Exhibit 99.3


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, 2010, as well as the audited consolidated financial statements and MD&A for the year ended December 31, 2009.  Readers should also read the “Forward-Looking Statements” legal advisory located 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”).  Amounts presented in this MD&A are stated in thousands (000’s) of dollars except per share and boe amounts, unless otherwise stated.  This document is dated as at February 24, 2011.




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 majority of 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 four deep basin natural gas plays:  the Rock Creek sands at Niton in central Alberta, the Basal Quartz sands at High River in southern Alberta, the shallower Southern Plains Belly River sands in southern Alberta, and an exploratory play in the Foothills area of southern Alberta.  Being in the Deep Basin, all areas have multi-zone potential, providing future development and exploration opportunity. Compton is also focused on developing its emerging oil potential in the Southern Plains area and in the Montana lands. Natural gas represents approximately 84% of production and 88% of reserves.




II.        Results from Corporate Strategy




Management has focused on value creation through capital efficiency and operating expense improvements.  This approach has increased Compton’s efficiencies and served to partially offset the impact of lower natural gas prices on cash flows generated by operation activities over the past two years.  These focused measures have resulted in the Corporation exceeding Management’s 2010 targets for average daily volume production, operational costs and administrative expenses.  Results for 2010 include:




·
Met or exceeded annual guidance targets




·
Average daily production was 17,402 boe/d




o
Operational improvements largely mitigated natural declines: exit rates in 2010 decreased approximately 8% over 2009 after adjusting for dispositions




·
Reduced operating and administrative expenses by a combined $24.3 million from 2009




o
Operating expenses were $66.1 million, which was 17% below guidance and 21% below 2009 expenses




o
Operating costs per boe were $10.41, which was below the 2009 average of $11.07 per boe despite lower production




1




o
Administrative expenses decreased by 21% to $22.7 million from 2009




·
Substantially improved capital efficiencies:




o
Improved drilling methods at Niton, resulting in approximately 25% higher average initial production rates and 15% to 20% lower drilling costs over the previous year




o
Base volume performance was 5% or 870 boe/d higher than expectations  due to production optimization




o
Reinitiated development programs in High River with the refracture of two wells, resulting in combined average production of 450 Mcf/d, which was  4.5-times previous levels




·
Achieved a 80% success rate on the 31 wells drilled or participated in during the year




·
Increased production rates at Niton: a Rock Creek well drilled during the fourth quarter had an initial test rate of 5.5 MMcf/d with 30 bbl/MMcf of liquids. The well is currently on production at approximately 3.3 MMcf/d and 35 bbl/MMcf of liquids




·
Successfully drilled a Spirit River vertical well in Niton that was brought on production at 1 MMcf/d. The results from this well support further development in the Spirit River Formation, reinforcing Niton’s multi-zone potential




·
Initiated oil prospect drilling with an Ellerslie well in the Southern Plains, which is awaiting completion. Initial indications are promising with approximately 700 metres of pay being encountered in the wellbore




·
Completed the sale of $150.2 million in assets at Niton and Gilby




·
Completed an exchange of existing Senior Term Notes (the “Notes”) for a combination of cash from proceeds of asset sales and new term notes




·
Reduced the credit facility (the “Facility”) and Notes by 33% or $186.1 million compared to year-end 2009




·
Renewed the Facility to an authorized credit limit of $170.0 million at December 31, 2010




Throughout 2010, Compton strengthened its balance sheet and improved the Corporation’s capital structure, reducing overall financial risk.  Compton’s achievements in increasing initial well production while decreasing drilling and operating costs resulted in the ability to maximize the value of capital employed.




III.        Results of Operations





Years ended December 31,

2010


2009


2008Average production (boe/d)


17,402



20,922



28,658Capital expenditures


46,309



68,303



324,549Cash flow(1)(2)(3)

$
42,805


$
50,255


$
291,371Per share:   basic

$
0.16


$
0.32


$
2.25diluted

$
0.16


$
0.32


$
2.21Operating earnings (loss)(1)(2)

$
(75,576
)

$
(61,038
)

$
70,949Net earnings (loss)(4)

$
(330,854
)

$
(8,330
)

$
(43,003
)Per share:   basic

$
(1.26
)

$
(0.05
)

$
(0.33
)diluted

$
(1.26
)

$
(0.05
)

$
(0.33
)Revenue, net of royalties

$
186,027


$
200,202


$
490,374Field netback (per boe)(1)(2)

$
19.68


$
18.35


$
34.26


(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)
2010 includes non-recurring costs of $14.3 million related to terminated office lease costs
 (4)
A $367.0 million ceiling test write-down on petroleum and natural gas assets was recorded at December 31, 2010




2




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,

2010

2009

2008Cash flow from operating activities
$
41,104
$
28,834
$
300,231Plus:  Terminated office lease costs(1)

13,385

-

-Plus:  Strategic review and restructuring costs

5,547

4,816

35,490Less:  Gain on extinguishment of Notes(2)

(9,040)

-

-Less:  Change in non-cash working capital

(8,191)

16,605

(44,350)Cash flow
$
42,805
$
50,255
$
291,371Per share - basic
$
0.16
$
0.32
$
2.25- diluted
$
0.16
$
0.32
$
2.21


(1)
Terminated office lease costs exclude $0.9 million of non-cash expenses related to leasehold improvement costs
 (2)
On October 18, 2010 the 2013 7.625% Senior Term Notes were extinguished




Cash flow for 2010 decreased $7.5 million or 15% compared to 2009 as a result of:




·
a 17% decline in natural gas production volumes to 88 mmcf/d from 106 mmcf/d in 2009, resulting from normal production declines, the reduced level of capital expenditures and the impact of property sales completed in 2010;




·
a 16% decline in liquids production volumes to 2,791 bbls/d from 3,335 bbls/d in 2009, resulting from normal production declines, the reduced level of capital expenditures and the impact of property sales completed in 2010;




·
the effect of a 5.0% overriding royalty on revenue in 2010;







·
a $10.3 million increase in asset retirement expenditures for abandonment and reclamation work; and




·
realized risk management gains of $12.0 million compared to $30.0 million in 2009.




These factors were partially offset by:




·
reduced operating and administrative costs, which resulted in combined savings of approximately $24.3 million in 2010 due to reduced production volumes and the Corporation’s focus on cost reduction;




·
higher average realized natural gas prices, excluding financial hedges, which increased 7% to $4.43 per mcf in 2010 compared to $4.16 per mcf in 2009;




3




·
higher average realized liquids prices, which increased 32% to $65.71 per bbl compared to $49.79 per bbl in 2009;




·
a $8.2 million decrease in interest and finance charges, resulting from reduced debt levels in 2010 compared to 2009; and




·
lower transportation cost of $0.9 million resulting from reduced average production in 2010 compared to 2009.




