dec. 31       Year Ended Dec. 31
    ($000s, except
     per share
     amounts)         2006      2005   % Change    2006      2005   % Change
    -------------------------------------------------------------------------
    Gross revenue   $127,902  $184,428    -31%   $533,656  $557,879     -4%

    Cash flow(1)    $ 55,263  $ 89,640    -38%   $256,305  $278,112     -8%
    Per share
      - basic       $   0.43  $   0.71    -39%   $   2.01  $   2.21     -9%
      - diluted     $   0.42  $   0.67    -37%   $   1.92  $   2.11     -9%

    Net earnings    ($10,037) $ 38,106   -126%   $127,426  $ 81,326     57%
    Per share
      - basic       ($  0.08) $   0.30   -127%   $   1.00  $   0.65     54%
      - diluted     ($  0.08) $   0.29   -128%   $   0.95  $   0.62     53%

    Operating
     earnings       $ 11,822  $ 33,413    -65%   $ 65,168  $ 93,664    -30%

    Capital
     expenditures                                $525,874  $513,536      2%
    Corporate debt                               $875,548  $597,656     46%
    Pro forma Corporate
     debt, after
     dispositions(2)                             $829,679

    Shareholders'
     equity                                      $734,124  $596,336     23%

    Weighted
     averages
     shares (000s)
      - basic                                     127,820   125,627
      - diluted                                   133,626   131,667
    -------------------------------------------------------------------------
    (1) The term "cash flow" 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
        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.

    (2) See Property Disposition discussion above.



    OPERATING SUMMARY

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

                    Three Months Ended Dec. 31       Year Ended Dec. 31
    (6:1 boe
     conversion)      2006      2005   % Change    2006      2005   % Change
    -------------------------------------------------------------------------

    Average daily
     production
      Natural gas
       (MMcf/d)          148       133     11%        142       131      8%
      Liquids (light
       oil & ngls)
       (bbls/d)        8,600     8,879     -3%      9,516     7,646     24%
      Total oil
       equivalent
       (boe/d)        33,245    31,042      7%     33,187    29,424     13%

    Average realized
     prices
      Natural gas
       ($/Mcf)      $   6.52  $  11.20    -42%   $   6.37  $   8.42    -24%
      Liquids
       ($/bbl)      $  49.46  $  57.99    -15%   $  58.53  $  56.04      4%
      Total oil
       equivalent
       ($/boe)      $  41.82  $  64.58    -35%   $  44.05  $  51.95    -15%

    Field operating
     netback
     ($/boe)        $  27.03  $  38.88    -30%   $  28.16  $  31.46    -10%
    Cash flow
     netback
     ($/boe)        $  19.38  $  31.46    -38%   $  21.52  $  25.76    -16%

    Undeveloped land
      Gross acres                                 980,179   971,317      1%
      Net acres                                   798,192   738,954      8%
      Average working
       interest                                       81%       76%      7%

    Reserves (Mboe)
      Proved oil
       equivalent                                 147,218   125,960     17%
      Proved plus
       probable oil
       equivalent                                 248,755   206,671     20%
      Proved plus
       probable gas
       equivalent, Tcfe                             1.492     1.240

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

    OPERATIONS

    PROPERTY REVIEW

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

    SHALLOW GAS

    The Plains Belly River and overlying Edmonton Horseshoe Canyon shallow
gas zones cover more than 1,000 sections of Compton held land in southern
Alberta. The entire 800 metre gas-charged section is comprised of multiple
Belly River sands, silts, shales, and coals, overlain by the
Edmonton/Horseshoe Canyon Coals that similarly include sands, silts, and
shales. In 2006 we drilled 183 wells through the Edmonton Horseshoe Canyon
Group targeting the Belly River section, for a total of 550 wells drilled as
of year end. This allows for numerous recompletion and commingling
opportunities. Going forward, we will focus on downspacing, development
drilling, and recompletions in order to establish a resource manufacturing and
processing model designed to maximize production. Three key elements - one
industry driven, the others Compton driven - have recently come together to
make this model possible.

    
    1.  In July 2006, the Alberta Energy and Utilities Board ("EUB")
        announced a downspacing initiative for zones above the Mannville,
        including the Plains Belly River, that is intended to see standard
        well spacing increase from one to four wells per section. Reduced
        spacing is critical in the development of our unconventional
        reservoirs that require greater well density for more efficient
        resource development and recognition. With our current land
        holdings, this new regulation adds over 4,000 locations to our
        drilling inventory. Additional to downspacing, we now have the
        ability to maximize production through commingling Belly River with
        the Edmonton Horseshoe Canyon zones. The EUB released a directive for
        commingling on October 31, 2006 that allows for concurrent production
        of Belly River and Edmonton/Horseshoe Canyon Coals as a single
        procedure, following minimal application.

    2.  We are in a unique position of having a large 3D seismic data base,
        totaling 2,140 km(2) (826 mi(2)) as at December 31, 2006, with an
        additional 427 km(2)(165 mi(2)) as of the first quarter of 2007. The
        use of 3D seismic is key in positioning downspace well locations that
        maximize production and reduce capital requirements.

    3.  In recent years, we have focused efforts on establishing and
        expanding infrastructure and facilities in our core areas. We
        currently have 466 km of low pressure pipelines. Years in the making,
        this intricate system of compressors and low pressure pipeline
        gathering systems covers a large portion of our existing land base.
    

    2006 saw Compton take advantage of new EUB downspacing and commingling
initiatives to successfully test our seismic modeling and complete
infrastructure development. In 2006 we drilled 25 sections to as many as four
wells per section. Preliminary results on the second to fourth wells in each
section have generally exceeded the first drill in the section. As a result,
we will ramp up our Belly River/Edmonton drilling program in 2007 to grow
production from these zones. Late in the fourth quarter of 2006, we tied in
21 Belly River/Coalbed Methane wells. An additional 21 wells are projected to
be tied in during the first and second quarters of 2007.
    In 2006, we expanded our southern Alberta shallow gas compression
capability to 105 mmcf/d.
    In 2007, we have budgeted 215 shallow gas wells targeting the Plains
Belly River/Edmonton group. In select areas, drilling is planned in groups of
20 to 40 wells to capitalize on downspacing and associated cost efficiencies.
As well, we have 69 hybrid coal bed methane and sand gas wells. Low pressure
gathering and compression facilities are largely in place in the area to
assist in reducing on-stream times. It is our intent that production from
these multi-zone wells will be commingled for optimal production results.
Going forward, in 2008 and beyond, we plan to accelerate drilling and
associated production through large well counts plus tie-ins to existing
facilities. A 4,000 well drilling inventory makes this possible.

    DEEP GAS

    Compton has three deep gas resource plays: the Basal Quartz sands at
Hooker, the stacked, thrusted, Belly River play at Callum in southern Alberta,
and the Gething/Rock Creek sands at Niton in central Alberta.

    Hooker

    Discovered by Compton in 1999, the Basal Quartz sandstone pool at Hooker
is the southern Alberta extension of the Lower Cretaceous Deep Basin gas
trend. This play covers an extensive area of approximately 124,800 net acres,
with our working interest averaging 85%. Current production extends over five
townships, and in 2006, we drilled 18 wells at Hooker, testing the aerial
extent of the play. The edges of the Hooker pool have yet to be defined.
    In 2006, the total Hooker infrastructure system was expanded to 65
mmcf/d.
    The key to maximizing production at Hooker, or any Deep Basin play, is
downspacing. Currently, Compton's drilling is approved for two wells per
section, although the majority of the 120 gas wells drilled to date in this
area are on single section spacing. Our engineering and geological models
indicate that a minimum four wells per section is required for optimal
production here. As such, we have made an application to the EUB to reduce
space one section in the pool to four wells per section on a pilot basis, with
two other sections pending. We will be drilling approximately 20 Basal Quartz
wells during 2007. The majority of these wells are infill locations planned
for the second half of 2007, once downspacing is approved.

    Callum

    Our Callum property consists of a series of overpressured, thrusted, low
permeability Belly River sands in the foothills of southern Alberta. With the
acquisition of our partner's interest in 2006, we now hold a 100% interest in
70,400 acres (110 sections) of land on trend. A total of 13 exploratory wells
have been drilled over the life of the play. Based on our initial detailed
geological, geophysical, and engineering analysis of seismic, cores, well
logs, and test and production data, Callum appears to exhibit many
similarities to the deep unconventional gas pools of the Rocky Mountain region
of the United States.
    In 2006, we drilled five exploratory wells, all of which encountered
multiple sands. The wells were cased and extensively cored. The two most
recent wells, drilled during the third quarter of 2006, are two and 15 miles
south of current production, respectively, and following laboratory analysis
of the cores, these wells will be appropriately completed.
    Compton is conducting environmental studies on four additional pads prior
to submitting the required license applications. We are working with all
stakeholders in the area to proceed in an environmentally responsible manner
and we remain committed to minimizing the impact of our activities. To this
end, drilling in this area is based on one drill pad per section.
    In 2007, we plan to drill two exploratory wells at Callum. We remain
confident in pursuing this challenging and technically complex play. Our
activities in the area will increase once regulatory well licensing issues are
resolved.

