Exhibit 20.3





Management’s Discussion and Analysis




This Management’s Discussion and Analysis (“MD&A”) for Compton Petroleum Corporation (“Compton” or the “Corporation”) should be read with the audited consolidated financial statements and related notes for the year ended December 31, 2009, as well as the audited consolidated financial statements
and MD&A for the year ended December 31, 2008.  Readers should also read the “Forward-Looking Statements” legal advisory contained at the end of this document.  Non-GAAP Financial Measures and disclosure regarding use of BOE Equivalents is contained in the “Advisories” section located at the end of this document.




The audited consolidated financial statements and comparative information have been prepared in accordance with Canadian Generally Accepted Accounting Principles (“GAAP”).  This document is dated as at February 25, 2010.




I.           Compton’s Business




Compton Petroleum Corporation is a public Corporation actively engaged in the exploration, development and production of natural gas, natural gas liquids, and crude oil in western Canada.  The Corporation’s strategy is focused on creating value for shareholders by providing appropriate investment returns through the effective
development and optimization of assets.




The Corporation’s operations are located in the deep basin fairway of the Western Canada Sedimentary Basin in the province of Alberta.  In this large geographical region, Compton pursues three deep basin natural gas plays:  the Rock Creek sands at Niton and Gilby in central Alberta, the Basal Quartz sands at
High River in southern Alberta, and the shallower Plains Belly River sands in southern Alberta.  In addition, the Corporation has an exploratory play in the Foothills area of southern Alberta.  Natural gas represents approximately 84% of reserves and production.




II.           Corporate Strategy in the Current Economic Environment




Economic conditions and global financial markets improved throughout 2009.  These improvements have benefited Compton in restructuring its business.  To achieve success in the current economic environment, Compton will remain focused on its key business objectives.  These objectives include optimizing
capital investments, decreasing operating and administrative expenses, reducing cash flow volatility and lowering the amount of its debt.  During 2009, these focused measures have resulted in:




•
a $5.6million reduction in gross administrative expenses from that of 2008;




•
the completion of an equity offering in October 2009 with gross proceeds of $172.5 million;




•
the sale of a 3.75% overriding royalty in the fourth quarter of 2009 with proceeds of $71.3 million (an additional 0.5% closed subsequent to year-end for additional proceeds of $9.5 million);




•
the sale of non-core assets and interests in overriding royalties in July 2009 for gross proceeds of $8.0 million and $7.0 million, respectively;




•
a reduction of bank debt to $107.0 million from a peak in 2009 of $350.0 million; and




•
operating results that met Management's guidance.




Throughout 2009, Compton strengthened its balance sheet and improved the Corporation’s capital structure and reduced overall financial risk.  In the short-term, Compton’s financial flexibility is enhanced by unused committed borrowing capacity of $110.5 million under the bank facility.




The “Risks” section (see page 15) provides greater detail of operational and financial risks that may impact the execution of our strategy.







- 1 -





The Corporation will maintain its strategy of operating within cash flow and investing in projects that meet internal rate of return hurdles.  In addition, field activities will focus on optimizing production from existing wells in order to improve operating efficiencies.




III.           Results of Operations





Years ended December 31,

2009


2008


2007($000’s, except per share amounts)Average production (boe/d)


20,922



28,658



31,326Capital expenditures


68,303



324,549



385,886Cash flow(1)(2)(3)

$
45,439


$
255,881


$
201,425Per share:
basic

$
0.29


$
1.98


$
1.56diluted

$
0.29


$
1.94


$
1.52Operating earnings (loss)(1)(2)

$
(61,038
)

$
70,949


$
32,585Net earnings (loss)

$
(8,330
)

$
(43,003
)

$
129,266Per share:
basic

$
(0.05
)

$
(0.33
)

$
1.00diluted

$
(0.05
)

$
(0.33
)

$
0.98Revenue, net of royalties

$
200,202


$
490,374


$
403,540Field netback (per boe)(1)(2)

$
18.35


$
34.26


$
26.99


(1)
Cash flow, operating earnings (loss) and field netback are non-GAAP measures that are defined in this document


(2)
Prior periods have been revised to conform to current period presentation


(3)
Net of asset retirement expenditures (2009 - $4,387; 2008 - $2,768; 2007 - $4,441)




CASH FLOW




Cash flow is considered a non-GAAP measure; it is commonly used in the oil and gas industry and by Compton to assist Management and investors in measuring the Corporation’s ability to finance capital programs and repay its debt.  Cash flow should not be considered an alternative to, or more meaningful than, cash provided
by operating, investing and financing activities or net earnings as determined in accordance with Canadian GAAP, as an indicator of the Corporation’s performance or liquidity.  The following schedule sets out the reconciliation of cash flow from operations to cash flow.





Years ended December 31,


2009


2008


2007(000’s)Cash flow from operating activities


$
28,834


$
300,231


$
178,059Change in non-cash working capital



16,605



(44,350
)


23,366Cash flow(1)


$
45,439


$
255,881


$
201,425


(1)
Cash flow is a non-GAAP measures that is defined in this document




Cash flow for 2009 decreased $210.4 million or 82% compared to 2008 as a result of:




•
lower average realized natural gas prices, excluding financial hedges, which decreased 49% to $4.16 per mcf in 2009 compared to $8.17 per mcf in 2008;




•
lower average realized liquids prices, excluding financial hedges, which decreased 50% to $49.79 per bbl compared to $98.68 per bbl in 2008;




•
a 26% decline in natural gas production volumes to 106 mmcf/d from 143 mmcf/d in 2008;




•
a 30% decline in liquids production volumes to 3,335 bbls/d from 4,769 bbls/d in 2008; and




•
the sale of 250 boe/d in 2009.




These factors were partially offset by:


- 2 -
 
 •
realized risk management gains of $30.0 million compared to $19.0 million in 2008; and
  •
overall decreases in operating, transportation, interest and administrative expenses, resulting from reduced production volumes and the Corporation’s focus on cost reduction.
  Cash flow for the three months ended December 31, 2009 decreased $23.1 million or 78% compared to the same period in 2008 as a result of:
  •
lower realized average natural gas prices, excluding financial hedges, which decreased by 37% to $4.38 per mcf compared to $6.99 per mcf in 2008;
  •
lower average realized liquids prices, excluding financial hedges, which decreased by 6% to $57.10 per bbl compared to $60.60 per bbl in 2008;
  •
a 22% decline in natural gas production volumes to 98 mcf/d from 125 mcf/d in 2008;
  •
a 26% decline in liquids production volumes to 3,055 bbls/d from 4,113 bbls/d in 2008; and
  •
a 65% decline in realized risk management gains to $3.7 million in 2009 compared to $10.5 million in 2008.
  These factors were partially offset by:
  •
a reduction of $21.3 million in strategic review and restructuring costs in 2009 compared to 2008; and
  •
a slight decrease in overall operating, interest and administrative expenses in 2009 compared to 2008.
  NET EARNINGS (LOSS)
  A net loss of $8.3 million in 2009 was an improvement of $34.7 million when compared to the $43.0 million loss in 2008.  This year’s net loss was largely due to the same factors that impacted cash flow.  Additional items affecting net loss were:
  •
non-cash unrealized foreign exchange gains of $84.8 million compared to losses of $113.8 million in 2008;
  •
a $30.7 million reduction in strategic review and restructuring costs in 2009 from 2008;
  •
lower stock based compensation costs, which decreased $5.4 million compared to 2008 due to reduced expense relating to Compton’s stock option and employee share purchase programs;
  •
future income tax recovery of $24.1 million recognized in 2009 compared to $14.8 million in expense for 2008 (see “Income Taxes”); and
  •
a decline in depletion and depreciation costs of $23.3 million in 2009 over 2008, reflecting the sale of non-core assets and reduced production volumes.
  These factors were partially offset by:
  •
a $9.9 million write-down of goodwill.
  Net loss for the three months ended December 31, 2009 was $23.8 million, an improvement of $72.1 million when compared to the $95.9 million loss in 2008.  Items affecting cash flow detailed previously also affected net loss.  Additional items affecting net loss were:
  •
non-cash unrealized foreign exchange gains of $12.0 million compared to losses of $80.1 million in 2008; and
  •
lower depletion and depreciation of assets of $11.3 million in 2009 over 2008 resulting from the sale of non-core assets and reduced production volumes.
  These factors were partially offset by:
  •
a $9.9 million write-down of goodwill; and


- 3 -
 •
higher than anticipated operating costs associated with extreme seasonal conditions and related compensation costs.


OPERATING EARNINGS (LOSS)




Operating earnings (loss) is an after tax non-GAAP measure used by the Corporation to facilitate comparability of earnings between periods.  Operating earnings is derived by adjusting net earnings for certain items that are largely non-operational in nature, or one-time non-recurring items.  Operating earnings (loss)
should not be considered more meaningful than or an alterative to net earnings as determined in accordance with Canadian GAAP.  The following provides the calculation of operating earnings (loss).