Cash flow for the three months ended December 31, 2010 was $7.0 million, a decrease of $1.1 million or 13% when compared to $8.1 million in the same period in 2009.  The factors affecting cash flow for the fourth quarter were:




·
a 23% decline in natural gas production volumes to 75 mmcf/d from 98 mmcf/d in 2009, resulting from normal production declines, the reduced level of capital expenditures and the impact of property sales completed in 2010;




·
a 21% decline in liquids production volumes to 2,411 bbls/d from 3,055 bbls/d in 2009, resulting from normal production declines, the reduced level of capital expenditures and the impact of property sales completed in 2010;




·
lower average realized natural gas prices, excluding financial hedges, which decreased by 12% to $3.87 per mcf compared to $4.38 per mcf in 2009;







·
the effect of an additional 1.25% overriding royalty on revenue in 2010.




These factors were partially offset by:




·
higher average realized liquids prices, excluding financial hedges, which increased by 21% to $69.30 per bbl compared to $57.10 per bbl in 2009;




·
a 11% increase in realized risk management gains to $4.1 million in 2010 compared to $3.7 million in 2009;




·
a $1.7 million decrease in interest and finance charges, resulting from reduced debt levels in 2010 compared to 2009; and




·
reduced operating and administrative costs, which resulted in combined savings of approximately $14.7 million in 2010 due to reduced production volumes and the Corporation’s focus on cost reduction.




NET EARNINGS (LOSS)




The net loss of $330.9 million in 2010 was an increase of $322.6 million as compared to the $8.3 million loss in 2009.  The 2010 net loss was partially due to the same factors that impacted cash flow.  Additional items affecting net loss were:
  ·
ceiling test write-down of $367.0 million on petroleum and natural gas assets in 2010 due to a reduction in the estimated discounted cash flows of proved plus probable reserves arising from the use of a lower price deck for natural gas, reflecting the current price levels in comparison to prior years;
  ·
unrealized foreign exchange and other gains of $4.8 million compared to gains of $80.1 million in 2009;
  ·
one-time terminated office lease costs of $14.3 million in 2010;
  ·
increased strategic review and restructuring costs of $0.7 million in 2010 compared to 2009; and
  ·
accretion expense of $4.3 million compared to $3.2 million in 2009.
  These factors were partially offset by:
  ·
gain on extinguishment of the 2013 Senior Term Notes of $9.0 million in 2010;




4




·
lower stock based compensation costs, which decreased $0.5 million compared to 2009 due to reduced expense relating to Compton’s stock option and employee share purchase programs;
  ·
write-down of goodwill of $nil for 2010 compared to $9.9 million in 2009; and
  ·
future income tax recovery of $110.2 million recognized in 2010 compared to $24.1 million for 2009 (see “Income Taxes”).
  Net loss for the three months ended December 31, 2010 was $291.2 million, an increase of $267.4 million compared to the $23.8 million loss in 2009.  Items affecting cash flow detailed previously also affected net loss.  Additional items affecting net loss were:
  ·
ceiling test write-down of $367.0 million on petroleum and natural gas assets in 2010 due to a reduction in the estimated discounted cash flows of proved plus probable reserves;
  ·
increased strategic review and restructuring costs of $4.0 million in 2010 compared to 2009; and
  ·
non-cash unrealized foreign exchange and other gains of $2.8 million compared to losses of $12.0 million in 2009.




These factors were partially offset by:




·
gain on extinguishment of the 2013 Senior Term Notes of $9.0 million in 2010;




·
write-down of goodwill of $nil for 2010 compared to $9.9 million in 2009;and




·
future income tax recovery of $95.0 million recognized in 2010 compared to $2.8 million for 2009 (see “Income Taxes”).




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 alternative to net earnings as determined in accordance with Canadian GAAP.  The following provides the calculation of operating earnings (loss).





Years Ended December 31,

2010


2009


2008Net earnings (loss), as reported

$
(330,854
)

$
(8,330
)

$
(43,003
)Non-operational items, after taxUnrealized foreign exchange and other (gains) losses(1)


(19,361
)


(80,100
)


106,425Unrealized mark-to-market hedging (gains) losses


(9,151
)


9,510



(2,546
)Other expenses


19,873



4,816



35,490Goodwill written-off


-



9,933



-Ceiling test write-down(2)


366,956



-



-Tax effect


(103,039
)


4,579



(25,416
)Operating earnings (loss)(3)

$
(75,576
)

$
(59,592
)

$
70,950Per share   -    basic

$
(0.29
)

$
(0.38
)

$
0.55-    diluted

$
(0.29
)

$
(0.37
)

$
0.54


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


(2)
Excess of carrying amount of petroleum and natural gas assets when compared to proved plus probable reserves, discounted at a risk free rate of 3.75%


(3)
Prior periods have been revised to conform to current period presentation




5




CAPITAL EXPENDITURES





Years ended December 31,

2010


2009


2008Land and seismic

$
6,743


$
7,014


$
19,846Drilling and completions


43,253



26,818



221,282Alberta drilling credits


(5,905
)


-



-Production facilities and equipment


16,021



29,102



82,616Asset retirement expenditures


(14,647
)


(4,387
)


(2,768
)Corporate and other


844



9,756



3,573Capital investment


46,309



68,303



324,549AcquisitionsProperty


-



304



10,940DivestituresProperty


(152,992
)


(9,241
)


(202,892
)Gross Overriding Royalty


-



(7,165
)


-Overriding Royalty


(23,469
)


(70,651
)


-Acquisitions (divestitures), net


(176,461
)


(86,753
)


(191,952
)Total capital expenditures

$
(130,152
)

$
(18,450
)

$
132,597




The current level of natural gas prices has limited internally generated cash flow available to invest in drilling activities.  As a result, capital spending, before acquisitions, divestments and corporate expenses decreased by 32% in 2010 compared to 2009.  Capital spending in 2010 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 31 wells (18 operated wells and 13 non-operated wells), 20.1 net wells, during 2010 as compared to a total of 20 wells (6 operated wells and 14 non-operated wells), 7.0 net wells, drilled during 2009.




