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
in conjunction with the consolidated financial statements and related notes for the year ended December 31, 2011 as well as the
audited consolidated financial statements and MD&A for the year ended December 31, 2010. Readers should also read the “Forward-Looking
Statements” legal advisory contained at the end of this document.



The audited consolidated financial statements
and comparative information have been prepared in accordance with International Financial Reporting Standard (“IFRS”)
1, “First-time Adoption of International Financial Reporting Standards”. Previously, the Corporation prepared its audited
annual consolidated financial statements in accordance with Canadian Generally Accepted Accounting Principles (“Previous
GAAP”).



This document contains non-GAAP Financial Measures
that do not have any standardized meaning as prescribed under IFRS or Previous GAAP; see “Advisories” for definitions.



Further information regarding Compton, including
the Annual Information Form for the year ended December 31, 2011 can be accessed under the Corporation’s public filings at
www.sedar.com, EDGAR at www.sec.gov, and on the Corporation’s website at www.comptonpetroleum.com.



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 March
7, 2012.



| | I. | COMPTON’SBUSINESS
| | -- | -----------------



Compton 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 majority
of the Corporation’s operations are located in the Deep Basin fairway of the Western Canada Sedimentary Basin, providing
multi-zone potential for future development and exploration opportunity.



Compton’s production focus has been on
developing its high-return, liquids-rich natural gas areas of the Rock Creek Formation at its Niton property and exploring the
crude oil potential of the property’s Wilrich and Notikewin Formations.



Compton’s emerging oil plays target the
Bakken/Big Valley, Ellerslie and Glauconite Formations in the Southern Plains area as well as future exploratory potential through
the joint venture on its Montana Bakken/Big Valley lands. The successful development of these areas is expected to provide growth
in oil production and reserves, further augmenting the Corporation’s large natural gas reserves that can be capitalized on
when natural gas prices recover.



Compton will create value by providing appropriate
investment returns for shareholders through further improving operating efficiencies, maximizing returns on capital invested and
focusing on higher return assets.



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 1







| | II. | RESULTS FROM CORPORATE STRATEGY
| | --- | -------------------------------



Management’s strategy throughout 2011
has been to strengthen its capital structure and improve operating efficiencies to better position the Corporation within a low natural
gas price environment. Results for 2011 include:



| | · | Achieved average daily production of 13,347 boe/d;
| | - | --------------------------------------------------



| | · | Reduced costs by a combined $27.9 million or 38% from 2010:
| | - | -----------------------------------------------------------



| | o | Administrative costs decreased by 32% or $7.3 million; and
| | - | ----------------------------------------------------------



| | o | Interest and finance charges decreased by 41% or $20.6 million;
| | - | ---------------------------------------------------------------



| | · | Achieved  100% success on the 13 wells drilled or participated in during 2011;
| | - | ------------------------------------------------------------------------------



| | · | Achieved continued drilling success in the Rock Creek Formation at the Niton property:
| | - | --------------------------------------------------------------------------------------



| | o | Average production rates of wells drilled continued to improve during 2011 with the most recent
well drilled achieving an initial test production rate of 4.0 mmcf/d of liquids-rich natural gas; and
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | o | A second well had initial production rates of 1.4 mmcf/d of gas plus 250 to 300 bbls/d of oil.
The well is currently producing at approximately 800 mcf/d of gas plus 65 bbls/d of oil;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | Advanced exploration of other prospective up-hole zones at Niton to further evaluate the area’s
potential:
| | - | ----------------------------------------------------------------------------------------------------------



| | o | During the third quarter of 2011, a non-operated Wilrich horizontal well was tied-in and is
currently on production at approximately 2.9 mmcf/d and 20 bbl/mmcf of liquids; and
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | o | Drilled two additional wells late in 2011 to define the potential of the Notikewin and Wilrich
Formations, respectively, in the Niton area. These wells are currently awaiting completion, however, initial results are encouraging;
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | Initiated development of emerging oil prospects in the Southern Plains’ Ellerslie, Mannville
and Big Valley Formations;
| | - | -----------------------------------------------------------------------------------------------------------------------