    Niton

    The Niton area in central Alberta, 150 miles west of Edmonton, is in the
Alberta Deep Basin. Our main targets are the Jurassic Rock Creek and
Cretaceous Gething, analogous to the Hooker pool in southern Alberta.
Proprietary exploration, development, and operations knowledge gained in
southern Alberta has resulted in accelerated growth of this core area. We have
assembled 156,800 (128,000 net) acres of land in this multi-target area. In
2006, 31 wells were drilled with results exceeding expectations.
    Compton undertook a major facility project at Niton during 2006. At our
McLeod River 7-34-54-14W5 gas plant all major equipment was purchased in 2006
to prepare for a March 31, 2007 completed gas plant expansion from 18 to 23
mmscf/d processing capacity.
    In 2007, we plan to drill 39 wells in this area.

    Worsley/Cecil

    Located in the Peace River Arch, the Worsley and Cecil properties produce
from the Triassic Charlie Lake Formation, a layered sandy Carbonate. These two
properties comprise the majority of Compton's conventional oil production.
    For 2006 the Worsley pool was the focus of the Company's operations in
this area. We drilled 27 Charlie Lake oil wells in 2006, for a total of
118 vertical and 12 horizontal wells in the area.
    The horizontal drilling program at Worsley has produced very positive
results. One horizontal well replaces three vertical wells, at a cost saving
of $1.2 million. Horizontal wells allow successful drilling and production in
oil bearing rock layers where underlying water is recognized.
    In 2005, the Company initiated a waterflood program in this area that is
projected to increase the ultimate recovery factor for the pool to 25% from
15% on primary depletion. A total of eight wells have been converted to
injectors.
    The Worsley gas plant was successfully expanded with the installation of
a 15 mmcf/d amine unit in the first quarter of 2007. The plant is now capable
of processing 13 mmcf/d.
    2007 will focus on horizontal drilling and definition of pool boundaries.

    OPERATING RESULTS

    UNDEVELOPED LAND

    In 2006, we continued to maintain a dominant land position in our core
areas. The Company's total net land inventory increased 12% in 2006, with
acquisitions occurring primarily in the southern and central Alberta core
areas. Net undeveloped land increased 8% from the prior year. For 2006 we had
an 81% average working interest in our undeveloped land base, as opposed to
76% in 2005, reflecting Compton's strategy to establish high ownership levels
and control of operations.

    
    Land Summary

    -------------------------------------------------------------------------
                                     Undeveloped Acres           Total Acres
    Area                              Gross        Net      Gross        Net
    -------------------------------------------------------------------------

    Southern Alberta                495,854    473,444    907,134    822,966
    Central Alberta                 284,603    206,617    581,016    340,254
    Peace River Arch                102,400     71,775    196,960    119,188
    Northern Alberta                 41,888     15,572     68,769     23,207
    Other                            55,434     30,784     84,984     33,866
    -------------------------------------------------------------------------
    December 31, 2006 total         980,179    798,192  1,838,863  1,339,481
    -------------------------------------------------------------------------

    December 31, 2005 total         971,317    738,954  1,709,982  1,195,792
    -------------------------------------------------------------------------
    

    During 2007, we plan to continue to invest in the future and expand in
our core areas. Our 2007 budget includes $39 million directed towards land
acquisitions and seismic surveys in our major operating areas.

    DRILLING ACTIVITY

    We drilled 342 gross (274 net) wells in 2006 with a 94% success rate,
compared with 392 gross (334 net) wells drilled in 2005.
    Of the 342 wells drilled in 2006, 84% were classified as development
wells and 16% were classified as exploratory wells, compared to 80% and 20%
respectively in 2005. The higher percentage of development wells in the
current year reflects the increasing maturity of our oil and gas plays.

    
    Drilling Summary

    -------------------------------------------------------------------------
                             Natural
    Years ended December 31,     Gas     Oil     D&A   Total     Net Success
    -------------------------------------------------------------------------

    Southern Alberta             184       1       4     189     167     98%
    Central Alberta               56       9       5      70      47     93%
    Peace River Arch              11      46      11      68      46     84%
    -------------------------------------------------------------------------
                                 251      56      20     327     260     94%
    Standing, cased wells                                 15      14
    -------------------------------------------------------------------------
    2006 Total                                           342     274
    -------------------------------------------------------------------------

    2005 Total                   261     114      17     392     334
    -------------------------------------------------------------------------
    


    RESERVES

    For the year ended December 31, 2006, Netherland, Sewell & Associates,
Inc. ("NSAI") independently evaluated 94% of Compton's reserves and audited
the Company's internal evaluation of the remaining 6%.
    As required by National Instrument 51-101 "Standards of Disclosure for
Oil and Gas Activities" ("NI 51-101"), Compton filed Form 51-101 F1 as part of
our Annual Information Form ("AIF"). The AIF is considered comprehensive.
Certain information has been summarized below regarding the Company's
operations. All such information is consistent with the Form NI 51-101 F1
filing. Compton's extended disclosure contained in the AIF is available on
both the SEDAR website and Compton's website.
    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 and the calculation of finding,
development, and acquisition costs. The impact of these sales on corporate
indebtedness as at December 31, 2006 is set out in the Liquidity and Capital
Resource section of Management's Discussion and Analysis in this Annual
Report.

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

    -------------------------------------------------------------------------
                                 Crude Oil      Natural Gas         NGLs
                               Gross     Net   Gross     Net   Gross     Net
    As at December 31, 2006    (Mbbl)  (Mbbl)   (Bcf)   (Bcf)  (Mbbl)  (Mbbl)
    -------------------------------------------------------------------------

    Proved
      Developed producing     15,065  13,985     443     362   8,021   5,734
      Developed non-producing  1,714   1,592      69      57   1,152     795
      Undeveloped              3,220   2,752     175     146   2,016   1,473
    -------------------------------------------------------------------------
    Total proved              19,999  18,329     687     565  11,189   8,002
    Probable                   9,234   7,884     502     419   7,879   5,759
    -------------------------------------------------------------------------
    Total proved plus
     probable                 29,233  26,213   1,189     984  19,068  13,761
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    2005 total proved plus
     probable                 28,493  25,488     954     788  16,628  12,070
    -------------------------------------------------------------------------


    -----------------------------------------------------------
                                      Sulphur          Total
                               Gross     Net    Gross     Net
    As at December 31, 2006     (Mlt)   (Mlt)   (Mboe)  (Mboe)
    -----------------------------------------------------------

    Proved
      Developed producing      1,392   1,237   98,337   81,302
      Developed non-producing     50      40   14,364   11,893
      Undeveloped                115      96   34,517   28,693
    -----------------------------------------------------------
    Total proved               1,557   1,373  147,218  121,888
    Probable                     714     603  101,537   84,007
    -----------------------------------------------------------
    Total proved plus
     probable                  2,271   1,975  248,755  205,895
    -----------------------------------------------------------

    -----------------------------------------------------------
    2005 total proved plus
     probable                  2,545   2,221 206,672 171,031
    -----------------------------------------------------------
    (1) Numbers may not add due to rounding.


    In 2006, we added 42.2 MMboe, after production, to our proved plus
probable reserves primarily through the drill bit. Total proved plus probable
reserves increased 20% from the prior year to 249 MMboe.
    Our total proved reserve base is comprised of 78% natural gas and 22%
liquids. Proved producing reserves comprise 67% of total proved reserves,
while total proved reserves account for 59% of the proved plus probable
reserves. We have a 12 year proved reserve life index.


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

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

    Proved
      Producing                          $   2,774   $    1,446   $    1,302
      Non-producing                            546          274          242
      Undeveloped                            1,072          438          363
    -------------------------------------------------------------------------
    Total proved                         $   4,392   $    2,158   $    1,907
    Probable                                 3,241        1,154          938
    -------------------------------------------------------------------------
    Total proved plus probable           $   7,633   $    3,312   $    2,845
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    2005 proved plus probable            $   6,199   $    2,842   $    2,493
    -------------------------------------------------------------------------
    (1) Pricing assumptions are the average of four major Canadian oil and
        gas evaluation firms. Numbers may not add due to rounding.