Capital expenditures in 2010 were partially offset by the implementation of the Alberta drilling credit program.  Asset retirement expenditures have been excluded from capital investment totals, as they are considered operational in nature.  Corporate and other expenses decreased significantly in 2010 due to one-time charges for design, construction and equipment related to the relocation of the corporate office in 2009.




During 2010, the Corporation finalized the sale of the overriding royalty over existing lands and divested properties in the Niton and Gilby areas.  In 2009, non-core assets were divested at Cecil, Zama, Thornbury and the Peace River Arch.




At December 31, 2010, a ceiling test write-down of $367.0 million was recognized in respect of the Corporation’s petroleum and natural gas assets.  The write-down reflects the excess of the carrying amount of the assets over the discounted cash flows from proved and probable reserves plus undeveloped land.  Cash flows were discounted using a risk free discount rate of 3.75%, based on long term bond rates and are reflective of the current level for natural gas prices.




Looking forward, Management plans to execute a capital program that is funded through available cash flows and funds from other sources.  The bulk of 2011 capital expenditures are scheduled in the second half of the year, but remain flexible should commodity price levels increase and additional funds become available.




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 2010 free cash





6




flow deficit of $13.5 million is lower as compared to the $18.0 million deficit in 2009. This is primarily due to the reduction in capital expenditures, as well as reduced operating and administrative costs.





Years ended December 31,

2010


2009


2008Cash flow

$
42,805


$
50,255


$
291,371Less:  capital investment


(46,309
)


(68,303
)


(324,549
)Free cash flow (deficit)

$
(3,504
)

$
(18,048
)

$
(33,178
)





PRODUCTION VOLUMES AND REVENUE





Years ended December 31,

2010


2009


2008Average productionNatural gas (mmcf/d)


88



106



143Liquids (bbls/d)


2,791



3,335



4,769Total (boe/d)


17,402



20,922



28,658Benchmark pricesAECO ($/GJ)Monthly index

$
3.91


$
3.92


$
7.71Daily index

$
3.79


$
3.75


$
7.72WTI (US$/bbl)

$
79.54


$
61.80


$
109.47Edmonton sweet light ($/bbl)

$
77.52


$
65.79


$
102.11Realized prices(1)Natural gas ($/mcf)

$
4.43


$
4.16


$
8.17Liquids ($/bbl)

$
65.71


$
49.79


$
98.68Total ($/boe)

$
32.87


$
28.90


$
57.26Revenue(1)Natural gas

$
141,841


$
160,112


$
428,413Liquids


74,228



67,764



181,885Total

$
216,069


$
227,876


$
610,298


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




Production volumes for 2010 were 17% lower than in 2009, primarily due to the sale of assets at Niton and Gilby during 2010.  In addition, natural declines and limited capital spending during 2010 contributed to the decline.




Revenue decreased by 5% for 2010 compared to 2009 due to reduced sales volumes, partially offset by higher realized prices.  Realized prices and revenues are before any hedging gains or losses.  The impact of hedging increased realized natural gas prices by $0.32 per mcf in 2010 and by $0.70 per mcf in 2009.




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 alternative to net earnings (loss) as determined in accordance with Canadian GAAP.  The following provides the calculation of field netback and funds flow netback.




7




Years ended December 31,

2010


2009


2008($/boe)Realized price(1)

$
32.87


$
28.90


$
57.26Processing revenue


1.15



0.94



0.92Realized commodity hedge gain (loss)


1.89



4.22



(0.80
)Royalties


(4.73
)


(3.62
)


(11.43
)Operating expenses


(10.41
)


(11.07
)


(10.75
)Transportation


(1.09
)


(1.02
)


(0.94
)Field netback

$
19.68


$
18.35


$
34.26Administrative


(3.57
)


(3.75
)


(2.96
)Interest


(7.67
)


(7.45
)


(5.81
)Funds flow netback

$
8.44


$
7.15


$
25.49


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




ROYALTIES





Years ended December 31,

2010


2009


2008Crown royalties(1)

$
6,901


$
7,919


$
88,542Overriding royalty(2)


9,274



1,892



-Other royalties


13,867



17,863



31,382Net royalties

$
30,042


$
27,674


$
119,924Percentage of revenues


13.9
%


12.1
%


19.7
%


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


(2)
The overriding royalty came into effect on October 1, 2009




Royalties as a percentage of revenues increased in 2010 compared to 2009.  Crown royalties decreased in 2010 with lower production, despite a reduction in the gas cost allowance of $3.3 million in 2010 relating to the Corporation’s reduced capital expenditure program.  The sale of an overriding royalty right to a third party also was effective in the fourth quarter of 2009.




In March 2010, the Alberta government announced changes to its royalty framework following a competitive review process.  These changes result in a reduction of future royalty rates beginning in January 2011.  These rate reductions are focused on lowering the progressive royalty rates applicable in a higher commodity price environment than that being experienced by the Corporation under current economic conditions.  This change is not anticipated to have a near term impact on the Corporation given its current production profile and the outlook for gas prices remaining in the low range of the gas price cycle.




OPERATING EXPENSES





Years ended December 31,

2010


2009


2008Operating expenses

$
66,134


$
84,554


$
112,723Operating expenses ($/boe)

$
10.41


$
11.07


$
10.75




Operating expenses per boe for 2010 decreased by 6% from 2009, while total operating expenses decreased by 22%.  The decreases were a result of cost savings arising from the cost control initiatives implemented in 2010.




8




TRANSPORTATION





Years ended December 31,

2010


2009


2008Transportation costs

$
6,901


$
7,759


$
9,860Transportation costs ($/boe)

$
1.09


$
1.02


$
0. 94




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.  Compton incurs charges for the transportation of its production from the wellhead to the point of sale.




Transportation expenses per boe increased by 7% in 2010 when compared to 2009.  The increase in transportation costs is attributable to an increase of approximately 25% in pipeline tariffs, and $2.4 million (2009 – $1.6 million; 2008 - $1.5 million) pertaining to reclassified transportation costs from operating expenses for liquids trucking.




ADMINISTRATIVE EXPENSES





Years ended December 31,

2010


2009


2008Gross administrative expenses

$
31,109


$
36,560


$
38,617Capitalized administrative expenses


(4,306
)


(3,295
)


(4,713
)Operator recoveries


(4,101
)


(4,654
)


(2,889
)Administrative expenses

$
22,702


$
28,611


$
31,015Administrative expenses ($/boe)

$
3.57


$
3.75


$
2.96





Administrative expenses per boe decreased 5% in 2010 compared to 2009.  The reductions were achieved primarily as a result of cost control initiatives following the strategic review completed in 2009; however, they were partially offset by reduced production volumes for 2010.