Years ended December 31,

2009


2008


2007($000’s, except per share amounts))Net earnings (loss), as reported

$
(8,330
)

$
(43,003
)

$
129,266Non-operational items, after taxUnrealized foreign exchange and other (gains) losses(1)


(68,486
)


90,727



(66,934
)Unrealized market-to-market hedging (gains) losses


6,752



(1,795
)


3,711Strategic review and restructuring


3,419



25,020



-Goodwill written-off


7,052



-



-Tax rate change effects


(1,445
)


-



(33,458
)Operating earnings(2)

$
(61,038
)

$
70,949


$
32,585Per share
-      basic

$
(0.38
)

$
0.55


$
0.25-      diluted

$
(0.38
)

$
0.54


$
0.25


(1)
Includes foreign exchange (gain) loss on the translation of US$ debt and marketable securities valuation (gain) loss


(2)
Prior periods have been revised to conform to current period presentation




CAPITAL EXPENDITURES





Years ended December 31,

2009


2008


2007($000’s)Land and seismic

$
7,014


$
19,846


$
47,528Drilling and completions


22,431



218,514



217,883Production facilities and equipment


29,102



82,616



116,011Corporate and other


9,756



3,573



4,464Sub-total


68,303



324,549



385,886AcquisitionsProperty


304



10,940



73,703Corporate


-



-



131,380DivestituresProperty


(9,241
)


(202,892
)


(303,093
)Gross Overriding Royalty


(7,165
)


-



-Overriding Royalty


(70,651
)


-



-Acquisitions (divestitures), net


(86,753
)


(191,952
)


(98,010
)Total capital expenditures

$
(18,450
)

$
132,597


$
287,876




The decline in commodity prices reduced internally generated cash flow available to invest in drilling activities.  As a result, capital spending, before acquisitions, divestments and corporate expenses, decreased by 78% in 2009 compared to 2008.  Capital spending in 2009 continued to be directed towards the development
of core natural gas resource plays in southern and central Alberta.  Compton drilled or participated in a total of 20 wells (6 operated wells and 14 non-operated wells) during 2009 as compared to a total of 256 wells drilled during 2008 (199 operated wells and 57 non-operated wells).  Corporate and other expenses increased significantly due to one-time charges for design, construction and equipment related to the relocation of the corporate office.


- 4 -


During 2009, the Corporation sold an overriding royalty over existing lands and divested non-core properties in the Pembina Region.  In 2008, non-core assets were divested at Cecil, Zama, Thornbury and the Peace River Arch.




Looking forward, Management’s objective is to limit spending to within cash flow, which is consistent with the Corporation’s objective of lowering its debt.  The bulk of 2010 capital expenditures are scheduled in the first half of the year.  Capital plans for the balance of the year are flexible; should
commodity price levels increase and additional funds become available, Management will consider additional activities.




FREE CASH FLOW




Free cash flow is a non-GAAP measure that Compton defines as cash flow in excess of capital investment, excluding net acquisitions and divestitures, and is used by Management to determine the funds available for other investing activities and/or other financing activities.  Compton’s 2009 free cash flow deficit of $22.9
million is significantly lower as compared to 2008 due to the reduction in capital expenditures.





Years ended December 31,

2009


2008


2007(000’s)Cash flow

$
45,439


$
255,881


$
201,425Less: capital investment


(68,303
)


(324,549
)


(385,886
)Free cash flow (deficit)

$
(22,864
)

$
(68,668
)

$
(184,461
)





PRODUCTION VOLUMES AND REVENUE





Years ended December 31,

2009


2008


2007Average productionNatural gas (mmcf/d)


106



143



145Liquids (bbls/d)


3,335



4,769



7,166Total (boe/d)


20,922



28,658



31,326Benchmark pricesAECO ($/GJ)Monthly index

$
3.92


$
7.71


$
6.27Daily index

$
3.75


$
7.72


$
6.11WTI (US$/bbl)

$
61.80


$
109.47


$
72.37Edmonton sweet light ($/bbl)

$
65.79


$
102.11


$
76.23Realized prices(1)Natural gas ($/mcf)

$
4.16


$
8.17


$
6.33Liquids ($/bbl)

$
49.79


$
98.68


$
62.28Total ($/boe)

$
28.90


$
57.26


$
43.56Revenue ($000’s)(1)Natural gas

$
160,112


$
428,413


$
335,176Liquids


67,764



181,885



171,042Total

$
227,876


$
610,298


$
506,218


(1)
Prior periods have been revised to conform to current period presentation


(2)
Average production volumes have been impacted by the sale of certain non-core assets for 2008




Production volumes for 2009 were 27% lower than in 2008 primarily due to natural declines, the sale of 250 boe/d of production in the second quarter, limited new production additions and the sale of 4,100 boe/d of production in the third quarter of 2008.




Revenue decreased by 63% for 2009 compared to 2008 due to lower realized natural gas and liquids prices and reduced sales volumes.


- 5 -


Realized prices and revenues are before any hedging gains or losses.  The impact of hedging increased realized natural gas prices by $0.70 per mcf in 2009, and reduced realized prices by $0.13 per mcf in 2008.




FIELD NETBACK AND FUNDS FLOW NETBACK




Field netback and funds flow netback are non-GAAP measures used by the Corporation to analyze operating performance.  Field netback equals the total petroleum and natural gas sales, including realized gains and losses on commodity hedge contracts, less royalties and operating and transportation expenses, calculated on a $/boe
basis.  Funds flow netback equals field netback less administrative and interest costs.  Field netback and funds flow netback should not be considered more meaningful than or an alterative to net earnings (loss) as determined in accordance with Canadian GAAP.  The following provides the calculation of field netback and funds flow netback.





Years ended December 31,

2009


2008


2007($/boe)Realized price(1)

$
28.90


$
57.26


$
43.56Processing revenue


0.94



0.92



0.71Realized commodity hedge gain (loss)


4.22



(0.80
)


1.68Royalties


(3.62
)


(11.43
)


(8.98
)Operating expenses


(11.29
)


(10.89
)


(8.88
)Transportation


(0.80
)


(0.80
)


(1.10
)Field netback

$
18.35


$
34.26


$
26.99Administrative


(3.75
)


(2.96
)


(2.60
)Interest


(7.45
)


(5.81
)


(5.55
)Funds flow netback

$
7.15


$
25.49


$
18.84


(1)      Prior periods have been revised to conform to current period presentation




OPERATING EXPENSES





Years ended December 31,

2009


2008


2007Operating expenses ($000’s)

$
86,195


$
114,205


$
101,515Operating expenses ($/boe)

$
11.29


$
10.89


$
8.88




Operating expenses for 2009 decreased by 24% from 2008 primarily as a result of reduced production levels.  Additional cost savings were also realized following an overall reduction in industry activity, a commodity price environment lowering power and chemical costs, and a corporate focus on operational efficiencies. Reduced
production levels resulted in a 4% increase in operating costs on a per barrel basis in 2009.




ROYALTIES





Years ended December 31,

2009


2008


2007Crown royalties(1)

$
7,919


$
88,542


$
81,082Overriding royalty


1,892



-



-Other royalties


17,863



31,382



21,596Net royalties

$
27,674


$
119,924


$
102,678Percentage of revenues


12.1
%


19.7
%


20.3
%


(1)      Crown royalties are presented net of any gas cost allowance




The Alberta royalty structure is based upon commodity prices and well productivity, with higher prices and well productivity attracting higher royalty rates.  On January 1, 2009, new royalty rates from the Alberta government’s New Royalty Framework (“NRF”) came into effect.  The NRF established new
royalty rates for conventional oil, natural gas and bitumen that are linked to commodity prices, well production volumes, well depth relating to gas wells and oil quality relating to oil wells.  Subsequently, the government has made certain concessions due to the uncertain economic environment and, in June 2009, announced that the NFR, originally set to expire in March 2010, will be extended by one year to March 2011.


- 6 -


The one-year extension affects the following two previously announced programs:




•
the drilling royalty credit for new exploration wells:  provides a $200-per-metre-drilled royalty credit to companies on a sliding scale based on production levels from 2008; and




•
the new well incentive program:  offers a maximum 5% royalty rate for the first year of production from new oil or gas wells.




Royalties as a percentage of revenues decreased by 7.6% in 2009 compared to 2008 largely as a result of the decline in natural gas prices, the implementation of the Alberta government’s NRF and the benefit of a one time recovery of $3.3 million of royalties paid in prior years.




TRANSPORTATION





Years ended December 31,

2009


2008


2007Transportation costs ($000’s)

$
6,118


$
8,378


$
12,615Transportation costs ($/boe)

$
0.80


$
0.80


$
1.10





Compton incurs 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.




Transportation expenses for 2009 fell by 27% over 2008 as a result of reduced production volumes.




ADMINISTRATIVE EXPENSES





Years ended December 31,

2009


2008


2007Gross administrative expenses

$
36,199


$
41,780


$
40,022Capitalized administrative expenses


(3,294
)


(8,236
)


(7,470
)Operator recoveries


(4,294
)


(2,529
)


(2,835
)Administrative expenses

$
28,611


$
31,015


$
29,717Administrative expenses ($/boe)

$
3.75


$
2.96


$
2.60





Gross administrative expenses before recoveries decreased by 13% for 2009 compared to 2008 primarily as a result of the Corporation’s restructuring, partially offset by lease costs of $1.9 million for excess office space.  On a per boe basis, administrative costs increased 27% for 2009 due to the impact of reduced production
volumes.  Management will continue to focus on further cost reductions in 2010, including the subletting of excess office space.