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


    iii) Reserve Reconciliation (net after royalties) - Forecast Prices and
         Costs

    -------------------------------------------------------------------------
                      Crude Oil, NGLs, and Sulphur        Natural Gas
    -------------------------------------------------------------------------
                                             Net                       Net
                                           Proved                     Proved
                           Net      Net     Plus     Net      Net      Plus
                         Proved  Probable Probable  Proved Probable Probable
                         (Mbbl)   (Mbbl)   (Mbbl)   (MMcf)   (MMcf)   (MMcf)
    -------------------------------------------------------------------------

    December 31, 2005    28,731   11,047   39,778  449,790  337,719  787,509
    Extensions              916    1,033    1,949   27,309   20,086   47,395
    Improved recovery     1,027    1,069    2,096   50,394  125,247  175,641
    Technical revisions    (667)     620      (47)  75,206  (84,481)  (9,275)
    Discoveries             317       54      371    4,312    4,441    8,753
    Acquisitions            222      437      659   11,331   16,982   28,313
    Dispositions           (229)     (14)    (243) (12,939)  (1,426) (14,365)
    Production           (2,613)       0   (2,613) (40,300)       0  (40,300)
    -------------------------------------------------------------------------
    December 31, 2006    27,704   14,246   41,950  565,102  418,568  983,671
    -------------------------------------------------------------------------
    

    FINDING & DEVELOPMENT COSTS

    Our 2006 reserve report was reduced by property sales that closed
subsequent to year end. Accordingly, Finding, Development and Acquisition
("FD&A") costs have been calculated giving effect to the net proceeds realized
on the dispositions. It should be noted that the aggregate of the exploration
and development costs incurred in 2006 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.

    
    -------------------------------------------------------------------------
                                                                      3 Year
    FD&A costs ($/boe)                 2006       2005       2004    Average
    -------------------------------------------------------------------------

    Including future capital
      Proved                         $18.45     $15.42     $14.91     $16.37
      Proved plus probable           $13.56     $13.02     $13.19     $13.19

    Excluding future capital
      Proved                         $14.36     $12.84     $13.87     $13.61
      Proved plus probable           $ 8.84     $ 7.05     $ 8.51     $ 7.97
    -------------------------------------------------------------------------

    FINANCIAL REVIEW

    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.
    


    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.

    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) loss                         (18,027)       6,345        1,338
      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
    -------------------------------------------------------------------------


    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                     $     6.19   $     8.27   $     6.18
      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

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


    
    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.


    
    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.


    
    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.
    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.


    
    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.

    
    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.


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

    In November 2005, we completed a tender offer and consent solicitation to
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.


    
    NETBACKS

    -------------------------------------------------------------------------
    Years ended December 31, ($/boe)          2006         2005         2004
    -------------------------------------------------------------------------

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


    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.

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


    A. 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.

    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.

    
    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.

    INCOME TAXES

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

    CURRENT INCOME TAXES

    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.

    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.

    
    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.

    
    TAX POOLS

    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.

    
    CAPITAL EXPENDITURES

    SUMMARY OF CAPITAL EXPENDITURES

    -------------------------------------------------------------------------
    Years ended December 31,    2006             2005             2004
    -------------------------------------------------------------------------
                              ($000s)    %     ($000s)    %     ($000s)    %
    -------------------------------------------------------------------------

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

    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 million 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.
    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. These funds 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 effect on 2007 capital efficiencies.