STOCK-BASED COMPENSATION





Years ended December 31,

2010


2009


2008Stock option plan

$
2,647


$
2,921


$
8,826Share appreciation rights plan


-



-



(970
)Employee share purchase plan


1,015



1,226



1,718Stock-based compensation

$
3,662


$
4,147


$
9,574




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 individuals, and to align their success with that of shareholders.  Details relating to stock-based compensation arrangements are presented in Note 11 to the audited consolidated financial statements.




OTHER EXPENSES





Years ended December 31,

2010


2009


2008Terminated office lease costs

$
14,326


$
-


$
-Strategic review costs


-



2,550



35,490Restructuring costs


5,547



2,266



-Total costs

$
19,873


$
4,816


$
35,490Total costs ($/boe)

$
3.13


$
0.63


$
3.38




9




Surplus office lease costs relate to the rent on unused office space and a one-time payment of $11.6 million to return unused office space to the landlord, terminating the Corporation’s obligation under the lease for the space.  The office lease surrender payment reduces the rent obligation in future periods.




A strategic review and restructuring process undertaken by Management was originally completed in 2009.  In 2010, additional costs were incurred relating to a second restructuring process undertaken by the Corporation. The 2010 restructuring is anticipated to be fully settled by the second quarter of 2011.




INTEREST AND FINANCE CHARGES





Years ended December 31,

2010


2009


2008Interest on bank debt, net

$
4,424


$
11,268


$
20,280Interest on senior notes


34,716



41,032



38,228Interest expense


39,140



52,300



58,508Finance charges


9,569



4,586



2,403Total interest and finance charges

$
48,709


$
56,886


$
60,911Total interest and finance charges ($/boe)

$
7.67


$
7.45


$
5.81




Interest expense for 2010 decreased by 25% compared to 2009.  Although interest rates increased in 2010, the overall decrease was as a result of reduced borrowings from the revolving Facility and lower interest related to the US dollar denominated Notes.  The lower interest on the Notes resulted from a strengthening of the Canadian dollar in relation to the US dollar.




Finance charges in 2010 increased by 109% compared to the same period in 2009, as a result of higher fees for the unutilized Facility.




Total interest and finance charges increased on a per boe basis in 2010 due to decreased production volumes despite lower interest expense.




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





Years ended December 31,

2010


2009


2008Senior credit facility

$
92,224


$
249,359


$
325,020Effective interest rate


4.80
%


4.52
%


6.20
%2013 Senior term 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
%2011 Mandatory convertible senior term notes (US$)

$
45,000


$
-


$
-Coupon Rate (US$)


10.000
%


-



-Effective interest rate (Cdn$)


9.946
%


-



-2017 Senior term notes (US$)

$
193,500


$
-


$
-Coupon Rate (US$)


10.000
%


-



-Effective interest rate (Cdn$)


9.946
%


-



-




10




RISK MANAGEMENT





Years ended December 31,

2010


2009


2008Commodity contractsRealized (gain) loss

$
(12,014
)

$
(32,286
)

$
8,367Unrealized (gain) loss


(9,204
)


9,510



(6,493
)Foreign currency contractsRealized (gain) loss


-



2,303



(27,360
)Unrealized (gain) loss


53



-



3,947Total risk management (gain) loss

$
(21,165
)

$
(20,473
)

$
(21,539
)Realized (gain) loss

$
(12,014
)

$
(29,983
)

$
(18,993
)Unrealized (gain) loss


(9,151
)


9,510



(2,546
)Total risk management (gain) loss

$
(21,165
)

$
(20,473
)

$
(21,539
)





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.




The Corporation uses hedges for both natural gas (per giga joules (“GJ”)) and electricity (per megawatt hours (“MWh”)) to stabilize fluctuations in commodity pricing.  Currency hedges are applied to reduce exposure to payments due in foreign currencies.   The Corporation’s outstanding hedging instruments at December 31, 2010 are as follows:




Type
Term
Volume
Average

Price
IndexCommodityNatural gasCollars
July 2009 – June 2011
30,250 GJ/d
$4.52 - $7.02/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
AESOCurrencyUS Dollar Swap
March 15, 2011
$9.8 million
$1.00
N/A




DEPLETION AND DEPRECIATION





Years ended December 31,

2010


2009


2008Total depletion and depreciation(1)

$
135,922


$
134,710


$
157,973Depletion and depreciation ($/boe)

$
21.40


$
17.64


$
15.06


(1)  Excluding the $367.0millionceiling test write-down assessed at December 31, 2010




11




Total depletion and depreciation expense increased during 2010 as compared to 2009.  The impact of reductions in the Corporation’s overall depletable base following the sales of properties and the overriding royalty interest were offset by the increased depletion rate derived from reduced reserve balances.  On a per boe basis, the lower production volumes have increased depletion and depreciation expense by 21% in 2010 over 2009.




FOREIGN EXCHANGE AND OTHER GAINS AND LOSSES





Years ended December 31,

2010


2009


2008Foreign exchange on translation of US$ debt

$
(4,842
)

$
(80,100
)

$
106,425Foreign exchange and settlement gain on extinguishment of US$ debt


(23,299
)


-



-Other foreign exchange


1,117



(2,779
)


(82
)Other (gains) losses


(1,861
)


(1,931
)


7,439Total foreign exchange and other (gains) losses

$
(28,885
)

$
(84,810
)

$
113,782





The foreign exchange gain recognized in the consolidated statements of earnings (loss) resulted primarily from the translation of the US dollar denominated Notes into Canadian dollars.  The 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.  In addition, a $9.0 million settlement gain on extinguishment of the 2013 Notes was recognized following the completion of the Arrangement.




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 $110.2 million was recognized in 2010.  This was primarily the result of the $367.0 million ceiling test write-down included in the net loss for the year ended December 31, 2010.  In addition, reductions in the effective federal corporate tax rates reduced the future income tax liability recorded in prior years.  Partially offsetting this was the settlement gain on extinguishment of the 2013 Senior Term Notes, and the reduction of tax pools under a corporate reorganization of Compton’s wholly owned subsidiaries.




Under current legislation, the statutory federal income tax rate will continue to be reduced by 1.5% annually until 2012.




CORPORATE TAX RATES





Years ended December 31,

2010


2009


2008Statutory rate


28.0
%


29.0
%


29.5
%





A reconciliation of the effective tax rate to the statutory rate may be found in Note 16(a) to the consolidated financial statements.