| | o | An Ellerslie well was drilled in the first quarter to evaluate oil potential. The well
                                                                                                                              currently produces approximately 500 mcf/d of natural gas and 30 bbls/d of oil. Future optimization of completion methods
                                                                                                                              is expected to yield improved production levels;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | o | Drilled two vertical oil wells late in 2011: one in the Basal Quartz and the second in the
                                                                                                                              Ellerslie Formation. These wells are expected to be put on production late in the first and second quarters of 2012, respectively;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 2







| | · | Completed the acquisition of 25 net sections of land in the Southern Plains area, prospective for
the Big Valley/Bakken oil Formation;
| | - | --------------------------------------------------------------------------------------------------------------------------------------



| | o | Compton now has a total of 49 net sections of land in the area and has secured all the
                                                                                                                              prospective land holdings for developing the new play. Assuming initial success of exploratory drilling, the play has the potential
                                                                                                                              to expand
                                                                                                                              into
                                                                                                                              approximately 90 well locations;
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | Completed minor asset sales totalling $26.2 million from holdings in the Niton and Centron properties;
| | - | ------------------------------------------------------------------------------------------------------



| | · | Completed a farmout and joint venture agreement on the Montana Bakken property. The joint venture
partner has committed to complete a work program at a minimum cost of $2.0 million on or before July 31, 2012, and the drilling
of a test well on or before December 31, 2012; and
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------





| | · | Completed the Recapitalization plan of arrangement
(the “Recapitalization”), reducing the Corporation’s net debt by 64% to $161.0 million from December 31,
2010 (net debt includes MPP Term Financing; see Section IV “Liquidity and Capital Resources – Capital Structure”).
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------





| | III. | RESULTS OF OPERATIONS
| | ---- | ---------------------



|                           |  | 2011 |         |   | 2010 |  
|-------------------------- |  | ---- | ------- | - | ---- | -
|                           |  |      |         |   |      |  
|Average Production (boe/d) |  |      | 13,347  |   |      |  
|                           |  |      |         |   |      |  
|Capital Investment2,3      |  | $    | 50,469  |   |      | $
|                           |  |      |         |   |      |  
|Cash Flow 1,2              |  | $    | 42,497  |   |      | $
|Per share -  basic         |  | $    | 4.42    |   |      | $
|-  diluted                 |  | $    | 3.22    |   |      | $
|                           |  |      |         |   |      |  
|Operating loss1,2          |  | $    | (3,444  | ) |      | $
|                           |  |      |         |   |      |  
|Net earnings (loss)        |  | $    | 17,279  |   |      | $
|Per share -  basic         |  | $    | 1.80    |   |      | $
|-  diluted                 |  | $    | 1.47    |   |      | $
|                           |  |      |         |   |      |  
|Revenue                    |  | $    | 141,996 |   |      | $
|                           |  |      |         |   |      |  
|Field netback (per boe)1,2 |  | $    | 18.79   |   |      | $



| | (1) | Cash flow, operating 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) | Total shares outstanding changed from 263.6 million to 26.4 million on August 10, 2011 in accordance with the Recapitalization
| | --- | ------------------------------------------------------------------------------------------------------------------------------



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 3







CASH
FLOW



Cash flow is considered a non-GAAP measure;
it is commonly used in the oil and gas industry and is used 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, nor more meaningful
than, cash provided by operating, investing and financing activities or net earnings (loss) as determined in accordance with IFRS,
in assessing the Corporation’s performance or liquidity. The following schedule sets out the reconciliation of cash flow
from operations to cash flow.



|                                               |  | 2011 |        |   | 2010 |  
|---------------------------------------------- |  | ---- | ------ | - | ---- | -
|                                               |  |      |        |   |      |  
|Cash flow from operating activities            |  | $    | 36,381 |   |      | $
|Add:  Strategic review and restructuring costs |  |      | -      |   |      |  
|Less:  change in non-cash working capital      |  |      | (6,116 | ) |      |  
|Cash flow                                      |  | $    | 42,497 |   |      | $