    
    LIQUIDITY AND CAPITAL RE

SOURCES ------------------------------------------------------------------------- As at December 31, 2006 Pro ($000s, except where noted) forma(3) 2006 2005 2004 ------------------------------------------------------------------------- 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 $213,992 $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% ------------------------------------------------------------------------- (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 sales 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 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. 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. ------------------------------------------------------------------------- Payments Due by Period Less than After ($000s) 1 year 1-3 years 4-5 years 5 years ------------------------------------------------------------------------- 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 $24,000 ------------------------------------------------------------------------- We have the ability and the intention to extend the term of our bank borrowings and therefore repayment of the facility is not included in the schedule of contractual obligations above. OUTLOOK AND GUIDANCE FOR 2007 Consistent with general industry thinking, we are of the opinion that natural gas prices will strengthen significantly during 2007. We are also of the opinion that the cost of specific goods and services will moderate during the year. In the interim, we believe it prudent to move forward with a relatively moderate capital spending program. During 2007, the majority of our activities will focus on the continued development and delineation of our natural gas resource plays. We will concentrate on development drilling and the acceleration of on-stream timing with a view to production growth. At the same time, increased emphasis will be placed on capital discipline and efficiency. Equally important is our need to increase our complement of qualified personnel for the expansion of operations necessary to realize on our opportunities in an efficient manner. We view the current reduction in industry activity as an opportunity to attract additional staff in preparation for increased drilling programs in the last half of 2007 and into 2008. The following section summarizes our plans and guidance for 2007. SUMMARY OF 2007 GUIDANCE ------------------------------------------------------------------------- 2007 Budget Range ------------------------------------------------------------------------- Capital expenditures ($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 ------------------------------------------------------------------------- The average Canadian/U.S. exchange rate is budgeted at $0.89 U.S. = $1.00 Cdn. CASH FLOW SENSITIVITIES FOR 2007 ------------------------------------------------------------------------- ($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. SELECTED QUARTERLY INFORMATION ------------------------------ The following tables set out selected quarterly financial information for the last two fiscal years. ------------------------------------------------------------------------- Three Months Ended Year Ended ------------------------------------------------------------------------- ($000s, except March 31, June 30, Sept. 30, Dec. 31, Dec. 31, where noted) 2006 2006 2006 2006 2006 ------------------------------------------------------------------------- Average production (boe/d) 34,029 32,645 32,843 33,245 33,187 Average pricing ($/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 ------------------------------------------------------------------------- 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. ------------------------------------------------------------------------- Three Months Ended Year Ended ------------------------------------------------------------------------- ($000s, except March 31, June 30, Sept. 30, Dec. 31, Dec. 31, where noted) 2005 2005 2005 2005 2005 ------------------------------------------------------------------------- Average production (boe/d) 28,714 28,877 29,041 31,042 29,424 Average pricing ($/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 ------------------------------------------------------------------------- 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. 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. 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. Non-GAAP Financial Measures Included herein 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. 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. ------------------------------------------------------------------------- Compton Petroleum Corporation Consolidated Balance Sheets (unaudited)(thousands of dollars) ------------------------------------------------------------------------- December 31, December 31, Assets 2006 2005 Current Cash $ 12,232 $ 8,954 Accounts receivable 83,535 122,073 Unrealized risk management gain (Note 16a (i)) 22,625 - Other current assets (Note 16b (ii)) 24,513 10,726 Future income taxes (Note 15b) 1,479 2,609 ------------ ------------ 144,384 144,362 Property and equipment (Note 4 and 19) 1,977,062 1,587,371 Goodwill (Note 2) 7,914 7,914 Deferred financing charges and other (Note 8) 14,144 12,841 Deferred risk management loss (Note 16a (ii)) 3,968 5,610 ------------ ------------ $2,147,472 $1,758,098 ------------ ------------ ------------ ------------ Liabilities Current Accounts payable $ 141,443 $ 203,869 Unrealized risk management loss (Note 16a (i) and (iii)) 4,604 7,758 Future income taxes (Note 15b) 7,269 - ------------ ------------ 153,316 211,627 Bank debt (Note 5) 330,000 177,900 Senior term notes (Note 6) 524,385 357,640 Asset retirement obligations (Note 10) 29,791 20,770 Unrealized risk management loss (Note 16a (iii)) 6,816 10,201 Future income taxes (Note 15b) 302,690 314,726 Non-controlling interest (Note 3) 66,350 68,898 ------------ ------------ 1,413,348 1,161,762 ------------ ------------ Shareholders' equity Capital stock (Note 11b) 231,992 226,444 Contributed surplus (Note 12a) 16,974 9,173 Retained earnings 485,158 360,719 ------------ ------------ 734,124 596,336 ------------ ------------ $2,147,472 $1,758,098 ------------ ------------ ------------ ------------ Commitments and contingent liabilities (Note 18) Subsequent events (Note 19) See accompanying notes to the consolidated financial statements. ------------------------------------------------------------------------- Compton Petroleum Corporation Consolidated Statements of Earnings (unaudited) (thousands of dollars, except per share data) ------------------------------------------------------------------------- Three months ended Years ended December 31, December 31, -------------------- -------------------- 2006 2005 2006 2005 --------- --------- --------- --------- Revenue Oil and natural gas revenues $ 127,902 $ 184,428 $ 533,656 $ 557,879 Royalties (29,182) (43,524) (123,677) (132,717) --------- --------- --------- --------- 98,720 140,904 409,979 425,162 --------- --------- --------- --------- Expenses Operating 27,316 18,929 95,462 66,802 Transportation 3,214 3,118 12,564 10,858 General and administrative 7,422 6,864 26,231 21,223 Interest and finance charges (Note 7) 15,926 10,741 54,075 34,951 Tender costs (Note 8) - 20,750 - 20,750 Depletion and depreciation 37,036 31,005 143,057 105,504 Foreign exchange (gain) loss (Note 9) 22,708 (347) (891) (7,353) Accretion of asset retirement obligations (Note 10) 632 559 2,257 1,975 Stock-based compensation (Note 12a and c) 3,616 1,649 10,488 5,903 Risk management (gain) loss (Note 16a (iv)) (6,028) (16,808) (63,721) 19,302 --------- --------- --------- --------- 111,842 76,460 279,522 279,915 --------- --------- --------- --------- Earnings before taxes and non-controlling interest (13,122) 64,444 130,457 145,247 --------- --------- --------- --------- Income taxes (Note 15a) Current 21 3,597 44 5,071 Future (5,530) 21,261 (3,636) 52,317 --------- --------- --------- --------- (5,509) 24,858 (3,592) 57,388 --------- --------- --------- --------- Earnings before non-controlling interest (7,613) 39,586 134,049 87,859 Non-controlling interest (Note 3) 2,424 1,480 6,623 6,533 --------- --------- --------- --------- Net earnings $ (10,037) $ 38,106 $ 127,426 $ 81,326 --------- --------- --------- --------- --------- --------- --------- --------- Net earnings per share (Note 13) Basic $ (0.08) $ 0.30 $ 1.00 $ 0.65 --------- --------- --------- --------- --------- --------- --------- --------- Diluted $ (0.07) $ 0.28 $ 0.95 $ 0.62 --------- --------- --------- --------- --------- --------- --------- --------- Consolidated Statements of Retained Earnings (unaudited) (thousands of dollars) ------------------------------------------------------------------------- Three months ended Years ended December 31, December 31, -------------------- -------------------- 2006 2005 2006 2005 --------- --------- --------- --------- Retained earnings, beginning of year $ 495,727 $ 323,311 $ 360,719 $ 284,712 Net earnings (10,037) 38,106 127,426 81,326 Premium on redemption of shares (Note 11b) (532) (698) (2,987) (5,319) --------- --------- --------- --------- Retained earnings, end of year $ 485,158 $ 360,719 $ 485,158 $ 360,719 --------- --------- --------- --------- --------- --------- --------- --------- See accompanying notes to the consolidated financial statements. ------------------------------------------------------------------------- Compton Petroleum Corporation Consolidated Statements of Cash Flow (unaudited) (thousands of dollars) ------------------------------------------------------------------------- Three months ended Years ended December 31, December 31, -------------------- -------------------- 2006 2005 2006 2005 --------- --------- --------- --------- Operating activities Net earnings $ (10,037) $ 38,106 $ 127,426 $ 81,326 Amortization of deferred charges and other 401 743 1,996 2,190 Tender costs - 20,750 - 20,750 Depletion and depreciation 37,036 31,005 143,057 105,504 Accretion of asset retirement obligations 632 559 2,257 1,975 Unrealized foreign exchange (gain) loss 22,500 (796) (665) (7,808) Future income taxes (5,530) 21,261 (3,636) 52,317 Unrealized risk management (gain) loss 6,073 (24,759) (27,522) 10,171 Stock-based compensation 2,249 1,649 9,121 5,903 Asset retirement expenditures (485) (358) (2,352) (749) Non-controlling interest 2,424 1,480 6,623 6,533 --------- --------- --------- --------- 55,263 89,640 256,305 278,112 Change in non-cash working capital (Note 17) 23,087 11,809 18,901 8,441 --------- --------- --------- --------- 78,350 101,449 275,206 286,553 --------- --------- --------- --------- Financing activities Issuance (repayment) of bank debt 50,000 (82,100) 152,100 (42,100) Issuance of senior notes - 353,130 174,930 353,130 Issue costs on senior notes - (12,670) (3,408) (12,670) Redemption of senior notes - (199,973) (7,520) (199,973) Proceeds from share issuances, net 598 331 4,672 89,752 Distributions to partner (2,293) (2,293) (9,171) (9,172) Redemption of common shares (635) (790) (3,433) (6,118) Change in non-cash working capital (Note 17) (8,092) (6,679) 1,278 (1,829) --------- --------- --------- --------- 39,578 48,956 309,448 171,020 --------- --------- --------- --------- Investing activities Property and equipment additions (88,453) (161,186) (490,429) (484,213) Property acquisitions (3,603) (11,376) (34,444) (28,575) Property dispositions - - 1,350 - Change in non-cash working capital (Note 17) (35,636) 14,211 (57,853) 54,101 --------- --------- --------- --------- (127,692) (158,351) (581,376) (458,687) --------- --------- --------- --------- Change in cash (9,764) (7,946) 3,278 (1,114) Cash, beginning of year 21,996 16,900 8,954 10,068 --------- --------- --------- --------- Cash, end of year $ 12,232 $ 8,954 $ 12,232 $ 8,954 --------- --------- --------- --------- --------- --------- --------- --------- See accompanying notes to the consolidated financial