STOCK-BASED COMPENSATION





Years ended December 31,

2009


2008


2007(000’s)Stock option plan

$
2,921


$
8,826


$
8,416Share appreciation rights plan


-



(970
)


-Employee retention program


-



-



2,618Employee share purchase plan(1)


1,226



1,718



1,574Stock-based compensation

$
4,147


$
9,574


$
12,608


(1)      Number of shares purchased (2009 - 1,209,132; 2008 - 406,273; 2007 - 153,933)


- 7 -


The Corporation has instituted various compensation arrangements, the value of which is determined in relation to the market value of Compton’s capital stock.  These arrangements are designed to attract, motivate and retain outstanding individuals, and to align their success with that of shareholders.  Details
relating to stock-based compensation arrangements are presented in Note 12 to the financial statements.




STRATEGIC REVIEW AND RESTRUCTURING COSTS





Years ended December 31,

2009


2008


2007(000’s, except where noted)Strategic review costs

$
2,550


$
35,490


$
-Restructuring costs


2,266



-



-Total costs

$
4,816


$
35,490


$
-Total costs ($/boe)

$
0.63


$
3.38


$
-





The strategic review process undertaken in 2008 was suspended late in that year; certain trailing costs under the review were expensed as incurred in 2009.  Compton initiated a restructuring process following the strategic review and throughout 2009, the costs of which comprised severance, professional services and one-time
costs in realigning the operations of the Corporation.  No further costs are anticipated under the program beyond 2009.




INTEREST AND FINANCE CHARGES





Years ended December 31,

2009


2008


2007(000’s, except where noted)Interest on bank debt, net

$
11,268


$
20,280


$
22,476Interest on senior notes


41,032



38,228



38,345Interest expense


52,300



58,508



60,821Finance charges


4,586



2,403



2,672Total interest and finance charges

$
56,886


$
60,911


$
63,493Total interest and finance charges ($/boe)

$
7.45


$
5.81


$
5.55





Interest and finance charges for 2009 decreased by 7% compared to the prior year.  The reduction was comprised of reduced borrowings on the revolving credit facility and an overall reduction in interest rates on bank debt, partially offset by interest related to the senior term notes.  Interest charges on the senior
term notes are payable in US dollars.  The Canadian to US dollar exchange in 2009 compared to 2008 resulted in a 7.3% increase in interest on these notes year over year.  On a per boe basis, interest and finance changes increased due to reduced production volumes.




Effective interest rates on a weighted average debt basis are presented below.





Years ended December 31,

2009


2008


2007(000’s, except where noted)Bank debt

$
249,359


$
325,020


$
348,216Effective interest rate


4.52
%


6.20
%


6.46
%Senior notes (US$)

$
450,000


$
450,000


$
450,000Coupon rate (US$)


7.625
%


7.625
%


7.625
%Effective interest rate (CDN$)


8.150
%


8.150
%


8.150
%





- 8 -


RISK MANAGEMENT





Years ended December 31,

2009


2008


2007(000’s, except where noted)Commodity contractsRealized (gain) loss

$
(32,286
)

$
8,367


$
(19,220
)Unrealized (gain) loss


9,510



(6,493
)


20,834Foreign currency contractsRealized (gain) loss


2,303



(27,360
)


7,739Unrealized (gain) loss


-



3,947



(15,367
)Total risk management (gain) loss

$
(20,473
)

$
(21,539
)

$
(6,014
)Realized (gain) loss

$
(29,983
)

$
(18,993
)

$
(11,481
)Unrealized (gain) loss


9,510



(2,546
)


5,467Total risk management (gain) loss

$
(20,473
)

$
(21,539
)

$
(6,014
)





The Corporation’s financial results are impacted by external market risks associated with fluctuations in commodity prices, interest rates, and the Canadian/US dollar exchange rate.  Compton utilizes various financial instruments for non-trading purposes to manage and mitigate exposure to these risks.  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 (loss) and comprehensive income.




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 values of 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.




Commodity hedges were put in place so that the Corporation has natural gas hedged for 54,250 giga joules (“GJ”) per day between an equivalent AECO floor price of $4.50 per GJ and a ceiling price of $7.01 per GJ.  The Corporation has also entered into electricity hedges for a total of 84 mega watt hours (“MWh”)
per day at a fixed price of $50.74/MWh.  These hedges will be in effect throughout 2010 and 2011 as follows:




Commodity
Term
Volume
Average
Price
IndexNatural gasCollars
July 2009 - June 2010
14,000 GJ/d
$4.50 - $5.80/GJ
AECOCollars
July 2009 - June 2011
30,250 GJ/d
$4.52 - $7.01/GJ
AECOCollars
July 2009 - Oct. 2011
10,000 GJ/d
$4.50 - $7.00/GJ
AECOElectricitySwap
Jan. 2010 - Dec. 2011
84 MWh/d
$50.74/MWh
AESO




DEPLETION AND DEPRECIATION





Years ended December 31,

2009


2008


2007Total depletion and depreciation ($000’s)

$
134,710


$
157,973


$
151,411Depletion and depreciation ($/boe)

$
17.64


$
15.06


$
13.24


- 9 -


Total depletion and depreciation expense decreased 15% during 2009 as compared to 2008.  Depletion and depreciation expense per boe increased in part due to lower production volumes.  Accelerated capital programs prior to 2009 have resulted in a larger asset base and in turn, increased depletion and depreciation.




FOREIGN EXCHANGE AND OTHER GAINS AND LOSSES





Years ended December 31,

2009


2008


2007(000’s)Foreign exchange (gain) loss on translation of US$ debt

$
(80,100
)

$
106,425


$
(79,740
)Other foreign exchange (gain) loss


(2,779
)


(82
)


1,023Marketable securities valuation (gain) loss


(1,931
)


7,439



5,231Total foreign exchange and other (gains) losses

$
(84,810
)

$
113,782


$
(73,486
)





The foreign exchange gain recognized in the consolidated statements of earnings (loss) resulted primarily from the translation of the US dollar denominated senior term notes into Canadian dollars.  The senior term notes are translated and recorded in the financial statements at the period end exchange rate, with any change from
prior periods being recognized as an unrealized foreign exchange gain or loss.




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.


A future income tax recovery of $24.1 million was recognized in 2009.  This was primarily as a result of reductions in the effective federal corporate tax rates, which affected the future income tax liability recorded in prior years, and the non-taxable portion of capital gains.





Under current legislation, the statutory federal income tax rate will continue to be reduced by 0.5% annually until 2012.




CORPORATE TAX RATES





Years ended December 31,

2009


2008


2007Statutory rate


29.0
%


29.5
%


32.1
%





A reconciliation of the effective tax rate to the statutory rate may be found in Note 17a to the consolidated financial statements.




IV.
Liquidity and Capital Resources




CAPITAL STRUCTURE




Compton manages its capital structure to support current and future business plans.  The structure may be adjusted by modifying capital programs, altering debt levels, disposing of assets and/or issuing equity, as circumstances dictate.




Adjusted EBITDA is a non-GAAP measure defined as net earnings, before interest and finance charges, income taxes, depletion and depreciation, accretion of asset retirement obligations, and foreign exchange and other gains and losses.  Capitalization is a non-GAAP measure defined as working capital, long-term debt including current
portion, MPP term financing and shareholders' equity.  Debt to capitalization and debt to adjusted EBITDA are two ratios that Management uses to steward the Corporation’s overall debt position as measures of Compton’s overall financial strength.


- 10 -


Years ended December 31,

2009


2008Working capital deficit(1)

$
7,748


$
44,020Bank debt


107,000



290,000Senior term notes


470,970



551,070MPP term financing


51,408



-Total net debt


637,126



885,090Shareholders’ equity


992,237



834,690Capitalization

$
1,629,363


$
1,719,780Total net debt to adjusted EBITDA(2)(3)


7.3x



2.9xTotal net debt to total capitalization(2)


39%



51%


(1)
Adjusted working capital excludes risk management items and related future income taxes


(2)
Excludes risk management items net of related future income taxes


(3)
Based on trailing 12 month adjusted EBITDA




Of total net debt, 74% is comprised of senior term notes that mature on December 1, 2013 and 8% relates to the MPP term financing, $27.8 million of which matures on April 30, 2014.




WORKING CAPITAL




Excluding the impact of current hedging assets and liabilities, Compton had a working capital deficiency of $7.7 million at December 31, 2009, as compared to a deficit of $44.0 million as at December 31, 2008.  The reduced deficit is due to a decrease in accounts payable resulting from the decrease in field activities and reduced
capital expenditures.  As is typical in the oil and gas industry, there is not a direct correlation between amounts receivable from the sale of production and trade payables, which results from operating activities that vary seasonally and also with activity levels.  This will result in fluctuations in working capital and often result in a working capital deficit.  Management anticipates that the Corporation will continue to meet the payment terms of suppliers.




BANK DEBT




The Corporation’s outstanding bank debt at December 31, 2009 of $107.0 million was drawn on a revolving term facility authorized at $190 million and a revolving working capital facility authorized at $30 million (for a total of $220 million).  As of the date of this report, the facility has been reduced to a total of $217.5
million following the exercised overriding royalty options subsequent to year end.  The credit facilities were renewed on July 2, 2009 for a period of 364 days until July 1, 2010.  The Corporation expects that the credit facilities will be renewed at that time for a further 364-day period; total credit available under the facilities will be dependent on the borrowing base of Compton at that time.  The credit facility is subject to re-determination of the borrowing base twice a year
at December 31 and May 31.  The borrowing base of the facilities is determined based on, among other things, the Corporation’s current reserve report, results of operations, the lenders view of the current and forecasted commodity prices and the current economic environment.