12




IV.
Liquidity and Capital Resources




CAPITAL STRUCTURE




Compton manages its capital structure based on changes in economic conditions and the Corporation’s planned capital requirements.  Compton has the ability to adjust its capital structure by making modifications to its capital expenditure program, divesting of assets and by altering debt levels or issuing equity.





The Corporation monitors its capital structure and financing requirements using non-GAAP measures consisting of total net debt to capitalization and total net debt to “Adjusted EBITDA”.  Adjusted EBITDA is defined as net earnings (loss) before interest and finance charges, income taxes, depletion and depreciation, accretion of asset retirement obligation, goodwill written-off, unrealized foreign exchange and other gains (losses), unrealized risk management gains (losses) and other non-recurring expenses.





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.  Compton targets a total net debt to total capitalization ratio of between 40% and 50%, and total net debt to Adjusted EBITDA of 2.5 to 3.0 times.





Years ended December 31,

2010


2009Working capital deficit(1)

$
21,185


$
7,294Credit facility(2)


145,584



107,183MPP term financing(3)


45,620



51,408Senior term notes(4)


237,212



461,741Total net debt


449,601



627,626Shareholders’ equity


664,035



992,237Total capitalization

$
1,113,636


$
1,619,863Total net debt to Adjusted EBITDA


3.7
x


5.9
xTotal net debt to total capitalization ratio


40.4
%


38.7
%


(1)
Adjusted working capital excludes risk management, future income taxes, current MPP term financing and Facility


(2)
Includes unamortized transaction costs of $1,692 (2009 – $1,279)


(3)
Includes unamortized financing fees of $520 (2009 – $679)


(4)
Includes unamortized original issue discount and related transaction costs of $nil (2009 – $9,229)




Of total net debt, 53% is comprised of Senior Term Notes, of which $44.8 million matures September 15, 2011, and $192.5 matures on September 15, 2017.   The $26.6 million purchase option component of the MPP term financing matures on April 30, 2014, and represents 10% of total net debt.




WORKING CAPITAL




Compton had a working capital deficiency of $21.2 million at December 31, 2010, as compared to a deficit of $7.3 million as at December 31, 2009.  Typically 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.




SENIOR CREDIT FACILITY




The Corporation’s outstanding bank debt at December 31, 2010 of $147.3 million was drawn on a revolving term facility authorized at $155 million and a revolving working capital facility authorized at $15 million (for a total of $170 million).  The credit facilities were renewed on June 30, 2010 for a period of 366 days until July 1, 2011.  The 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




13




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 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 Facility is secured by a fixed and floating charge debenture on the assets of the Corporation.




The amount that may be drawn on the Facility is limited, in certain circumstances, by a provision contained in the note indenture governing the Notes (the adjusted consolidated net tangible assets (“ACNTA”) test, detailed in “senior term notes and risks – liquidity risk”).  At December 31, 2010, the ACNTA test capped the borrowings under the credit facilities to $278.7 million.




SENIOR TERM NOTES




Notes 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, 2010, the carrying value of the Notes decreased by $224.5 million from December 31, 2009.  The decrease was as a result of the extinguishment of the 2013 Notes completed under the Plan of Arrangement (the “Arrangement”), and the unrealized foreign exchange gain on translation at December 31, 2010.




On October 18, 2010, the Arrangement was completed resulting in the replacement of all the existing US$450.0 million 2013 Notes for a combination of:







(a)
US$193.5 million 10% notes due September 15, 2017 (the “2017 Notes”);


(b)
US$45.0 million 10% notes due September 15, 2011 (the “2011 Mandatory Convertible Notes”); and




(c)
US$184.5 million of cash, in part funded by a draw of $145.0 million from the Facility.




The extinguishment of the 2013 Notes resulted in the recognition of a realized settlement gain of $9.0 million.




The 2011 Mandatory Convertible Notes are redeemable, in whole or in part, prior to maturity at face value.  Redemption is required at maturity, or in the event any share issuance proceeds are received prior to the maturity date. Based on the terms and specified conversion features of the 2011 Mandatory Convertible Notes, no bifurcation to equity has been made.  As a result, the entire value has been presented as a financial liability in the consolidated financial statements.  Management anticipates redemption of the 2011 Mandatory Convertible Notes for cash in 2011 prior to maturity.




The indenture governing the 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, 2010, the Ratio was 2.16 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 $278.7 million under the 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 ”Risk Factors - Liquidity Risk” in Compton’s 2010 AIF filed as exhibit 99.1 to Compton's annual report on Form 40-F for the year ended December 31, 2010).




14




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 $45.6 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 10.55% per annum.  The principal amount of the MPP term financing is equal to the purchase option price of the MPP partnership units at the end of the five-year term, plus the principal portion of monthly base fee payments.




The purchase option represents the pre-determined price at which Compton may, at its discretion, purchase the MPP partnership on April 30, 2014.  If Compton does not exercise this purchase option it may renew the MPP Agreements with terms and conditions to be negotiated at that time, or enter into an arrangement with the owners of the MPP facilities to process natural gas for Compton at a fee to be determined at that time.




The MPP Agreements prescribe minimum throughput volumes and dedicated reserves which, if not exceeded, may require a buy-down of the purchase option.  The minimum throughput volume is an average of the throughput volume of the preceding two consecutive calendar quarters.  The prepayment amount is $400,000 per 1.0 mmcf/d of shortfall.  Each prepayment of the purchase option will cause the minimum throughput volume to be adjusted downward to the average throughput volume of the preceding two consecutive calendar quarters.  In the event that the estimated dedicated reserves, as projected at April 30, 2014, are less than 200 BCF or have a discounted reserve value of less than $250 million using a 10% discount rate, the prepayment amount is the greater of $108,000 per $1 million of reserve value shortfall and $135,000 per 1.0 BCF of the reserves shortfall.




As of December 31, 2010, the threshold throughput volume was reduced to 61.51 mmcf/d.  The cumulative prepayments of the purchase option in 2010 were $1.21 million (2009 – $nil), reducing the amount of the MPP term financing liability.  Subsequent to year end, an additional payment of $1.2 million was made.  Internal estimates indicate that dedicated reserves will not exceed the minimum reserve test threshold at December 31, 2010.  The amount of any resulting prepayment, subject to third party verification, may approximate $4.8 million, which would be due prior to April 30, 2011.