statements. ------------------------------------------------------------------------- Compton Petroleum Corporation Notes to the Consolidated Financial Statements December 31, 2006 (unaudited) (Tabular amounts in thousands of dollars, unless otherwise stated) ------------------------------------------------------------------------- 1. Significant accounting policies Compton Petroleum Corporation (the "Company" or "Compton") is in the business of the exploration for and production of petroleum and natural gas reserves in the Western Canada Sedimentary Basin. a) Basis of presentation The consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in Canada within the framework of the accounting policies summarized below. The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. The consolidated financial statements also include the accounts of Mazeppa Processing Partnership in accordance with Accounting Guideline 15 ("AcG-15") "Consolidation of Variable Interest Entities", as outlined in Note 3. All amounts are presented in Canadian dollars unless otherwise stated. b) Measurement uncertainty The timely preparation of financial statements requires that Management make estimates and assumptions and use judgment regarding assets, liabilities, revenues, and expenses. Such estimates relate primarily to transactions and events that have not settled as of the date of the financial statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur. Amounts recorded for depletion and depreciation, and amounts used in impairment test calculations are based upon estimates of petroleum and natural gas reserves and future costs to develop those reserves. By their nature, these estimates of reserves, costs, and related future cash flows are subject to uncertainty, and the impact on the consolidated financial statements of future periods could be material. The calculation of asset retirement obligations includes estimates of the ultimate settlement amounts, inflation factors, credit adjusted discount rates, and timing of settlement. The impact of future revisions to these assumptions on the consolidated financial statements of future periods could be material. The values of pension assets and obligations and the amount of pension costs charged to net earnings depend on certain actuarial and economic assumptions which by their nature are subject to measurement uncertainty. c) Property and equipment i) Capitalized costs The Company follows the full cost method of accounting for its petroleum and natural gas operations within one Canadian cost centre. Under this method all costs related to the exploration for and development of petroleum and natural gas reserves are capitalized. Costs include lease acquisition costs, geological and geophysical expenses, costs of drilling both producing and non-producing wells, production facilities, future asset retirement costs, and certain general and administrative expenses directly related to exploration and development activities. Proceeds from the sale of properties are applied against capitalized costs, without any gain or loss being realized, unless such sale would significantly alter the rate of depletion and depreciation. Expenditures related to renewals or betterments that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs, other than major turnaround costs, are expensed as incurred. Major turnaround costs are included in property and equipment when incurred and charged to depletion and depreciation in the consolidated statement of earnings over the estimated period of time to the next scheduled turnaround. ii) Depletion and depreciation Depletion and depreciation of property and equipment is provided using the unit-of-production method based upon estimated proved petroleum and natural gas reserves. The costs of significant undeveloped properties are excluded from costs subject to depletion until it is determined whether or not proved reserves are attributable to the properties or impairment has occurred. Estimated future costs to be incurred in developing proved reserves are included and estimated salvage values are excluded in costs subject to depletion. For depletion and depreciation purposes, relative volumes of natural gas production and reserves are converted at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil. Depreciation of certain midstream facilities is provided for on a straight line basis over 30 years and depreciation of office equipment is provided for on a declining balance basis which ranges from 20% to 30% per year. iii) Impairment test At each reporting period the Company performs an impairment test to determine the recoverability of capitalized costs associated with reserves. An impairment loss is recognized when the carrying amount of a cost centre exceeds its fair value. The carrying amount of the cost centre is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows from proved reserves plus the costs of unproved properties. If the sum of the cash flows is less than the carrying amount, the impairment loss is limited to the amount by which the carrying amount exceeds the sum of the fair value of discounted proved and probable reserves and the costs of unproved properties that have been subject to a separate impairment test and contain no probable reserves. iv) Asset retirement obligations The Company recognizes the fair value of estimated asset retirement obligations on the consolidated balance sheet when a reasonable estimate of fair value can be made. Asset retirement obligations include those legal obligations where the Company will be required to retire tangible long-lived 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-lived asset. Changes in the estimated obligation resulting from revisions to estimated timing or amount of undiscounted cash flows are recognized as a change in the asset retirement obligation and the related asset retirement cost. Asset retirement costs are amortized using the unit-of-production method and are included in depletion and depreciation in the consolidated statement of earnings. 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. Actual expenditures incurred are charged against the accumulated obligation. v) Inventories Physical inventory held for exploration, development, and operating activities is included in property and equipment and is valued at cost. d) Goodwill Goodwill is recorded on a corporate acquisition when the purchase price is in excess of the fair values assigned to assets acquired and liabilities assumed. Goodwill is not amortized and an impairment test is performed at least annually to evaluate the carrying value. To assess impairment, the fair value of the consolidated entity, excluding the Mazeppa Processing Partnership, is determined and compared to the carrying value. If the fair value is less than the carrying value then a second test is performed to determine the amount of the impairment. Any loss recognized is equal to the difference between the implied fair value and the carrying value of the goodwill. e) Financial instruments and derivatives Financial instruments consist mainly of cash, accounts receivable, other current assets, accounts payable, and long-term debt. The Company uses derivative financial instruments for non-trading purposes to manage fluctuations in commodity prices, foreign currency exchange rates, and interest rates as outlined in Note 16. The Company has elected not to designate any of its current risk management activities as accounting hedges and accounts for all derivative financial instruments using the mark-to-market accounting method. f) Joint operations Certain petroleum and natural gas activities are conducted jointly with others. These consolidated financial statements reflect only the Company's proportionate interest in such activities. g) Earnings per share amounts The Company uses the treasury stock method to determine the dilutive effect of stock options. This method assumes that proceeds received from the exercise of in-the-money stock options are used to repurchase common shares at the average market price for the period. Basic net earnings per common share are determined by dividing net earnings by the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed by giving effect to the potential dilution that would occur if stock options were exercised. h) Income taxes Income taxes are recorded using the liability method of accounting. Future income taxes are calculated based on the difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates. Changes in income tax rates that are substantively enacted are reflected in the period the change occurs. i) Revenue recognition Revenue associated with the production and sale of crude oil, natural gas, and natural gas liquids owned by the Company is recognized when title passes to the customer and delivery has taken place. Revenue as reported, represents the Company's share and is presented before royalty payments to governments and other mineral interest owners. Other revenue is recognized in the period that the service is provided to the customer. j) Stock-based compensation plan The Company records compensation expense in the consolidated statements of earnings for stock options granted to Directors, Officers, and employees using the fair-value method. Compensation costs are recognized over the vesting period and the fair values are determined using the Black-Scholes option pricing model. The Company also has an employee stock savings plan. The contributions are recorded as compensation expense as incurred. k) Deferred financing charges Financing costs related to the issuance of senior term notes are deferred and are amortized over the term of the notes on a straight- line basis. If the notes are retired, in whole or in part, prior to maturity, a pro-rata share of the unamortized balance is expensed in the consolidated statement of earnings. l) Foreign currency translation Monetary assets and liabilities of the Company that are denominated in foreign currencies are translated into Canadian dollars at the period-end exchange rate, with any resulting gain or loss recorded in the consolidated statement of earnings. m) Dividend policy The Company has neither declared nor paid any dividends on its common shares. The Company intends to retain its earnings to finance growth and expand its operations and does not anticipate paying any dividends on its common shares in the foreseeable future. n) Defined benefit pension plan The Company accrues for obligations under a defined benefit pension plan and the related costs, net of plan assets for employees of Mazeppa Processing Partnership. The cost of the pension is actuarially determined using the projected benefit method based on length of service and reflects Management's best estimate of expected plan investment performance, salary escalation, and retirement age of employees. o) Recent accounting pronouncements 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 earnings. As well, all financial instruments, including derivatives, are to be included in the Company's 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 the Company's financial statements which currently reflect 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. The Company has assessed the impact of these new accounting standards on the consolidated financial statements at January 1, 2007 and has determined that: - The balance in deferred financing charges will no longer be disclosed separately but will be netted against the corresponding senior term notes. - The presentation of accumulated other comprehensive income will be similar to the presentation of United States accounting principles and reporting included in Note 20. - The measurement and recording of financial instruments at fair value will not have a material impact on the Company's consolidated financial statements. In July 2006, the CICA replaced Handbook Section 1506, "Accounting Changes" with a new Section 1506, "Accounting Changes" to substantially 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. The Company does not expect the application of this revised standard to have a material impact on the 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". These new standards will require increased disclosure of financial instruments with particular emphasis on the risks associated with recognized and unrecognized financial instruments and how those risks are managed. The standards are effective for fiscal years beginning on or after October 1, 2007 and the Company is 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 the Company is currently assessing the impact on the consolidated financial statements. p) Reclassification Certain amounts disclosed for prior years have been reclassified to conform with current period presentation. 