The credit facility provides that advances may be made by way of prime loans, bankers’ acceptances, US base rate loans, LIBOR loans and letters of credit.  Advances will bear interest at the applicable lending rate plus a margin based on Compton’s debt to trailing cash flow ratio.  The credit facility is
secured by a fixed and floating charge debenture on the assets of the Corporation.




The amount that may be drawn on the credit facility is limited, in certain circumstances, by a provision contained in the note indenture governing the senior term notes (the adjusted consolidated net tangible assets (“ACNTA”) test, detailed in “senior term notes and risks - liquidity risk”).  At December
31, 2009, the ACNTA test capped the borrowings under the credit facilities to $263.4 million.


- 11 -


SENIOR TERM NOTES




Senior term notes due in 2013 are payable in US dollars and are translated into Canadian dollars at the period end prevailing exchange rate.  Any change from the prior period is recognized as an unrealized exchange gain or loss and decreases or increases the carrying value of the notes.  At December 31, 2009, the carrying
value of the notes decreased by $80.1 million from December 31, 2008 as a result of the unrealized gain on translation at December 31, 2009.




The indenture governing the senior term notes limits the extent to which Compton can incur incremental debt and requires the Corporation to meet a fixed charge coverage ratio test (“Ratio”) and ACNTA test if the Ratio test is not met.  At each quarter end, the fixed charge coverage ratio must exceed a trailing four
quarters 2.5 to 1 threshold and if the Ratio is less than 2.5 to 1, the value calculated under the ACNTA test must exceed borrowings under the credit facilities.  The Ratio restricts Compton’s ability to incur incremental debt, and the value determined under the ACNTA test restricts the borrowings under the credit facilities to the ACNTA calculated value.


At December 31, 2009, the Ratio was 2.0 to 1, which was below the minimum requirement and thereby restricts the amount of incremental borrowings the Corporation may incur.  Based on the ACNTA calculation, Compton may incur up to $263.4 million under the credit facility and certain other permitted debt until the time when the
ratio exceeds 2.5 to 1.  Management does not anticipate these restrictions to have any limiting or adverse effect on the operations of the Corporation (see “risks - liquidity risk”).


MPP TERM FINANCING




On April 30, 2009, Compton completed the renegotiation of the MPP processing and other related agreements for a further term of five years, expiring on April 30, 2014.  In connection with the renewal, the Corporation has reclassified a portion of the non-controlling interest associated with MPP as MPP term financing.  MPP
term financing in the aggregate amount of $51.4 million is included as a liability in the consolidated financial statements.  The fixed base fee payments under the MPP term financing includes a principal and interest component.  The effective rate of interest is 10.16% per annum.  The principal amount of the MPP term financing is equal to the option purchase price of the MPP partnership units at the end of the five-year term.




DEBT REPAYMENT AND LEASE OBLIGATIONS




As part of normal business, Compton has entered into arrangements and incurred obligations that will impact future operations and liquidity, some of which are reflected as liabilities in the interim consolidated financial statements.  The following table summarizes all contractual obligations as at December 31, 2009.




2010


2011


2012


2013


2014


ThereafterBank debt

$
108,462


$
-


$
-


$
-


$
-


$
-Senior term notes (US $450 mm)


-



-



-



470,970



-



-MPP term financing(1)


9,592



9,592



9,592



9,592



3,198



-Accounts payable


58,970



-



-



-



-



-Operating leases


7,426



2,391



1,009



-



-



-Office facilities


3,234



3,234



3,234



3,234



3,234



13,964Vacant office facilities(2)


5,215



4,542



4,542



4,542



4,542



19,682$
192,899


$
19,759


$
18,377


$
488,338


$
10,974


$
33,646


(1)
Represents monthly fixed base fee payments


(2)
Management is currently pursuing the sublease of certain vacant office facilities




Compton intends to renew its bank credit facility.  Therefore repayment of the credit facility is not expected to occur, although it is included in the schedule of contractual obligations consistent with its current expiry.


- 12 -


V.           Outlook




Compton will continue to take a prudent approach in its capital investment decisions through its minimum 20% rate of return on investment requirements by reducing its internal cost structure, managing its capital structure, and focusing its exploration strategy to optimize asset value.  As a result, the Corporation expects
to:




•
take a limited but flexible approach to its 2010 capital expenditure program that will be adjusted according to economic circumstances;




•
continue to develop its long-term exploration strategy;




•
increase its emphasis on reducing its operating and administrative costs;




•
maintain its disciplined approach to natural gas price hedging activities to reduce cash flow volatility; and




•
selectively enter into transactions that de-lever the balance sheet to improve its capital structure and reduce overall financial risk, and maximize shareholder value.




Through these activities, Compton expects to emerge as a stronger company, poised to capitalize on its assets, achieve growth in production and cash flow.




Compton’s asset base provides solid growth potential through a large focused land position and significant impact from horizontal multi-stage fracture wells in the Niton and High River properties.  With a continued focus on lowering cost structures, Management believes that these horizontal wells may represent the best
opportunity for return on investment.  The strength of the team as it implements its multi-year strategic plan will position the Corporation to deliver long-term value to its shareholders.




The following represents Compton's guidance for 2010:




Average daily production (boe/d)


17,900 - 18,500Administrative expenses ($ millions)

$
25 - 27Operating costs ($ millions)

$
80 - 85Cash flow ($ millions)

$
70 - 80Capital expenditures ($ millions)

$
70 - 80




Compton's 2010 guidance is based on consultants' average forecast prices of $6.00 per GJ of natural gas (AECO), $78.39 per barrel of crude oil (Edmonton Sweet Light), and a foreign exchange rate of $0.925.  A $0.25 change in the AECO natural gas price is expected to result in a $7 million change in cash flow.




VI.
Changes in Internal Control Over Financial Reporting




CONTROLS AND PROCEDURES




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




There are certain procedural and wording differences between the US and Canadian certifications.  Management has chosen to file the form of certification pursuant to Section 302 of the Sarbanes-Oxley Act with the US Securities and Exchange Commission (“SEC”) and Form 52-109F1, Certification of Annual Filings Full
Certificate, with the Canadian Securities Administrators (“CSA”).


- 13 -


Compton has complied with both the US and Canadian requirements in respect to disclosure controls and procedures, and internal control over financial reporting as reported below.




MANAGEMENT’S EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES




The term “disclosure controls and procedures” is defined, under Rule 13a-15(d) of the US Exchange Act of 1934, as controls and other procedures that are designed to ensure both non-financial and financial information required to be disclosed in periodic reports is recorded, processed, summarized, and reported within the time
periods required, and this information is accumulated and communicated to Management as appropriate to allow timely decisions regarding required disclosures.  The definition of disclosure controls and procedures with respect to Canadian National Instrument 52-109 is substantially the same.




As indicated in certifications filed with the SEC and CSA, Compton completed an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2009, under the supervision and with the participation of our Management, including our President & CEO and VP Finance & CFO.  Based
upon the evaluation, Management concluded that its disclosure controls and procedures were effective.




MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING




Management, including the President & CEO and VP Finance & CFO, is responsible for establishing and maintaining adequate internal control over financial reporting.  The term “internal control over financial reporting” is defined under Rule 13a-15(f) of the US Securities Exchange Act of 1934, with the Canadian
National Instrument 52-109 definition being substantially the same; as processes designed by, or under the supervision of, our principal executive and principal financial officers, and effected by our board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with GAAP.  These controls include policies and procedures that:




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




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




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




Management completed an evaluation of the effectiveness of the design and operation of internal control over financial reporting under the supervision of the President & CEO and VP Finance & CFO.  Compton conducted an evaluation of the effectiveness of its internal control over financial reporting based on the Internal
Control - Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission, also known as COSO.  Based upon the evaluation, Management has concluded that, as of December 31, 2009, Compton’s internal control over financial reporting was effective.




The effectiveness of internal control over financial reporting as of December 31, 2009, was audited by Grant Thornton LLP, Chartered Accountants, the independent registered public accounting firm which also audits our financial statements.  They have issued their Independent Auditors’ Report which is included in this document
following the MD&A.




CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING




There were no changes to internal control over financial reporting during the period beginning on January 1, 2009 and ending on December 31, 2009 that materially affected or are reasonably likely to materially affect Compton’s internal control over financial reporting.


- 14 -


VII.           Risks




Following is a list of risks that Compton faces in its normal course of business.  If any of these risks actually occur, Compton’s business, financial condition, results of operations, cash flows and prospects could be harmed.  Such risks and uncertainties are not the only ones the Corporation faces.  Additional
risks and uncertainties, including those of which Management is currently unaware or that are deemed immaterial, may also adversely affect Compton’s business, financial condition, results of operations, cash flows and prospects.




CURRENT GLOBAL FINANCIAL CONDITION




Operations are affected by local, national and worldwide economic conditions and the condition of the oil and gas industry. Recent disruptions in the credit markets and concerns about the global economy have had an adverse impact on global financial markets.  These and other factors may affect Compton’s ability to
obtain equity or debt financing in the future on favourable terms.  Additionally, these factors, as well as other related factors, may cause decreases in the Corporation’s asset values that may be other than temporary, which may result in impairment losses.  If such increased levels of volatility and market turmoil continue, or if more extensive disruptions of the global financial markets occur, operations could be adversely impacted and the trading price of Compton’s common shares
may be adversely affected.