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 consolidated financial statements.  The following table summarizes all contractual obligations, with anticipated payment timing, as at December 31, 2010:




2011


2012


2013


2014


2015


ThereafterCredit facility

$
147,276


$
-


$
-


$
-


$
-


$
-Senior term notes


44,757



-



-



-



-



192,455MPP term financing(1)


15,575



9,592



9,592



23,802



-



-Accounts payable


55,512



-



-



-



-



-Operating leases


719



806



-



-



-



-Office facilities


1,893



1,938



2,001



2,001



2,046



5,449$
265,732


$
12,336


$
11,593


$
25,803


$
2,046


$
197,904


(1)
Represents monthly fixed base fee payments; the 2011 amount includes purchase option prepayments of $6.0 million




Compton intends to renew its Facility; therefore the repayment is not expected to occur, although it has been included in the schedule of commitments consistent with its current term.




15




The 2011 Mandatory Convertible Notes have been reflected above consistent with Management’s target to repay in cash.  If not completed prior to maturity at September 15, 2011, these will convert to equity with no cash impact.




V.        Outlook




The current unfavourable outlook for natural gas in North America is expected to continue into 2011 and constrain the Corporation’s cash flow levels.  As a result, Compton is shifting its focus to concentrate on those areas that provide the highest economic return and to areas that will help identify additional future development opportunities for the Corporation. In 2011, Compton will focus on the liquids-rich, high return Niton area as well as its emerging oil opportunities in Southern Plains, providing significant upside potential through its multiple zone development opportunities and contiguous land blocks. Management’s emphasis is on realizing the underlying value within the existing asset base and act on accretive acquisitions when possible.




In addition, Management will continue its prudent approach to capital investment decisions, as well as its focus on value creation through further capital efficiency improvements. This approach improved Compton’s operating efficiencies and partially offset the impact of lower natural gas prices on cash flows generated by operations over the past two years.




Management will take a flexible approach to its 2011 capital expenditure program that will be adjusted to respond to economic circumstances and opportunities. The following represents Compton’s plans and guidance for 2011:




Average daily production (boe/d)
13,250 - 13,750Administrative expenses ($ millions)
$15.5 - $16.5Operating costs(1) ($ millions)
$47.0 - $50.0Cash flow(2) ($ millions)
$27.0 - $30.0Capital expenditures(3) ($ millions)
$70.0 - $75.02011 Pricing:Natural gas - AECO (Cdn$/GJ)
$3.58Crude oil - Edmonton Sweet (Cdn$/bbl)
$89.43Exchange rate (Cdn$/bbl)
$1.01
 (1)
Net of $11.7 million of gas cost allowance
 (2)
A $0.25 change in the AECO natural gas price is expected to result in a $2.5 million change in cash flow
 (3)
Includes development and corporate capital expenditures; total capital expenditure amount is dependent upon available capital above cash flow


To reduce cash flow volatility, Compton will continue its hedging program with approximately 60% of production being hedged to the middle of 2011, and 30% thereafter. Management is focused on identifying additional hedging opportunities as they appear. Should additional funds become available due to better than projected natural gas prices or reductions in the Corporation’s cost structure, Management will consider allocating funds to further reduce debt or increase capital expenditures as appropriate.




Compton significantly strengthened its capital structure and improved its liquidity over the past two years. Management will continue to evaluate options to further improve its capital structure and reduce overall financial risk in ways that support shareholder value.




Compton’s asset base provides solid growth potential through a focused land position, multi-zone opportunities and positive impact from horizontal multi-stage fracture technology. The Corporation has shown its ability to be a strong operator through its solid improvements in drilling and operations. Compton continues to take a selective approach to its business, identifying and evaluating various opportunities to capture unrealized value for the Corporation and maximize future shareholder benefit.




16




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”).




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(e) of the US Securities and Exchange Act of 1934 as amended (the “Exchange Act”), 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, 2010, under the supervision and with the participation of Management, including the 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 Exchange Act, 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 the board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of the financial reporting and the preparation of the 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 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




17




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, 2010, Compton’s internal control over financial reporting was effective.




The effectiveness of internal control over financial reporting as of December 31, 2010, was audited by Grant Thornton LLP, Chartered Accountants, the independent registered public accounting firm which also audits Compton’s consolidated financial statements.  They have issued their Independent Auditors’ Report which is included in this document following the MD&A.




INTERNAL AUDIT FUNCTION




Reporting directly to the Audit Finance and Risk committee, the Manager of Internal Audit is responsible for oversight of the Corporation’s control environment and provides quarterly updates regarding the degree of compliance and any changes in the internal controls over financial reporting.




CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING




There were no changes to internal control over financial reporting during the period beginning on January 1, 2010 and ending on December 31, 2010 that materially affected or are reasonably likely to materially affect Compton’s internal control over financial reporting.




VII.        Risks




The following discussion highlights key risks facing Compton in its normal course of business, which  could negatively impact Compton’s business, financial condition, results of operations, cash flows and prospects.




Business Risks




Compton’s exploration and production activities are concentrated in the Western Canadian Sedimentary Basin, where activity is highly competitive and includes a variety of different sized companies ranging from smaller junior producers, intermediate and senior producers, to much larger integrated petroleum companies. Compton is subject to a number of risks that are also common to other organizations involved in the oil and gas industry. Such risks include: finding and developing oil and gas reserves at economic costs; estimating amounts of recoverable reserves; production of oil and gas in commercial quantities; marketability of oil and gas produced; fluctuations in commodity prices; financial and liquidity risks; and environmental and safety risks.




In order to reduce exploration risk, Compton employs highly qualified and motivated professionals who have demonstrated the ability to generate high-quality proprietary geological and geophysical prospects. To maximize drilling success, Compton explores in areas that afford multi-zone prospect potential, targeting a range of shallower low to moderate risk prospects with some exposure to select deeper high-risk prospects that offer high-reward opportunities.




Compton engages an independent engineering consulting firm that assists the Corporation in evaluating recoverable amounts of oil and gas reserves. Values of recoverable reserves are based on a number of variable factors and assumptions such as commodity prices, projected production, future production costs and government regulation. Such estimates may vary from actual results.




The Corporation mitigates its risk related to producing hydrocarbons through the utilization of advanced technology and information systems. In addition, Compton operates the majority of its prospects, thereby maintaining operational control. The Corporation does rely on its partners in jointly owned properties that Compton does not operate.