2. Business combinations On April 12, 2004 and November 15, 2004, respectively, the Company acquired 100% of the issued and outstanding shares of Redwood Energy, Ltd. and Mayfair Energy Ltd. for total cash consideration of $12.1 million plus the assumption of $12.1 million of debt. Both entities were independent exploration and production companies with operations in the Company's core areas. The business combinations have been accounted for using the purchase method with results of operations included in the consolidated financial statements from the date of acquisition. Goodwill recognized on these transactions amounted to $7.9 million. During the year ended December 31, 2004, both companies were wound up into Compton Petroleum Corporation and dissolved. 3. Non-controlling interest Mazeppa Processing Partnership ("MPP" or "the Partnership") is a limited partnership organized under the laws of the province of Alberta and owns certain midstream facilities, including gas plants and pipelines in Southern Alberta. The Company processes a significant portion of its production from the area through these facilities pursuant to a processing agreement with MPP. The Company does not have an ownership position in MPP, however, the Company, through a management agreement, manages the activities of MPP and is considered to be the primary beneficiary of MPP's operations. Pursuant to AcG-15, these consolidated financial statements include the assets, liabilities, and operations of the Partnership. Equity in the Partnership, attributable to the partners of MPP, is recorded on consolidation as a non-controlling interest and is comprised of the following: As at December 31, 2006 2005 ------------ ------------ Non-controlling interest, beginning of year $ 68,898 $ 71,537 Earnings attributable to non-controlling interest 6,623 6,533 Distributions to limited partner (9,171) (9,172) ------------ ------------ Non-controlling interest, end of year $ 66,350 $ 68,898 ------------ ------------ ------------ ------------ Commencing May 1, 2004, pursuant to the terms of a processing agreement between Compton and MPP, Compton pays a monthly fee to MPP for the transportation and processing of natural gas through the MPP owned facilities. The fee is comprised of a fixed base fee of $764 thousand per month plus MPP operating costs, net of third party revenues. These amounts are eliminated from revenues and expenses on consolidation. The processing agreement has a five year term ending April 1, 2009, at which time Compton may renew the agreement under terms determined at that time or purchase the Partnership units for the predetermined amount of $55 million, deemed to be fair value. In the event that the Company does not renew the processing agreement nor exercise the purchase option, the Limited Partner may dispose of the Partnership units to an independent third party. MPP has guaranteed payment of certain obligations of its limited partner under a credit agreement between the limited partner and a syndicate of lenders. The maximum liability of the Partnership under the guarantee is limited to amounts due and payable to MPP by the Company pursuant to the processing agreement. The maximum liability at December 31, 2006 was $21.4 million (2005 - $30.6 million) payable over the remaining term of the processing agreement. The Company has determined that its exposure to loss under these arrangements is minimal, if any. 4. Property and equipment Accumulated depletion and As at December 31, 2006 Cost depreciation Net ------------ ------------ ----------- Exploration and development costs $1,931,594 $(482,524) $1,449,070 Production equipment and processing facilities 582,705 (77,863) 504,842 Inventory 6,818 - 6,818 Future asset retirement costs 17,128 (4,906) 12,222 Office equipment 9,359 (5,249) 4,110 ------------ ------------ ----------- $2,547,604 $(570,542) $1,977,062 ------------ ------------ ----------- ------------ ------------ ----------- Accumulated depletion and As at December 31, 2005 Cost depreciation Net ------------ ------------ ----------- Exploration and development costs $1,553,543 $(366,902) $1,186,641 Production equipment and processing facilities 436,948 (52,771) 384,177 Inventory 6,469 - 6,469 Future asset retirement costs 10,365 (3,771) 6,594 Office equipment 7,641 (4,151) 3,490 ------------ ------------ ----------- $2,014,966 $(427,595) $1,587,371 ------------ ------------ ----------- ------------ ------------ ----------- At December 31, 2006, $9.6 million (2005 - $11.1 million) relating to employee salaries, insurance costs and overhead recoveries determined in accordance with industry procedures were capitalized. As at December 31, 2006, future capital expenditures of $329.7 million (2005 - $192.9 million, 2004 - $89.1 million), as estimated by independent reserve engineers, relating to the development of proved reserves have been included in costs subject to depletion. The estimated salvage value of production equipment and processing facilities at December 31, 2006 was $120.1 million (2005 - $108.6 million, 2004 - $81.0 million) and was excluded from costs subject to depletion. Undeveloped properties with a cost at December 31, 2006 of $202.9 million (2005 - $251.3 million, 2004 - $187.8 million) included in exploration and development costs, have not been subject to depletion. The prices used in the evaluation of the carrying value of the Company's reserves for the purposes of the impairment test are: Natural As at December 31, 2006 gas Oil NGL ------------ ------------ ----------- $ per mcf $ per bbl $ per bbl 2007 7.77 63.95 60.66 2008 8.27 65.20 60.10 2009 8.19 62.83 58.37 2010 8.18 60.37 56.69 2011 8.37 58.72 55.21 Approximate % increase thereafter 2.0% 2.0% 2.0% 5. Credit facilities As at December 31, 2006 2005 ------------ ------------ Authorized $ 500,000 $ 289,000 ------------ ------------ ------------ ------------ Prime rate $ 35,000 $ 22,900 Bankers' Acceptance 295,000 155,000 ------------ ------------ Utilized $ 330,000 $ 177,900 ------------ ------------ ------------ ------------ As at December 31, 2006, the Company had arranged authorized senior credit facilities with a syndicate of banks in the amount of $500 million. Advances under the facilities can be drawn and currently bear interest as follows: Prime rate plus 0.75% Bankers' Acceptance rate plus 1.75% LIBOR rate plus 1.75% Margins are determined based on the ratio of total consolidated debt to consolidated cash flow. The facilities reach term on July 4, 2007 and, if not renewed, will mature 366 days later on July 5, 2008. The senior credit facilities are secured by a first fixed and floating charge debenture in the amount of $1.0 billion covering all the Company's assets and undertakings. 6. Senior term notes As at December 31, 2006 2005 ------------ ------------ Senior term notes US$450 million, 7.625% due December 1, 2013 $ 524,385 $ 349,770 US$6.75 million, 9.90% due May 15, 2009 - 7,870 ------------ ------------ $ 524,385 $ 357,640 ------------ ------------ ------------ ------------ On April 4, 2006, the Company issued an additional U.S.$150 million 7.625% senior term notes due 2013 under the same terms and conditions as the 7.625% notes outstanding at December 31, 2005. The proceeds from the issue of the notes were used to repay a portion of the debt outstanding under the Company's senior credit facilities. The Company also used a portion of the proceeds to redeem the balance of the U.S.$6.75 million 9.90% senior notes on May 16, 2006, being the first call date, at 104.95%. In November 2005, the Company and a wholly owned subsidiary of the Company completed a tender offer and consent solicitation to amend the Indenture relating to the 9.9% notes. The Company and a wholly owned subsidiary paid 107.195% plus accrued and unpaid interest for the U.S. 158.25 million 9.9% notes tendered by the note holders. Information related to the tender costs can be found in note 8. The 7.625% notes are not redeemable by the Company prior to December 1, 2009, except in limited circumstances. After that time, they can be redeemed in whole or part, at the rates indicated below: December 1, 2009 103.813% December 1, 2010 101.906% December 1, 2011 and thereafter 100.000% The senior term notes are subordinate to the Company's senior credit facilities. 7. Interest and finance charges Amounts charged to expense during the year ended are as follows: Years ended December 31, 2006 2005 2004 ------------ ------------ ----------- Interest on bank debt, net $ 15,356 $ 11,520 $ 9,662 Interest on senior term notes 35,880 20,912 21,281 Finance charges 2,839 2,519 2,790 ------------ ------------ ----------- Total $ 54,075 $ 34,951 $ 33,733 ------------ ------------ ----------- ------------ ------------ ----------- Finance charges include the amortization of deferred charges and other current year expenses. The effective interest rate on bank debt at December 31, 2006 was 5.6% (2005 - 4.2%). 8. Deferred financing charges and other The following table presents the reconciliation of the beginning and ending aggregate carrying amount of deferred financing charges associated with the issue of senior term notes: Years ended December 31, 2006 2005 ------------ ------------ Deferred financing charges and other, beginning of year $ 12,841 $ 9,729 Issue costs on 7.625% Senior Notes 3,408 12,670 Pro-rata reduction on repayment of 9.90% Senior Notes (293) (7,053) Amortization expense (1,905) (2,119) Other 93 (386) ------------ ------------ Deferred financing charges and other, end of year $ 14,144 $ 12,841 ------------ ------------ ------------ ------------ Costs incurred on the tender for the 9.90% senior term notes in 2005 were as follows: 2005 ------------ Premium payment $ 7,814 Consent solicitation fee 5,883 Pro-rata reduction of deferred financing charges on repayment of 9.90% Senior Notes 7,053 ------------ Total $ 20,750 ------------ ------------ The balance of the 9.9% senior notes were purchased in 2006 pursuant to a call option provision and no additional tender costs were incurred. 9. Foreign exchange (gain) loss Amounts charged to foreign exchange (gain) loss during the year ended were as follows: Years ended December 31, 2006 2005 2004 ------------ ------------ ----------- Foreign exchange gain on translation of US$ debt $ (665) $ (7,808) $ (14,652) Other foreign exchange (gain) loss (226) 455 21 ------------ ------------ ----------- Total $ (891) $ (7,353) $ (14,631) ------------ ------------ ----------- ------------ ------------ ----------- 10. Asset retirement obligations The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the obligations associated with the retirement of oil and natural gas assets: As at December 31, 2006 2005 ------------ ------------ Asset retirement obligations, beginning of year $ 20,770 $ 18,006 Liabilities incurred 7,031 5,218 Liabilities settled and disposed (267) (1,275) Accretion expense 2,257 1,975 Revision of estimates - (3,154) ------------ ------------ Asset retirement obligations, end of year $ 29,791 $ 20,770 ------------ ------------ ------------ ------------ The total undiscounted amount of estimated cash flows required to settle the obligations was $233.0 million (2005 - $185.8 million), which has been discounted using a credit-adjusted risk free rate of 10.6% (2005 - 10.7%). The majority of these obligations are not expected to be settled for several years or decades into the future. Settlements will be funded from general Company resources at the time of retirement and removal. 