ADDITIONAL FUNDING REQUIREMENTS




Compton’s ongoing activities may not generate sufficient cash flow from operations to fund future exploration, development, or acquisition programs.  The Corporation may require additional funding and there can be no assurance that debt or equity financing will be available or sufficient to meet these requirements or that
it will be on acceptable terms.  Continued uncertainty in domestic and international credit markets compounds the risk of obtaining debt financing.  Failure to obtain such financing on a timely basis could cause Compton to forfeit interests in certain properties, miss certain acquisition opportunities, and reduce or terminate operations.  This may result in the Corporation not being able to replace its reserves or maintain production, which will have an adverse effect on its financial
position.  Failure to obtain additional funding may also result in the Corporation failing to meet financial obligations as they come due or may result in the acceleration of the Corporation’s debt.




LIQUIDITY RISK




Liquidity risk is the risk that the Corporation is not able to meet its financial obligations as they fall due. Compton’s $217.5 million term Credit Facilities come due in July 2010 unless renewed by that time.  The lenders under the Credit Facilities will reassess the borrowing base semi-annually on May 31 and December
31, which review may change the amount that the Corporation may borrow under its Credit Facilities. As at December 31, 2009, Compton had $107.0 million outstanding under its Credit Facilities.




In addition, both the Credit Facilities and the Note Indenture governing the US$450 million of 7.625% senior notes due in 2013 limit the extent to which the Corporation can incur other debt and require it to meet a fixed charge coverage ratio test and the ACNTA test.  At each quarter end, the fixed charge coverage ratio must
exceed a 2.5 to 1 threshold and the value calculated under the ACNTA test must exceed borrowings under the Credit Facilities.  Failure to meet the fixed charge coverage ratio restricts Compton from incurring new debt.  The value determined under the ACNTA test limits borrowings under the Credit Facilities to the ACNTA calculated value. At December 31, 2009, the fixed charge coverage test resulted in a ratio of 2.01 to 1 (5.35 to 1 at December 31, 2008).  The December 31, 2009 ratio
calculation falls below the minimum requirement and thereby restricts the amount of incremental borrowings the Corporation may incur.  The Corporation may incur up to $263.4 million under the Credit Facilities and certain other permitted debt until the time when the ratio exceeds 2.5 to 1.  Management does not anticipate these restrictions to have any limiting or adverse affect on the operations of the Corporation.


- 15 -


The calculation of the ACNTA was $263.4 million at December 31, 2009 ($383.0 million at December 31, 2008), which was higher than the Credit Facilities' authorized limits.  Any reduction in Compton’s ability to access credit under the Credit Facilities, or requirement to pay amounts outstanding under the Note Indenture
before its stated maturity date may result in the Corporation not being able to meet its financial obligations as they come due.




VOLATILITY OF PRICES, MARKETS, AND MARKETING PRODUCTION




Oil and gas prices have historically been extremely volatile.  Factors which contribute to oil and gas price fluctuations include global demand, domestic and foreign supplies of oil and gas, the price of foreign oil and gas imports, decisions of the Organization of Petroleum Exporting Countries relating to export quotas, domestic
and foreign governmental regulations, political conditions in producing regions, global and domestic economic conditions, the price and availability of alternative fuels, including liquefied natural gas, and weather conditions.




The Corporation’s financial condition is substantially dependent on, and highly sensitive to, oil and gas commodity prices.  Any material decline in prices could result in a material reduction of Compton’s operating results, revenue, reserves, and overall value.  Lower commodity prices could change the
economics of production from some wells.  As a result, the Corporation could elect not to drill, develop, or produce from certain wells. In addition, Compton is impacted by the differential between prices paid by refiners for light quality oil and the grades of oil produced by the Corporation.




Current market conditions are particularly challenging with the global recession negatively impacting commodity prices as well as access to credit and capital markets.  These conditions impact Compton’s customers and suppliers and may alter Compton’s spending and operating plans.  There may be unexpected
business impacts from this market uncertainty.




Under Canadian GAAP, oil and gas assets are reviewed quarterly to determine if the carrying value of the assets exceeds their expected future cash flows.  A sustained period of low commodity prices may reduce expected future cash flows and require a write down to the fair value of the Corporation’s oil and gas properties,
thereby adversely affecting operating results.




Any future and sustained period of weakness in oil and gas prices would also have an adverse effect on Compton’s capacity to borrow funds.  The Corporation’s secured Credit Facilities are based upon the lenders’ estimate of the value of the Corporation’s proved reserves, which determines the borrowing
amount.  A reduction in the quantity or value of reserves may also obligate Compton to make additional payments under the processing agreement with MPP.




Any decline in the Corporation’s ability to market production could have a material adverse effect on production levels or on the sale price received for production.  Compton’s ability to market the oil and gas from the Corporation’s wells depends on numerous factors beyond the Corporation’s control,
including the availability and capacity of gas gathering systems, pipelines and processing facilities, and their proximity to the wells.  The Corporation will be impacted by Canadian federal and provincial, as well as US federal and state, energy policies, taxes, regulation of oil and gas production, processing, and transportation, as well as Canadian federal regulation of oil and gas sold or transported outside of the province of Alberta.




NEED TO REPLACE RESERVES




Compton’s future success depends upon the Corporation’s ability to find, develop, or acquire additional oil and gas reserves that are economically recoverable.  Without successful exploration, development, exploitation, or acquisition activities, the Corporation’s reserves will deplete and, as a consequence,
either production or the average life of reserves will decline.  If future production declines to the extent that cash flow becomes insufficient to fund capital expenditures, and external sources of capital become limited or unavailable, the Corporation’s ability to make the necessary capital expenditures to maintain and expand its oil and gas reserves will be impaired.  Compton cannot guarantee that it will be able to find and develop or acquire additional reserves at an acceptable
cost.


- 16 -


Management will continue to evaluate prospects on an ongoing basis in a manner consistent with industry standards and past practices.  The long-term commercial success of the Corporation depends on its ability to find, acquire, develop, and commercially produce oil and gas reserves.  No assurance can be given that
Compton will be able to locate satisfactory properties for acquisition or participation.  Moreover, if such acquisitions or participations are identified, the Corporation may determine that current markets, terms of acquisition and participation, or pricing conditions make such acquisitions or participations uneconomic.




Compton’s strategies to minimize this inherent risk include focusing on selected core areas in Western Canada with high working interests and assuming operatorship of key facilities.  The Corporation utilizes a team of highly qualified professionals with expertise and experience in these areas.  Compton assesses
strategic acquisitions to complement existing activities while striving for a balance between exploration and lower risk development and exploitation prospects.




UNCERTAINTY OF RESERVE ESTIMATES




Estimates of oil and gas reserves and the future net cash flow there from, involve a great deal of uncertainty because they depend upon the reliability of available geologic and engineering data, which is inherently imprecise.  Geologic and engineering data are used to determine the probability that an oil and gas reservoir
exists at a particular location and whether oil and gas are recoverable from the reservoir.  The probability of the existence and recoverability of reserves is less than 100% and actual recoveries of proved reserves may be materially different from estimates.




Estimates of oil and gas reserves require numerous assumptions relating to operating conditions and economic factors, including future oil and gas prices, availability of investment capital, recovery costs, the availability of enhanced recovery techniques, the ability to market production, and governmental and other regulatory factors,
such as taxes, royalty rates, and environmental laws.  A change in one or more of these factors could result in known quantities of oil and gas previously estimated as proved reserves becoming unrecoverable.  Each of these factors also impact recovery costs and production rates, and therefore, will reduce the present value of future net cash flows from estimated reserves.




In addition, estimates of reserves, and future net cash flows expected there from, that are prepared by different independent engineers or by the same engineers at different times, may vary substantially.




DIFFERENCE IN RESERVES REPORTING PRACTICES BETWEEN CANADA AND THE UNITED STATES




Compton reports its production and reserve quantities in accordance with Canadian practices and specifically in accordance with NI 51-101.  These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the SEC by companies in the United States.




The Corporation incorporates additional information with respect to production and reserves which is either not generally included or prohibited under rules of the SEC and practices in the United States.  Compton follows the Canadian practice of reporting gross production and reserve volumes; however, it also follows the United
States practice of separately reporting these volumes on a net basis (after the deduction of royalties and similar payments).  The Corporation also follows the Canadian practice of using forecast prices and costs when it estimates its reserves.  However, Compton separately estimates its reserves using prices and costs held constant at the effective date of the reserve report in accordance with the Canadian reserve reporting requirements.  These latter requirements are similar to
the average constant pricing reserve methodology utilized in the United States.




Compton has included estimates of proved, proved plus probable and possible reserves, as well as contingent resources in this AIF.  Prior to January 1, 2010, the SEC generally prohibited the inclusion of estimates of probable and possible reserves and contingent resources in filings made with it by United States oil and gas
companies.  However, the SEC has adopted revisions to its oil and gas reporting rules that, effective as of January 1, 2010, among other things, modified the standards to establish proved reserves and permit disclosure of probable and possible reserves under certain circumstances.  However, it is likely that significant differences will remain between the reserve categories and reserve reporting generally under Canadian and US securities laws and rules.