18




Compton is exposed to market risk to the extent that the demand for oil and gas produced by the Corporation exists within Canada and the United States. External factors beyond the Corporation’s control may affect the marketability of oil and gas. These factors include commodity prices and variations in the Canada-United States currency exchange rate, which in turn respond to economic and political circumstances throughout the world. Oil prices are affected by worldwide supply and demand fundamentals while natural gas prices are affected by North American supply and demand fundamentals. Compton may periodically use futures and options contracts to hedge its exposure against the potential adverse impact of commodity price volatility.




Exploration and production for oil and gas is very capital intensive. As a result, the Corporation relies on debt and equity markets as a source of capital. In addition, Compton utilizes bank financing to support on-going capital investment. Funds from operations also provide Compton with capital required to grow its business. Equity and debt capital is subject to market conditions and availability may increase or decrease from time to time. Funds from operations also fluctuate with changing commodity prices.




Safety and Environment




Oil and gas exploration and production can involve environmental risks such as pollution of the environment and destruction of natural habitat, as well as safety risks such as personal injury. The Corporation conducts its operations with high standards in order to protect the environment, employees and the general public. Compton maintains current insurance coverage for comprehensive and general liability as well as limited pollution liability. The amount and terms of this insurance are reviewed on an ongoing basis and adjusted as necessary to reflect current corporate requirements, as well as industry standards and government regulations.




Additional Risk Factors




For a more detailed discussion of the business risk factors affecting the Corporation refer to Compton’s Annual Information Form for the year ended December 31, 2010, 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 GLJ Petroleum Consultants Ltd. evaluated and reported on 100% of Compton’s oil and natural gas reserves as at December 31, 2010.  The firm of Netherland, Sewell and Associates Inc. evaluated oil and gas reserves for comparable periods prior to 2010.




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 (loss).




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




19




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 2010, Compton incurred $135.9 million of depletion and depreciation expense (excluding ceiling test impairment of $367.0 million recognized December 31, 2010).  If proved reserves were to increase by 5%, depletion and depreciation expense would decrease by $1.8 million and consolidated net earnings after tax would increase by $1.3 million.  If proved reserves were to decrease by 5%, depletion and depreciation expense would increase by $1.9 million and consolidated net earnings (loss) after tax would decrease by $1.4 million.




FULL COST ACCOUNTING AND CEILING TEST WRITE-DOWN




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.




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.  A write down 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.




If a write-down is found to exist, the identified 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.  A write down may result in a material loss for a particular period; however, future depletion and depreciation expense would be reduced as a result.  As at December 31, 2010, the ceiling amount calculated was $367.0 million less than the carrying value of the costs capitalized.  As a result, the carrying value of the costs capitalized was written down by $367.0 million, using a 3.75% risk free discount rate.  At December 31, 2009, the ceiling amount was $1.2 billion in excess of the carrying value of capitalized costs.




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 in the event of a write down.  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.




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




20




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.




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, 2010.  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 (loss).  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.




At December 31, 2010, the Corporation revised its estimated liability for asset retirement obligations.  The revision was made based on current abandonment and reclamation cost information in the Corporation’s specific areas of operation.  The revision of estimate increased the discounted asset retirement obligation by $21.0 million.




A summary of the significant accounting policies used by Compton can be found in Note 2 of the 2010 consolidated financial statements.




IX.        Forthcoming and Newly Adopted Accounting Policies




INTERNATIONAL FINANCIAL REPORTING STANDARDS




Accounting standards in Canada are to converge with International Financial Reporting Standards (“IFRS”) and companies will begin reporting, with comparative data, under IFRS for fiscal years beginning on or after January 1, 2011.  While IFRS is based on a conceptual framework similar to Canadian GAAP, there are significant differences with respect to recognition, measurement and disclosure.




The implementation of IFRS will apply to the Corporation’s interim and annual financial statements for the fiscal year beginning January 1, 2011, including the restatement of comparative amounts for 2010.  The Corporation’s IFRS project team has been meeting regularly with senior management and the Audit Committee to communicate progress, key accounting policy selections and transitional impacts.




The adoption of IFRS will result in changes; however these changes will not impact Compton’s operations or its cash flows.  The most significant impacts will be from the application of new accounting policies that will restate the Corporation’s balance sheet and financial statement presentation format.  The Corporation




21




continues work to finalize the adjustments required to restate its transitional balance sheet at January 1, 2010.




The general principle applied on the adoption of IFRS is that at the time of transition, accounting standards in effect should be applied retrospectively.  However, under the guidance of IFRS 1 – “First Time Adoption of IFRS”, the Corporation has elected to apply available exemptions in respect of the following:




·
To not restate past business combinations that occurred prior to January 1, 2010;




·
To allocate petroleum and natural gas assets, previously included in the full cost accounting pool, to identified cash generating units at January 1, 2010 on the basis of discounted cash flows for reserves;




·
To adjust through equity at January 1, 2010 the application of a risk free rate in determining the Corporation’s discounted asset retirement obligations;




·
To not apply IFRS 2 – “Share-based Payments” to awards that vested prior to January 1, 2010;




·
To prospectively apply IAS 23 – “Borrowing Costs” at January 1, 2010; and




·
To recognize the cumulative unrecognized actuarial gains and losses on its defined benefit pension plan in equity at January 1, 2010.




Impact on Transitional Balance Sheet




The following represents a summary of key changes to the balance sheet accounts on transition to IFRS at January 1, 2010:




(millions)



Canadian GAAP

IFRS Adjustments

IFRSCurrent Assets

A

52

-

52Long Term Assets

B

1,945

(250) to (275)

1,670 to 1,695Total Assets



1,997

(250) to (275)

1,722 to 1,747Current Liabilities

C

171

15 to 25

186 to 196Long Term Liabilities

D

834

(15) to (25)

819 to 809Equity

E

992

(250) to (275)

717 to 742Total Liabilities & Equity



1,997

(250) to (275)

1,722 to 1,747




A.  Current Assets




No significant impact on transition.




B.  Long Term Assets




Petroleum and natural gas assets, following allocation of the full cost pool to cash generating units (“CGU”), will have valuation adjustments to historical costs.  The valuation adjustment reflects an excess of allocated costs when compared to the discounted cash flows of each CGU, on a proved plus probable (“2P”) basis.  The adjustment in value is to be charged to equity on transition.




Exploration and evaluation costs recognized under IFRS, including undeveloped land and exploratory wells, have been recognized on transition.




22




C.  Current Liabilities




Recognition of the estimated liability associated with terminated office lease costs, settled in June 2010, under IAS 37 – Provisions, Contingent Liabilities and Contingent Assets.  The provision is to be charged to equity on transition.