11. Capital stock a) Authorized The Company is authorized to issue an unlimited number of common shares and an unlimited number of preferred shares, issuable in series. b) Issued and outstanding As at December 31, 2006 2005 -------------------- --------------------- Number Number of of Shares Amount Shares Amount --------- --------- --------- ---------- (000s) (000s) Common shares outstanding, beginning of year 127,263 $ 226,444 117,354 $ 135,526 Shares issued for cash, net - - 7,500 87,294 Shares issued under stock option plan 1,489 5,993 2,926 4,424 Shares repurchased (249) (445) (517) (800) --------- --------- --------- ---------- Common shares outstanding, end of year 128,503 $ 231,992 127,263 $ 226,444 --------- --------- --------- ---------- --------- --------- --------- ---------- The Company maintains a Normal Course Issuer Bid program on an annual basis. Under the current program, the Company may purchase for cancellation up to 6,000,000 of its common shares, representing approximately 5.0% of the issued and outstanding common shares at the time the bid received regulatory approval. During the year, the Company purchased for cancellation 248,900 common shares at an average price of $13.79 per share (2005 - 516,600 common shares at an average price of $11.84 per share) pursuant to the normal course issuer bid. The excess of the purchase price over book value has been charged to retained earnings. c) Shareholder rights plan The Company has a shareholder rights plan (the "Plan") to ensure all shareholders are treated fairly in the event of a take-over offer or other acquisition of control of the Company. Pursuant to the Plan, the Board of Directors authorized and declared the distribution of one Right in respect of each common share outstanding. In the event that an acquisition of 20% or more of the Company's shares is completed and the acquisition is not a permitted bid, as defined by the Plan, each Right will permit the holder to acquire common shares at a 50% discount to the market price at that time. 12. Stock-based compensation plans a) Stock option plan The Company has a stock option plan for employees, including Directors and Officers. The exercise price of each option approximated the market price for the common shares on the date the option was granted. Options granted under the plan before June 1, 2003 are generally fully exercisable after four years and expire ten years after the grant date. Options granted under the plan after June 1, 2003 are generally fully exercisable after four years and expire five years after the grant date. The following tables summarize the information relating to stock options: As at December 31, 2006 2005 -------------------- --------------------- Weighted Weighted average average Stock exercise Stock exercise options price options price --------- --------- --------- ---------- (000s) (000s) Outstanding, beginning of year 11,446 $ 6.13 11,655 $ 3.51 Granted 2,228 $ 13.99 2,930 $ 11.89 Exercised (1,489) $ 3.14 (2,926) $ 1.32 Cancelled (574) $ 10.92 (213) $ 8.30 --------- --------- --------- ---------- Outstanding, end of year 11,611 $ 7.79 11,446 $ 6.13 --------- --------- --------- ---------- --------- --------- --------- ---------- Exercisable, end of year 6,593 $ 4.82 6,219 $ 3.38 --------- --------- --------- ---------- --------- --------- --------- ---------- The range of exercise prices of stock options outstanding and exercisable at December 31, 2006 is as follows: Outstanding Options Exercisable Options ------------------------------------ ------------------------ Weighted average Weighted Weighted Range of Number of remaining average Number of average exercise options contractual exercise options exercise prices outstanding life (years) price outstanding price ----------- ------------- ----------- ----------- ----------- ----------- (000s) (000s) $1.25 - $2.99 1,859 2.2 $ 1.76 1,859 $ 1.76 $3.00 - $3.99 1,318 4.5 $ 3.51 1,242 $ 3.49 $4.00 - $4.99 1,402 5.1 $ 4.28 1,310 $ 4.25 $5.00 - $6.99 972 2.0 $ 5.86 727 $ 5.86 $7.00 - $9.99 1,267 2.4 $ 7.61 696 $ 7.61 $10.00 - $12.99 2,827 3.5 $11.64 660 $11.64 $13.00 - $18.39 1,966 4.1 $14.38 99 $13.62 ------------- ----------- ----------- ----------- ----------- 11,611 3.5 $ 7.79 6,593 $ 4.82 ------------- ----------- ----------- ----------- ----------- ------------- ----------- ----------- ----------- ----------- The Company has recorded stock-based compensation expense in the consolidated statement of earnings for stock options granted to employees, Directors, and Officers after January 1, 2003 using the fair value method. The fair value of each option granted is estimated on the date of grant using the Black-Scholes option pricing model with weighted average assumptions for grants as follows: Years ended December 31, 2006 2005 2004 ------------ ------------ ----------- Weighted average fair value of options granted $ 6.90 $ 5.45 $ 3.70 Risk-free interest rate 4.0% 3.6% 3.9% Expected life (years) 5.0 5.0 5.0 Expected volatility 43.5% 43.9% 49.6% The following table presents the reconciliation of contributed surplus with respect to stock-based compensation: As at December 31, 2006 2005 ------------ ------------ Contributed surplus, beginning of year $ 9,173 $ 3,840 Stock-based compensation expense 9,121 5,903 Stock options exercised (1,320) (570) ------------ ------------ Contributed surplus, end of year $ 16,974 $ 9,173 ------------ ------------ ------------ ------------ The Company has not recorded stock-based compensation expense in the consolidated statement of earnings related to stock options granted prior to 2003. If the Company had applied the fair value method to options granted prior to 2003, the effect would have been as follows: Years ended December 31, 2006 2005 2004 ------------ ------------ ----------- Reduction in net earnings $ 412 $ 1,007 $ 1,545 Reduction in net earnings per common share - basic and diluted $ 0.00 $ 0.01 $ 0.01 b) Share appreciation rights plan CICA Handbook section 3870 requires recognition of compensation costs with respect to changes in the intrinsic value for the variable component of fixed share appreciation rights ("SARs"). During the years ended December 31, 2006, 2005 and 2004, there were no significant compensation costs related to the outstanding variable component of these SARs. The liability related to the variable component of these SARs amounts to $1.2 million, which is included in accounts payable as at December 31, 2006 (2005 - $1.4 million). All outstanding SARs having a variable component expire at various times through 2011. c) Employee retention program In recognition of the shortage of qualified personnel that currently exists within the industry, the Company implemented an Employee Retention program in July 2006 for its existing employees, excluding Officers and Directors. Under the program and contingent upon various conditions present as at July 1, 2007, the Company may incur additional compensation costs to a maximum amount of $4.2 million. During the year ended December 31, 2006 $1.4 million has been recognized in stock-based compensation expense as a partial recognition of this potential liability. Any amount payable under the program will be paid on July 1, 2007 at which time the final amount will be fully determinable. 13. Per share amounts The following table summarizes the common shares used in calculating net earnings per common share: Years ended December 31, 2006 2005 2004 ------------ ------------ ----------- (000s) (000s) (000s) Weighted average common shares outstanding - basic 127,820 125,627 117,244 Effect of stock options 5,806 6,040 6,789 ------------ ------------ ----------- Weighted average common shares outstanding - diluted 133,626 131,667 124,033 ------------ ------------ ----------- ------------ ------------ ----------- In calculating diluted earnings per common share for the year ended December 31, 2006, the Company excluded 1,537,100 options (2005 - 331,800, 2004 - 288,000) as the exercise price was greater than the average market price of its common shares in those years. 14. Defined benefit pension plan There are 34 employees of MPP currently enrolled in a co-sponsored, defined benefit pension plan. The Company does not have a pension plan for other employees. Information relating to the MPP retirement plan is outlined below: As at December 31, 2006 2005 ------------ ------------ Accrued benefit obligation Accrued benefit obligation - beginning of year $ 7,562 $ 6,110 Current service cost 368 284 Interest cost 387 372 Benefits paid (392) (378) Actuarial (gain) loss (208) 1,174 ------------ ------------ Accrued benefit obligation - end of year $ 7,717 $ 7,562 ------------ ------------ ------------ ------------ Fair value of plan assets Fair value of plan assets - beginning of year $ 5,839 $ 5,221 Employee contributions 82 75 Employer contributions 439 308 Benefits paid (392) (378) Actual return on plan assets 667 613 ------------ ------------ Fair value of plan assets - end of year $ 6,635 $ 5,839 ------------ ------------ ------------ ------------ Accrued benefit asset Funded status - plan assets less than benefit obligation (1,082) (1,723) Unamortized net actuarial gain 414 891 Unamortized past service costs 793 862 ------------ ------------ Accrued benefit asset, included in deferred financing charges and other $ 125 $ 30 ------------ ------------ ------------ ------------ Economic assumptions used to determine benefit obligation and periodic expense were: Years ended December 31, 2006 2005 ------------ ------------ Discount rate 5.0% 5.0% Expected rate of return on assets 7.0% 7.0% Rate of compensation increase 3.5% 3.5% Average remaining service period of covered employees 16 years 15 years Actuarial evaluations are required every three years, the next evaluation being January 1, 2009. Pension expense, included in MPP operating costs, is as follows: Years ended December 31, 2006 2005 ------------ ------------ Current service cost $ 292 $ 232 Interest on accrued benefit obligation 387 372 Interest on assets (407) (364) Amortization on past service cost 69 69 Amortization of net actuarial loss 9 - ------------ ------------ Pension expense, included in operating expense $ 350 $ 309 ------------ ------------ ------------ ------------ MPP expects to contribute $437 thousand to the plan in 2007. 