- 17 -


EXPLORATION, DEVELOPMENT, AND PRODUCTION RISKS




There are many operating risks and hazards inherent in exploring for, producing, processing, and transporting oil and gas.  Drilling operations may encounter unexpected formations or pressures that could cause damage to equipment or personal injury and fires, explosions, blowouts, oil spills, or other accidents may occur.  Additionally,
Compton could experience interruptions to or the termination of drilling, production, processing, and transportation activities due to bad weather, natural disasters, delays in obtaining governmental approvals or consents, insufficient storage or transportation capacity, or other geological and mechanical conditions.  Any of these events that result in a shutdown or slowdown of operations will adversely affect the Corporation’s business.  While close well supervision and effective maintenance
operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees.




Drilling activities, including completions, are subject to the risk that no commercially productive reservoirs will be encountered and the Corporation will not recover all or any portion of its investment.  The cost of drilling, completing, and operating wells is often uncertain due to drilling in unknown formations, the costs
associated with encountering various drilling conditions, such as over pressured zones, and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof.




INSURANCE




The risks and hazards of Compton’s operations could result in damage to, or destruction of, oil and gas wells, production and processing facilities, pipelines or other property, environmental damage, or personal injury for which the Corporation will be liable.  The location of operations near populated areas, including
residential areas, commercial business centers, and industrial sites could increase these risks and hazards.  The Corporation cannot fully protect against all of these risks, nor are all of these risks insurable.  Compton may become liable for damages arising from these events against which it cannot insure or against which it may elect not to insure because of high premium costs or other reasons.  The occurrence of a significant event not fully insured or indemnified against could
seriously harm Compton’s financial condition and operating results.




COMPETITION




The oil and gas industry is highly competitive.  The Corporation competes for capital, acquisitions of reserves, undeveloped lands, skilled personnel, access to drilling rigs, service rigs and other equipment, access to processing facilities, and pipeline and refining capacity with a substantial number of other organizations,
many of which may have greater technical and financial resources than Compton.  Some of these organizations not only explore for, develop and produce oil and gas but also carry on refining operations and market crude oil and other products on a worldwide basis.  As a result of these complementary activities, some competitors may have greater and more diverse competitive resources to draw on than does Compton.




AVAILABILITY OF DRILLING EQUIPMENT AND ACCESS RESTRICTIONS




Compton’s drilling operations could be curtailed, delayed, or cancelled as a result of access restrictions or shortages or delays in the delivery of equipment and services.  Oil and gas industry operations in the WCSB are affected by road bans imposed from time to time, which can restrict access to well sites and production
facility sites.  In addition, landowner constraints or poor surface conditions could disrupt access to the Corporation’s properties.  Compton’s inability to access the Corporation’s properties or to conduct business as planned could result in a shutdown or slowdown of operations.




Exploration and development activities also depend on the availability of drilling and related equipment in the particular areas where such activities will be conducted.  Increased demand for that equipment or imposed access restrictions may affect the availability of equipment to the Corporation and may delay exploration and
development activities.  In addition, to the extent that Compton is not the operator of transportation facilities and pipelines, it will be dependent on such operators for the timing of activities related to such properties and will be largely unable to direct or control the activities of the operators.


- 18 -


RELIANCE ON KEY EMPLOYEES




Compton depends to a large extent on the services of key management personnel, including the Corporation’s executive officers and other key employees, the loss of any of whom could have a material adverse effect on operations.  The Corporation does not maintain key man life insurance with respect to any employees.  Compton’s
success will be dependent upon its ability to continue to employ and retain skilled personnel.




MARKET PRICE OF THE COMMON SHARES




The price of Compton’s Common Shares is likely to be significantly affected by short-term changes in commodity prices and currency exchange fluctuation.  Factors such as fluctuations in its operating results, the result of any public announcements made by the Corporation, and general market conditions can also have an
adverse effect on the market price of securities.  The trading price of Compton’s Common Shares has been and may continue to be subject to large fluctuations, which may result in losses to investors.  The high and low closing sale prices of Common Shares on the TSX were $13.19 and $7.40 in 2007; $13.20 and $0.88 in 2008; and $2.03 and $0.56 in 2009, respectively.




The high and low closing sale prices of Common Shares on the NYSE were US$12.16 and US$7.70 in 2007; US$12.94 and US$0.68 in 2008; and US$1.75 and US$0.44 in 2009, respectively.




POTENTIAL DILUTION




Management continually evaluates acquisition opportunities and recapitalization transactions, and although the Corporation is not currently party to any definitive agreements in respect of such transactions, it may engage in transactions that result in the issuance of additional Common Shares, which issuances may be dilutive.  In
October 2009, the Corporation issued 138 million warrants in connection with an equity transaction, which are exercisable at $1.55 per share at any time during two years following the transaction’s close.  Other issuances of additional Common Shares may also result in dilution to the holders of the Common Shares.




CHANGES TO ALBERTA ROYALTY REGIME




On January 1, 2009 the Mines and Minerals (New Royalty Framework) Amendment Act, 2008 became law in Alberta.  This legislation implements a new royalty framework (the “New Royalty Framework”) which involves an increase in the royalties collected by the Alberta government and changes the royalty structure for
natural gas and conventional oil by adjusting the current sliding rate formulae that are price and volume sensitive.  On November 19, 2008 the government of Alberta announced that it will be providing companies with a one-time option to select new transitional royalty rates, on a well-by-well basis, to companies that are drilling new natural gas or conventional oil wells (between 1,000 and 3,500 metres deep) after January 1, 2009.  All wells that are drilled between 2009 and the end of 2013
that adopt the transitional rates will be required to shift to the New Royalty Framework on January 1, 2014.  All current wells moved to the New Royalty Framework on January 1, 2009.




In addition, on March 3, 2009 the Alberta government announced an incentive program to encourage additional activity in the province’s oil and gas sectors.  The program applies to wells drilled between April 1, 2009 and March 31, 2010 and provides (i) a $200 per metre royalty credit for new wells and (ii) a maximum royalty
rate of 5% on such wells for the first 12 months of production up to a maximum of 50,000 barrels of oil or 500 million cubic feet of natural gas.  This program will be in effect until March 31, 2011 and will be assessed as required as to whether it is necessary or appropriate to continue it.  It is expected that the program will have the effect of reducing Compton’s royalties but the magnitude of this reduction is unknown.  Given the recent changes to Alberta’s royalty
regime, it is not possible to predict if and when any future changes may occur.


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ENVIRONMENTAL RISKS




The oil and gas industry is subject to extensive environmental laws and regulations pursuant to local, provincial, and federal legislation.  Compliance with any new legislation may require significant expenditures and a failure to comply may result in the issuance of shut-in or closure orders or the imposition of fines and penalties,
some of which may be material.  It is possible that the costs of complying with environmental regulations in the future will have a material adverse effect on the Corporation’s financial condition.  Environmental regulation provides for, among other things, restrictions and prohibitions on the generation, handling, storage, transportation, treatment, and disposal of hazardous substances and waste from spills, releases, or emissions of various substances produced in association with oil
and gas operations.  The legislation also requires that wells, facility sites, and other properties associated with the Corporation’s operations be operated, maintained, abandoned, and reclaimed to the satisfaction of applicable regulatory authorities.  Under environmental legislation, Compton may be liable for personal injury, clean-up costs, remedial measures, and other environmental and property damages, as well as administrative, civil, and criminal penalties.




Furthermore, future changes in environmental laws and regulations, including adoption of stricter standards or more stringent enforcement, could result in increased costs, incurred liability, and increased capital expenditures and operating costs, any of which could have a material adverse effect on Compton’s financial condition.  As
Compton’s production facilities and other operations and activities emit greenhouse gases, the Corporation may be subject to emissions targets and may subject the Corporation to legislation that will require increasingly strict regulation with respect to the emissions of greenhouse gases.




Given the evolving nature of climate change action and regulation, it is not possible to predict the nature of future legislation with respect to climate change or the impact on the Corporation, its operations and financial condition at this time.




Compton has not established a separate reclamation fund for the purpose of funding estimated future environmental and reclamation obligations.  Any site reclamation or abandonment costs incurred in the ordinary course in a specific period will be funded out of cash flow from operations.  It is not possible to predict
Compton’s ability to fully fund the cost of all its future environmental, abandonment and reclamation obligations.




The Corporation is not fully insured against certain environmental risks, either because such insurance is not available or because of high premium costs. In particular, insurance against risks from environmental pollution occurring over time, as opposed to sudden and catastrophic damages, is not available on economically reasonable terms.  Accordingly,
Compton’s properties may be subject to liability due to hazards that cannot be insured against or that have not been insured against due to prohibitive premium costs or for other reasons.




The risks above, as well as additional information are also disclosed in the Corporation’s Annual Information Form, and is available on www.sedar.com.




VIII.           Critical Accounting Estimates




The preparation of the Corporation’s financial statements requires Management to adopt accounting policies that involve the use of significant estimates and assumptions.  These estimates and assumptions are developed based on the best available information and are believed by Management to be reasonable under the existing
circumstances.  New events or additional information may result in the revision of these estimates over time.  The critical estimates are discussed below.