D.  Long Term Liabilities




For purposes of this disclosure non-controlling interest has been presented as a long term liability; the amount is to be reclassified to Equity upon transition to IFRS.




Asset retirement obligations have increased following the application of a risk free rate to the discount of estimated liability obligations.  Previously a credit risk adjusted discount rate of 10.5% had been applied.  The revision of estimate is to be charged to equity on transition.




Future income tax liability is reduced in relation to balance sheet adjustments under the transition to IFRS.  These have been adjusted under an estimated 25% rate.  The estimate is to be offset against equity on transition.




E.  Equity




In addition to the above noted entries, retained earnings will decrease following adjustments for the revaluation and recognition of the Corporation’s stock option expense, and defined benefit pension plan components.




Impact on Reported Financial Results




After giving effect to the adjustments outlined above the Corporation’s opening IFRS balance sheet at January 1, 2010, Management anticipates the following significant changes to its previously reported financial results: a reduction of depletion expense as a result of the cost adjustment to petroleum and natural gas assets; and increased share based compensation expense due to the valuation methodology of its stock option program.




Management’s selection of accounting policies under IFRS have been made, where possible, to minimize the impact on its internal control and financial reporting processes.




The areas impacted by IFRS and discussed above should not be considered a comprehensive list of changes on transition to IFRS.  The Corporation continues to work with its internal project team, and external financial advisors to finalize the impact of transition.




CHANGES IN ACCOUNTING POLICIES




With the exception of the transition to IFRS, there was no new accounting pronouncements issued under Canadian GAAP during 2010 affecting the Corporation.




23




X.        Quarterly Information




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




2010


2009($millions, except where noted)


Q4



Q3



Q2



Q1



Q4



Q3



Q2



Q1Total revenue(1)

$
45


$
43


$
57


$
71


$
58


$
47


$
54


$
69Cash flow(1)

$
7


$
3


$
11


$
22


$
8


$
8


$
12


$
22Per share-basic

$
0.03


$
0.01


$
0.04


$
0.08


$
0.03


$
0.06


$
0.09


$
0.18-diluted

$
0.03


$
0.01


$
0.04


$
0.08


$
0.03


$
0.06


$
0.09


$
0.18Net earnings (loss)

$
(291
)

$
(5
)

$
(52
)

$
17


$
(24
)

$
13


$
20


$
(17
)Per share-basic

$
(1.10
)

$
(0.02
)

$
(0.20
)

$
0.06


$
(0.09
)

$
0.10


$
0.16


$
(0.14
)-diluted

$
(1.10
)

$
(0.02
)

$
(0.20
)

$
0.06


$
(0.09
)

$
0.10


$
0.16


$
(0.14
)Operating earnings(1)

$
(29
)

$
(20
)

$
(21
)

$
(5
)

$
(25
)

$
(17
)

$
(16
)

$
(3
)ProductionNatural gas (mmcf/d)


75



81



98



97



98



99



108



117Liquids (bbls/d)


2,411



2,452



3,076



3,237



3,055



3,208



3,428



3,655Total (boe/d)


14,852



15,931



19,481



19,411



19,351



19,760



21,440



23,194Average priceNatural gas ($/mcf)

$
3.87


$
3.84


$
4.15


$
5.67


$
4.38


$
3.14


$
3.80


$
5.18Liquids ($/bbl)

$
69.30


$
59.39


$
66.00


$
67.59


$
57.10


$
55.42


$
49.94


$
38.35Total ($/boe)

$
30.70


$
28.61


$
31.41


$
39.62


$
31.16


$
24.78


$
27.15


$
32.20




(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.  Depressed natural gas prices and lower production volumes due to asset sales and natural declines contributed to decreased revenues since the beginning of 2009.  The Corporation’s production base stabilized to a consistent level in the final quarter of 2010, following asset sales during the second and third quarters.




Increases in the US dollar against the Canadian dollar had the effect of decreasing net earnings during the first quarter of 2009 and conversely increased net earnings throughout 2010, particularly in the fourth quarter.  Cash flow for the first quarter of 2010 increased as a result of higher realized prices and cost control initiatives following the restructuring process.  However, this was more than offset by one-time costs relating to the surrender of surplus leased office space in the second quarter.  For the third quarter of 2010, cash flow decreased due to lower realized risk management gains.




XI.        Selected Annual Information





Years ended and as at December 31,

2010


2009


2008Total revenue

$
216,069


$
227,876


$
610,298Net earnings (loss)

$
(330,854
)

$
(8,330
)

$
(43,003
)Per share:   basic

$
(1.26
)

$
(0.05
)

$
(0.33
)diluted

$
(1.26
)

$
(0.05
)

$
(0.33
)Total assets(1)

$
1,382,514


$
1,996,761


$
2,188,583Total financial liabilities(2)

$
382,796


$
568,924


$
829,321


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


(2)
Includes Notes and Facility




Total revenue in 2010 was 5% lower than in 2009 due to an overall reduction in production volumes from the sale of non-core asset and royalty interests following the strategic review process in 2009.  The 2010 net loss includes a $367.0 million ceiling test impairment relating to its petroleum and natural gas assets.




24




XII.        Trading and Share Statistics





As at February 24, 2011 there are 263,579,701 common shares, 12,673,003 options, and 138,000,000 share purchase warrants outstanding.





2010
2009
2008TSX

($Cdn)
NYSE(1)

($US)
TSX

($Cdn)
NYSE

($US)
TSX

($Cdn)
NYSE

($US)Average daily trading volume
775,996
1,704,674
1,187,853
867,206
525,474
332,354Share price ($/share)High
$1.11
$1.16
$2.03
$1.75
$13.20
$12.94Low
$0.39
$0.64
$0.56
$0.44
$0.88
$0.68Close
$0.44
$0.65
$0.94
$0.92
$0.93
$0.80Market capitalization at December 31, ($000s)
Cdn $115,975
Cdn $247,759
Cdn $116,957Shares outstanding (000s)
263,579
263,573
125,760


(1)
Effective Friday, June 25, 2010, Compton’s common shares discontinued trading on the NYSE.




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.




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




25




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 on the Canadian Securities Administrators’ SEDAR website at www.sedar.com, the EDGAR section of the U.S. Securities and Exchange Commission website at www.sec.gov, on the Corporation’s website at www.comptonpetroleum.com, or on request by sending an email to investorinfo@comptonpetroleum.com.





26