15. Income taxes a) The following table reconciles income taxes calculated at the Canadian statutory rate with actual income taxes: Years ended December 31, 2006 2005 2004 ------------ ------------ ----------- Earnings before taxes and non-controlling interest $ 130,457 $ 145,247 $ 103,234 ------------ ------------ ----------- Canadian statutory rate 34.5% 37.6% 38.6% Expected income taxes $ 45,008 $ 54,613 $ 39,848 Effect on taxes resulting from: Non-deductible Crown charges 2,145 15,061 17,611 Resource allowance (1,987) (11,980) (13,535) Non-deductible stock-based compensation 3,147 2,221 1,316 Federal capital tax - 1,896 2,526 Effect of tax rate changes (49,655) (5,764) (8,359) Non-taxable portion of capital items (115) - (2,831) Other (2,135) 1,341 (393) ------------ ------------ ----------- Provision for income taxes $ (3,592) $ 57,388 $ 36,183 ------------ ------------ ----------- ------------ ------------ ----------- Current Income taxes $ 44 $ 3,175 $ 225 Federal capital taxes - 1,896 2,526 Future (3,636) 52,317 33,432 ------------ ------------ ----------- $ (3,592) $ 57,388 $ 36,183 ------------ ------------ ----------- ------------ ------------ ----------- Effective tax rate (2.8)% 39.5% 35.0% ------------ ------------ ----------- ------------ ------------ ----------- A significant portion of the Company's taxable income is generated by a partnership. Income taxes are incurred on the majority of the partnership's taxable income in the year following its inclusion in the Company's consolidated net earnings. Current income tax is dependent upon the amount of capital expenditures incurred and the method of deployment. During the second quarter of 2006, the Canadian Federal and Alberta governments enacted corporate tax rate reductions. b) The net future income tax liability is comprised of: As at December 31, 2006 2005 ------------ ------------ Future income tax liabilities Property and equipment in excess of tax values $ 229,936 $ 232,258 Timing of partnership items 83,328 93,532 Foreign exchange gain on long-term debt 8,729 11,466 Other 2,591 - Future income tax assets Attributed Canadian royalty income (7,462) (8,830) Asset retirement obligations (8,642) (6,984) Other - (9,325) ------------ ------------ Net future income taxes $ 308,480 $ 312,117 ------------ ------------ ------------ ------------ Net future income taxes $ 308,480 $ 312,117 Current portion (5,790) 2,609 ------------ ------------ Non-current future income taxes $ 302,690 $ 314,726 ------------ ------------ ------------ ------------ 16. Financial instruments a) Derivative financial instruments and risk management activities The Company is exposed to risks from fluctuations in commodity prices, interest rates, and Canada/US currency exchange rates. The Company utilizes various derivative financial instruments for non- trading purposes to manage and mitigate its exposure to these risks. Effective January 1, 2004, the Company elected to account for all derivative financial instruments using the mark-to-market method. Risk management activities during the periods, utilizing derivative instruments, relate to commodity price hedges, foreign currency contracts and cross currency interest rate swap arrangements and are summarized below: i) Commodity price hedges The Company enters into hedge transactions relating to crude oil and natural gas prices to mitigate volatility in commodity prices and the resulting impact on cash flow. The contracts entered into are forward transactions providing the Company with a range of prices on the commodities sold. Outstanding hedge contracts at December 31, 2006 are: Daily Mark- Notional Average to-Market Commodity Term Volume Price gain --------- ---- -------- ------- ----------- Natural gas $8.43 - Collar Nov./06 - Mar./07 38,095 mcf $11.15/mcf $ 5,818 $6.74 - Collar Apr./07 - Oct./07 28,571 mcf $9.28/mcf 3,187 ----------- 9,005 Crude Oil US$75.00 - Collar Jan./07 - Dec./07 3,000 bbls $84.55/bbl 13,620 ----------- Unrealized risk management gain $ 22,625 ----------- ----------- The following financial instruments were entered into subsequent to December 31, 2006: Natural gas $7.35 - Collar Apr./07 - Oct./07 14,286 mcf $8.88/mcf At December 31, 2005 the mark-to-market valuation of commodity contracts resulted in a $3.2 million unrealized risk management loss. ii) Deferred risk management loss As at January 1, 2004, the Company elected not to designate any of its risk management activities as accounting hedges and accordingly accounts for all derivative instruments using the mark-to-market method. As a result, on January 1, 2004, the Company recorded a liability and a deferred risk management loss of $10.9 million relating to then outstanding commodity hedges and the interest rate swap. During the year ended December 31, 2006, $1.6 million (2005 - $1.6 million) of the deferred loss was charged to earnings. The remaining balance of $4.0 million at December 31, 2006 (2005 - $5.6 million) relates to the interest rate swap and will be charged to earnings in annual amounts of $1.6 million until eliminated in 2009 upon the termination of the swap contract. iii) Cross currency interest rate swap Concurrent with the issuance of 9.90% Senior Notes in 2002, the Company entered into interest rate swap arrangements expiring May 2009 that convert fixed rate U.S. dollar denominated interest obligations into floating rate Canadian dollar denominated interest obligations. On purchase of the majority of the 9.90% Senior Notes in November 2005, the Company elected not to collapse the cross currency interest rate swap. Accordingly, the swap remains outstanding and at December 31, 2006, the Company valued the liability relating to future unrealized losses on the swap arrangements to be $11.4 million (2005 - $14.8 million) on a mark-to-market basis. The current portion of this amount at December 31, 2006 is $4.6 million (2005 - $4.6 million). iv) Risk management (gain) loss Risk management (gains) and losses recognized during the periods relating to commodity prices, foreign exchange notes and the interest rate swap are summarized below: Interest Year ended December 31, Commodity Foreign Rate 2006 Contracts Currency Swap Total --------- --------- --------- ---------- Unrealized Amortization of deferred loss $ - $ - $ 1,642 $ 1,642 Change in fair value (25,775) - (3,389) (29,164) --------- --------- --------- ---------- (25,775) - (1,747) (27,522) Realized Cash settlements (39,217) (1,405) 4,423 (36,199) --------- --------- --------- ---------- Total (gain) loss $ (64,992) $ (1,405) $ 2,676 $ (63,721) --------- --------- --------- ---------- --------- --------- --------- ---------- Year ended December 31, Commodity Foreign Rate 2005 Contracts Currency Swap Total --------- --------- --------- ---------- Unrealized Amortization of deferred loss $ - $ - $ 1,642 $ 1,642 Change in fair value 5,136 - 3,393 8,529 --------- --------- --------- ---------- 5,136 - 5,035 10,171 Realized Cash settlements 9,663 - (532) 9,131 --------- --------- --------- ---------- Total loss $ 14,799 $ - $ 4,503 $ 19,302 --------- --------- --------- ---------- --------- --------- --------- ---------- Year ended December 31, Commodity Foreign Rate 2004 Contracts Currency Swap Total --------- --------- --------- ---------- Unrealized Amortization of deferred loss $ 2,001 $ - $ 1,642 $ 3,643 Change in fair value (3,986) - 2,522 (1,464) --------- --------- --------- ---------- (1,985) - 4,164 2,179 Realized Cash settlements 9,151 - (2,522) 6,629 --------- --------- --------- ---------- Total loss $ 7,166 $ - $ 1,642 $ 8,808 --------- --------- --------- ---------- --------- --------- --------- ---------- b) Other financial instruments and risk i) Credit risk management Accounts receivable include amounts receivable for oil and natural gas sales which are generally made to large credit worthy purchasers and amounts receivable from joint venture partners which are generally recoverable from production. Accordingly, the Company views credit risks on these amounts as low. The Company is exposed to losses in the event of non-performance by counter-parties to financial instruments. The Company deals with major financial institutions and believes these risks are minimal. ii) Fair value of financial assets and liabilities The carrying value of cash, accounts receivable, other current assets, current liabilities, and bank debt approximate fair value. The estimated fair value of senior term notes was $503.4 million as at December 31, 2006 versus the carrying amount of $524.4 million. Other current assets are comprised of prepaid expenses, Crown royalty deposits and marketable securities valued at cost. The fair value of the marketable securities at December 31, 2006 exceeded the cost by $1.3 million. iii) Foreign currency 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 certain 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. On December 31, 2006, all existing foreign exchange contracts expired and the Company has not entered into any new contracts subsequent to year end. 17. Cash flow Changes in non-cash working capital items increased (decreased) cash as follows: Years ended December 31, 2006 2005 2004 ------------ ------------ ----------- Accounts receivable and other current assets $ 24,751 $ (17,371) $ (20,176) Accounts payable (62,425) 78,385 39,598 Taxes payable - (301) (2,526) ------------ ------------ ----------- $ (37,674) $ 60,713 $ 16,896 ------------ ------------ ----------- ------------ ------------ ----------- Net change in non-cash working capital Relating to: Operating activities $ 18,901 $ 8,441 $ (12,594) Financing activities 1,278 (1,829) 324 Investing activities (57,853) 54,101 29,166 ------------ ------------ ----------- $ (37,674) $ 60,713 $ 16,896 ------------ ------------ ----------- ------------ ------------ ----------- Amounts paid during the year relating to interest expense and capital taxes were as follows: Years ended December 31, 2006 2005 2004 ------------ ------------ ----------- Interest paid $ 48,857 $ 31,444 $ 28,604 ------------ ------------ ----------- ------------ ------------ ----------- Current income taxes paid $ 14 $ 4,101 $ 4,952 ------------ ------------ ----------- ------------ ------------ ----------- 18. Commitments and contingent liabilities a) Commitments The Company has committed to certain payments over the next five years, as follows: 2007 2008 2009 2010 2011 --------- --------- --------- --------- --------- Operating leases $ 3,737 $ 3,365 $ 2,846 $ - $ - Office facilities 3,509 4,923 4,800 4,800 4,800 MPP partnership distributions 9,172 9,172 3,057 - - --------- --------- --------- --------- --------- $ 16,418 $ 17,460 $ 10,703 $ 4,800 $ 4,800 --------- --------- --------- --------- --------- --------- --------- --------- --------- --------- The Company has entered into a lease agreement for new office facilities commencing October 2008. Annual commitments under the lease agreement are approximately $4.8 million per year for the 10 year term. b) Legal proceedings The Company is involved in various legal claims associated with normal operations. These claims, although unresolved at the current time, in management's opinion, are not significant and are not expected to have a material impact on the financial position or results of operations of the Company. 19. Subsequent events Prior to December 31, 2006, the Company entered into transactions for the sale of certain minor non-core properties, effective at year end. The transactions closed subsequent to year end and net proceeds of $45.9 million from the dispositions were received. The dispositions have been recorded as at the closing dates and have not been recognized in the 2006 financial statements. 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. CONFERENCE CALL Compton will be conducting a conference call and audio webcast Tuesday, March 27, 2007 at 9:30 a.m. Mountain Standard Time (11:30 a.m. EST) to discuss the Company's 2006 fourth quarter and 2006 annual financial and operating results. To participate in the conference call, please contact the Conference Operator at 9:20 a.m. (MST), ten minutes prior to the call. Conference Operator Dial-in Number: Toll-Free 1-800-732-9307 Local Toronto: 1-416-644-3418 Webcast URL: http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID=1775840 The audio replay will be available two hours after the conclusion of the conference call and will be accessible until Tuesday, April 3, 2007. Callers may dial toll-free 1-877-289-8525 and enter access code 21223944 (followed by the pound key). Compton Petroleum Corporation is a Calgary-based public company actively engaged in the exploration, development, and production of natural gas, natural gas liquids, and crude oil in the Western Canada Sedimentary Basin. Compton's shares are listed on the Toronto Stock Exchange under the symbol CMT and on the New York Stock Exchange under the symbol CMZ. %SEDAR: 00003803E %CIK: 0001043572

For further information:

For further information: E.G. Sapieha, President & CEO, N.G. Knecht, VP
Finance & CFO, (403) 237-9400, Fax: (403) 237-9410; www.comptonpetroleum.com,
investorinfo@comptonpetroleum.com

Organization Profile

MFC Energy Corporation

More on this organization


Custom Packages

Browse our custom packages or build your own to meet your unique communications needs.

Start today.

CNW Membership

Fill out a CNW membership form or contact us at 1 (877) 269-7890

Learn about CNW services

Request more information about CNW products and services or call us at 1 (877) 269-7890