OIL AND NATURAL GAS RESERVES




The independent petroleum engineering and geological consulting firm of Netherland, Sewell & Associates, Inc. evaluated and reported on 100% of Compton’s oil and natural gas reserves as at December 31, 2009.


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




DEPLETION




Capitalized costs and estimated future expenditures to develop proved reserves, including abandonment costs, are depleted based on the proportion of proved oil and natural gas reserves produced during the year compared to estimated total proved reserves.  Investments in unproved properties and major development projects are
not depleted until proved reserves associated with the projects can be determined or until impairment occurs.  If it is determined that properties are impaired, the amount of the impairment is added to the capitalized costs to be depleted.




In 2009, Compton incurred $134.7 million of depletion and depreciation expense.  If proved reserves were to increase by 5%, depletion and depreciation expense would decrease by $1.4 million and consolidated net earnings after tax would increase by $1.0 million.  If proved reserves were to decrease by 5%, depletion
and depreciation expense would increase by $1.5 million and consolidated net earnings after tax would decrease by $1.1 million.




IMPAIRMENT




In applying the full cost method of accounting under Canadian GAAP, Compton periodically calculates a ceiling or limitation on the amount that property and equipment may be carried on the consolidated balance sheets.  An impairment exists if the undiscounted future net cash flows from proved reserves at future commodity prices
plus the cost of undeveloped properties are less than the carrying value of the capitalized costs.  As at December 31, 2009, the ceiling amount calculated was $1.2 billion (2008 - $2.5 billion) in excess of the carrying value of the costs capitalized.




If impairment is found to exist, the impaired properties are written down to their fair value.  The fair value of the assets is calculated based on future net cash flows from proved plus probable reserves, discounted at a risk free interest rate using forecasted future commodity prices, plus the estimated cost of undeveloped
properties.  An impairment may result in a material loss for a particular period; however, future depletion and depreciation expense would be reduced as a result.




Assumptions about reserves and future prices are required to calculate future net cash flows.  The assumptions made to estimate reserves have been discussed above.  There is significant uncertainty regarding forecasting future commodity prices due to economic and political uncertainties.  Future prices are
derived from a consensus of price forecasts among recognized reserve evaluators.  Estimates of future cash flows assume a long term price forecast and current operating costs per boe plus an inflation factor.




It is difficult to determine and assess the impact of a decrease in proved reserves on impairment.  The relationship between reserve estimates and the estimated undiscounted cash flows, and the nature of the property-by-property impairment test is complex.  As a result, it is not possible to provide a reasonable sensitivity
analysis of the impact that a reserve estimate decrease would have on impairment.




FULL COST ACCOUNTING AND CEILING TEST




The Corporation follows the full cost method of accounting for petroleum and natural gas operations.  All costs related to the acquisition of, exploration for and development of petroleum and natural gas reserves are capitalized.  These capitalized costs are evaluated on an annual basis to determine that the costs
are recoverable and do not exceed the fair value of the properties (the “ceiling test”).  These costs are also depleted on a unit-of-production basis.  The ceiling test and depletion expense require estimates of reserve volumes and discounted cash flows, which are calculated by independent reserve engineers using assumptions including, but not limited to, future commodity prices, government policy, royalty rates, capital spending and operating costs.


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GOODWILL




Compton records goodwill relating to a corporate acquisition when the purchase price exceeds the fair value for accounting purposes of the net identifiable assets and liabilities acquired by the Corporation.  The goodwill balance is assessed for impairment annually at year-end or as events occur that could result in an impairment.  Compton
compares the fair value of the entity to its carrying value, including goodwill.  If the carrying value exceeds the fair value, a goodwill impairment loss is charged to income.  The fair value is largely determined using estimates of reserve volumes and discounted cash flows, which are calculated by independent reserve engineers using assumptions including, but not limited to, future commodity prices, government policy, royalty rates, capital spending and operating costs.




The valuation of goodwill assessed under the CICA guidance of Handbook Section 3064, “Goodwill and Intangible Assets”, resulted in the write-off of goodwill ($9.9 million) at December 31, 2009.  The associated assets from which the goodwill arose were sold prior to 2009.  The write-off has been included
in the consolidated statements of earnings (loss) and other comprehensive income for 2009.




HEDGES




Compton uses derivative financial instruments to hedge its exposure to commodity price, foreign exchange and interest rate fluctuations.  The mark-to-market valuations of these hedge contracts are presented in the Corporation’s consolidated financial statements as at December 31, 2009.  These valuations are based
on forward looking estimates including, but not limited to, volatility, interest rates and commodity prices.




ASSET RETIREMENT OBLIGATIONS




The Corporation records a liability for the fair value of legal obligations associated with the retirement of long-lived tangible assets in the period in which they are incurred, normally when the asset is purchased or developed.  On recognition of the liability, there is a corresponding increase in the carrying amount of the
related assets, known as the asset retirement cost, which is depleted on a unit-of-production basis over the life of the reserves.  The liability for these future legal obligations is discounted using estimates of interest rates, inflation rates and the length of time to actual settlement.




Compton 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 Corporation will be required to retire tangible long term assets such as well sites, pipelines
and facilities.  The asset retirement cost, equal to the initially estimated fair value of the asset retirement obligation, is capitalized as part of the cost of the related long term assets.  Increases in the asset retirement obligations resulting from the passage of time are recorded as accretion of asset retirement obligations in the consolidated statement of earnings.  Amounts recorded for asset retirement obligations are subject to uncertainty associated with the method, timing
and extent of future retirement activities.  Actual payments to settle the obligations may differ from estimated amounts.




A summary of the significant accounting policies used by Compton can be found in Note 2 of the 2009 consolidated financial statements.




IX.           Forthcoming and Newly Adopted Accounting Policies




INTERNATIONAL FINANCIAL REPORTING STANDARDS




On February 13, 2008, the Canadian Accounting Standards Board (“AcSB”) confirmed the mandatory changeover date to International Financial Reporting Standards (“IFRS”) for Canadian profit-oriented publicly accountable entities (“PAEs”) such as Compton.


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The AcSB requires that IFRS compliant financial statements be prepared for annual and interim financial statements commencing on or after January 1, 2011.  For PAEs with a December 31 year-end, the first unaudited interim financial statements under IFRS will be for the quarter ending March 31, 2011, with comparative financial
information for the quarter ending March 31, 2010.  The first audited annual financial statements will be for the year ending December 31, 2011, with comparative financial information for the year ending December 31, 2010.  This also means that all opening balance sheet adjustments relating to the adoption of IFRS must be reflected in the January 1, 2010 opening balance sheet which will be issued as part of the comparative financial information in the March 31, 2011 unaudited interim financial
statements.




Compton will adopt these requirements as set out by the AcSB and other regulatory bodies.  The Corporation has developed and commenced implementing its plan for the changeover to IFRS to ensure that Compton addresses matters such as accounting policies, information technology systems, internal controls, disclosure controls and
procedures, staffing requirements, and business activities impacted by accounting processes and measures.




The plan is comprised of three stages.  The first stage is to obtain an understanding of the impact that the conversion to IFRS will have on the elements described above.  The second stage is to develop and test solutions for the issues identified in stage one.  The third and final stage is to implement the
solutions developed in stage two.




At December 31, 2009, Compton has completed its assessment of GAAP differences, and developed a project plan to transition the Corporation to IFRS under the required timelines.  The Corporation is currently in the second stage, assessing accounting policy selection alternatives, and developing solutions for the implementation
of systems and process changes necessary to support the Corporation’s reporting under IFRS.  The current activities are focused on areas identified as having the most significant impact to Compton, which include cost recognition for property and equipment, asset componentization and depreciation, the identification of cash generating units and valuation.  Management is working with an external consultant to support project resourcing and the execution of the transition plan.


- 23 -


The following milestones and timelines have been identified under the project plan, and focus Management’s key transition initiatives. As outlined below, Management believes it is on target to successfully transition to IFRS.





Financial Statements

Target
Completion
Status at
December 31, 2009•
Identification of significant differences between Canadian GAAP and IFRS.  Identification of key conversation issues

Q3 2009
Completed•
Development of position papers for identified GAAP differences, and selection of accounting policy alternatives

Q2 2010
In progress•
Selection of IFRS 1 exemptions and accounting policy choices

Q2 2010
In progress•
Preparation of the opening balance sheet reconciliation under IFRS

Q3 2010
To commence in Q2 2010•
Determination of new financial statement note disclosure requirements

Q3 2010
To commence in Q2 2010•
Restatement of 2010 Quarterly information for comparative presentation purposes

Q1 2011
To commence in Q3 2010Information Technology•
Assess systems impact for accounting policy selections and required note disclosure information

Q2 2010
Commenced in Q1 2010Control Environment•
For all accounting policy changes, assess impact on internal controls over financial reporting and disclosure controls.  Implement appropriate changes

Q4 2010
To commence in Q3 2010




While at this time the impact of adopting IFRS cannot be reasonably quantified, Management targets an assessment to be available for our Q3 2010 Corporate summary.  Management anticipates that the most significant impact of transition will be the revised financial disclosure under IFRS, which is generally viewed to be more detailed
and comprehensive than that of Canadian GAAP.




CHANGES IN ACCOUNTING POLICIES




New Accounting Policies Adopted




On January 1, 2009, the Corporation adopted the Canadian Institute of Chartered Accountants (“CICA”) Handbook Section 3064, “Goodwill and Intangible Assets”.  The new standard replaces the previous goodwill and intangible asset standard and revises the requirement for recognition, measurement, presentation
and disclosure of intangible assets.  The adoption of this standard has had no significant impact on the Corporation’s consolidated financial statements.




On January 1, 2009, the Corporation adopted Emerging Issues Committee Abstract 173, “Credit Risk and the Fair Value of Financial Assets and Financial Liabilities”.  The abstract outlines the requirement for an entity to assess both it’s own and any counterparty’s credit risk when assessing the fair value
of assets and liabilities, including derivative instruments.  The adoption of this abstract has had no significant impact on the Corporation’s consolidated financial statements.


- 24 -


Recent Accounting Pronouncements




In January 2009, the CICA issued Handbook Section 1582, “Business Combinations” which requires all assets and liabilities of an acquired business be recorded at fair value at acquisition.  Obligations for contingent consideration and contingencies will also be recorded at fair value at the acquisition date.  The
standard also states that acquisition related costs are expensed as incurred and that restructuring charges will be expensed in the periods after the acquisition date.  The standard applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period on or after January 1, 2011.  The Corporation is currently assessing the impact of the new standard on its consolidated financial statements.




In January 2009, the CICA issued Handbook Section 1601, “Consolidations” and Section 1602, “Non-controlling Interests”.  Section 1601 establishes standards for the preparation of consolidated financial statements.  Section 1602 establishes standards for accounting for a non-controlling interest
in consolidated financial statements subsequent to a business combination.  These standards apply to interim and annual consolidated financial statements relating to fiscal years beginning on or after January 1, 2011.  The Corporation is currently assessing the impact of these new standards on its consolidated financial statements.




X.           Quarterly Information




The following table sets forth certain quarterly financial information of the Corporation for the eight most recent quarters.





2009


2008($millions, except where noted)


Q4



Q3



Q2



Q1



Q4



Q3



Q2



Q1Total revenue(1)

$
58


$
47


$
54


$
69


$
105


$
153


$
187


$
161Cash flow(1)

$
6


$
7


$
10


$
22


$
29


$
87


$
77


$
63Per share
-   basic

$
0.03


$
0.06


$
0.08


$
0.18


$
0.23


$
0.67


$
0.59


$
0.49-   diluted

$
0.03


$
0.06


$
0.08


$
0.18


$
0.23


$
0.66


$
0.58


$
0.48Net earnings (loss)

$
(24
)

$
13


$
20


$
(17
)

$
(96
)

$
60


$
(9
)

$
2Per share
-   basic

$
(0.09
)

$
0.10


$
0.16


$
(0.14
)

$
(0.74
)

$
0.46


$
(0.07
)

$
0.01-   diluted

$
(0.09
)

$
0.10


$
0.16


$
(0.14
)

$
(0.74
)

$
0.46


$
(0.07
)

$
0.01Operating earnings(1)

$
(25
)

$
(19
)

$
(16
)

$
(1
)

$
(19
)

$
46


$
24


$
16ProductionNatural gas (mmcf/d)


98



99



108



117



125



130



150



170Liquids (bbls/d)


3,055



3,208



3,428



3,655



4,113



4,323



5,643



5,009Total (boe/d)


19,351



19,760



21,440



23,194



24,868



26,006



30,557



33,274Average priceNatural gas ($/mcf)

$
4.38


$
3.14


$
3.80


$
5.18


$
6.99


$
8.75


$
9.42


$
7.48Liquids ($/bbl)

$
57.10


$
55.42


$
49.93


$
38.35


$
60.60


$
124.05


$
110.37


$
94.97Total ($/boe)

$
31.16


$
24.78


$
27.74


$
33.01


$
45.79


$
64.08


$
67.18


$
53.07


(1)
Prior periods have been revised to conform to current period presentation




Fluctuations in quarterly results are due to a number of factors, some of which are not within the Corporation’s control such as seasonality and exchange rates.  Continued depressed commodity prices and lower production volumes due to asset sales and natural declines contributed to decreased revenues starting in the third
quarter of 2008.  The production base has stabilized to a consistent level in the final quarter of 2009.  Seasonality of winter operating conditions results in production increases that are typically higher in the third and fourth quarters.




Cash flow and operating earnings were negatively affected in the fourth quarter of 2008 by one-time non-recurring strategic review costs and quarterly during 2009 for related restructuring costs.  Increases in the US dollar against the Canadian dollar had the effect of decreasing net earnings during the fourth quarter of 2008
and the first quarter of 2009.


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XI.           Selected Annual Information





Years ended  and as at December 31,

2009


2008


2007($000’s)Total revenue

$
227,876


$
610,298


$
506,218Net earnings (loss)

$
(8,330
)

$
(43,003
)

$
129,266Per share:
basic

$
(0.05
)

$
(0.33
)

$
1.00diluted

$
(0.05
)

$
(0.33
)

$
0.98Total assets(1)

$
1,996,761


$
2,188,583


$
2,257,400Total long term financial liabilities(2)

$
568,924


$
829,321


$
832,188


(1)
Prior periods have been revised to conform with current period presentation


(2)
Includes senior term notes and bank debt




Total revenue in 2009 was 63% lower than in 2008 due significantly lower realized prices for both natural gas and liquids, as well as an overall reduction in production volumes from the sale of non-core asset and royalty interests following the strategic review process in 2008.




XII.           Trading and Share Statistics




As at February 25, 2010 there are 263,573,451 common shares, 18,143,570 stock options, and 138,000,000 share purchase warrants outstanding.





2009


2008


2007TSX
($Cdn)


NYSE
($US)


TSX
($Cdn)


NYSE
($US)


TSX
($Cdn)


NYSE
($US)Average daily trading volume


1,187,853



867,206



525,474



332,354



485,027



213,044Share price ($/share)High

$
2.03


$
1.75


$
13.20


$
12.94


$
13.19


$
12.16Low

$
0.56


$
0.44


$
0.88


$
0.68


$
7.40


$
7.70Close

$
0.94


$
0.92


$
0.93


$
0.80


$
9.14


$
9.20Market capitalization at December 31, ($000s)


Cdn $247,759



Cdn $116,957



Cdn $1,179,958Shares outstanding (000s)


263,573



125,760



129,098


XIII.           Advisories




NON-GAAP FINANCIAL MEASURES




Included in this document are references to terms used in the oil and gas industry such as, cash flow, operating earnings (loss), free cash flow, funds flow per share, adjusted EBITDA, field netback, cash flow netback, debt and capitalization.  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.  These measures have been described and presented in this document in order to provide shareholders and potential investors with additional information regarding the Corporation’s liquidity and its ability to generate funds to finance its operations.




USE OF BOE EQUIVALENTS




The oil and natural gas industry commonly expresses production volumes and reserves on a barrel of oil equivalent (“boe”) basis whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil.  The intention is to sum oil and natural gas measurement units
into one basis for improved measurement of results and comparisons with other industry participants.  Compton uses 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 well head and therefore may be a misleading measure if used in isolation.


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FORWARD-LOOKING STATEMENTS




Certain information regarding the Corporation contained herein constitutes forward-looking information and statements and financial outlooks (collectively, “forward-looking statements”) under the meaning of applicable securities laws, including Canadian Securities Administrators’ National Instrument
51-102 Continuous Disclosure Obligations and the United States Private Securities Litigation Reform Act of 1995 and the United States Securities and Exchange Act of 1934, as amended.




Forward-looking information and statements involve risks, uncertainties and other factors that could cause actual results to differ materially from those expressed or implied by them.  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 and capital and operating expenditures, (ii) exploration, drilling, completion, and production matters, (iii) results of operations, (iv) financial position, and (v) other risks and uncertainties described from time to time in the reports and filings made by Compton with securities regulatory authorities.  Although Compton believes that the assumptions underlying, and expectations reflected in, such forward-looking statements
are reasonable, it can give no assurance that such assumptions and expectations will prove to have been correct.  There are many factors that could cause forward-looking statements not to be correct, including risks and uncertainties inherent in the Corporation’s business.  These risks include, but are not limited to: crude oil and natural gas price volatility, exchange rate fluctuations, availability of services and supplies, operating hazards, access difficulties and mechanical failures,
weather related issues, uncertainties in the estimates of reserves and in projection of future rates of production and timing of development expenditures, general economic conditions, and the actions or inactions of third-party operators, and other risks and uncertainties described from time to time in the reports and filings made with securities regulatory authorities by Compton.  Statements relating to “reserves” and “resources” are deemed to be forward-looking statements,
as they involve the implied assessment, based on estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future.




The forward-looking statements contained herein are made as of the date of this document solely for the purpose of generally disclosing Compton’s views of its prospective activities.  Compton may, as considered necessary in the circumstances, update or revise the forward-looking statements, whether
as a result of new information, future events, or otherwise, but Compton does not undertake to update this information at any particular time, except as required by law.  Compton cautions readers that the forward-looking statements may not be appropriate for purposes other than their intended purposes and that undue reliance should not be placed on any forward-looking statement.  The Corporation’s forward-looking statements are expressly qualified in their entirety by this cautionary
statement.




Additional Information




Further information regarding Compton can be accessed under the Corporation’s public filings found at www.sedar.com and on the Corporation’s website at www.comptonpetroleum.com.




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