Cash flow for the year ended December 31, 2011
was $42.5 million, a decrease of approximately $4.2 million compared to 2010. The decrease in cash flow during the year was a result
of:



| | · | lower average realized natural gas prices, excluding financial hedges, which decreased 12% to $3.92
per mcf compared to $4.43 per mcf in 2010;
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------



| | · | a 24% decline in natural gas production volumes to 67 mmcf/d from 88 mmcf/d in 2010, resulting
from the impact of asset sales, normal production declines, and a reduced level of capital expenditures; and
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | a 22% decline in liquids production volumes to 2,191 bbls/d from 2,791 bbls/d in 2010, resulting
from the impact of asset sales, normal production declines, and a reduced level of capital expenditures.
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



These factors were partially offset by:



| | · | higher average realized liquids prices, which increased 22% to $80.39 per bbl compared to $65.71
per bbl in 2010;
| | - | -----------------------------------------------------------------------------------------------------------------



| | · | a decline in interest and finance charges of $20.6 million as a result of reduced debt levels compared
to 2010, including the impact of the extinguishment of Senior Term Notes and lower interest rates under the renewed credit facility;
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | a decline in administrative costs of $7.3 million in 2011, resulting from a continued corporate
focus on cost reduction;
| | - | ------------------------------------------------------------------------------------------------------------------------



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 4







| | · | a decline in transportation and operating costs of $6.4 million resulting from reduced production
volumes and ongoing efforts to reduce costs; and
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------



| | · | realized risk management gains of $13.6 million compared to $12.0 million in 2010.
| | - | ----------------------------------------------------------------------------------



Cash flow for the three months ended December
31, 2011 was $12.4 million, a decrease of approximately $2.5 million compared to 2010. The decrease in cash flow during the fourth
quarter was a result of:



| | · | lower average realized natural gas prices, excluding financial hedges, which decreased 8% to $3.53
per mcf compared to $3.87 per mcf in 2010;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------



| | · | a 15% decline in natural gas production volumes to 64 mmcf/d from 75 mmcf/d in 2010, resulting
from the impact of asset sales, normal production declines, and a reduced level of capital expenditures; and
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | a 9% decline in liquids production volumes to 2,126 bbls/d from 2,411 bbls/d in 2010, resulting
from the impact of asset sales, normal production declines, and a reduced level of capital expenditures.
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



These factors were partially offset by:



| | · | higher average realized liquids prices, which increased 29% to $88.31 per bbl compared to $69.30
per bbl in 2010;
| | - | -----------------------------------------------------------------------------------------------------------------



| | · | a decline in interest and finance charges of $6.7 million as a result of reduced debt levels compared
to 2010, including the impact of the extinguishment of Senior Term Notes and lower interest rates under the renewed credit facility;
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | a decline in administrative costs of $1.8 million in 2011, resulting from a continued focus on
cost reduction; and
| | - | ------------------------------------------------------------------------------------------------------------------



| | · | a decline in transportation and operating costs of $1.5 million, resulting from reduced production
volumes and ongoing efforts to reduce costs.
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------



NET
EARNINGS (LOSS)



Net earnings for the year ended 2011 was $17.3
million, an improvement of $554.9 million when compared to the $537.6 million net loss in the same period for 2010. In addition
to the factors that impacted cash flow, 2011 net earnings were affected by:



| | · | an impairment expense of $1.6 million compared to $695.4 million in 2010;
| | - | -------------------------------------------------------------------------



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 5







| | · | a net gain on the extinguishment of the Senior Term Notes of $55.2 million;
| | - | ---------------------------------------------------------------------------



| | · | lower depletion and depreciation expense of $58.1 million compared to $89.4 million in 2010; and
| | - | ------------------------------------------------------------------------------------------------



| | · | a non-cash share based compensation recovery of $1.2 million in 2011 arising from the surrender
of all outstanding stock options in conjunction with the Recapitalization, compared to an expense of $3.1 million in 2010 as a
result of the 2010 recapitalization.
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



These factors were partially offset by:



| | · | an increase in exploration and evaluation expense to $21.0 million compared to $2.1 million in
2010, relating to costs associated with exploratory wells drilled prior to 2010 determined to be uneconomic, and the expiry of
undeveloped lands;
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | a deferred tax expense of $10.1 million, compared to a recovery of $179.3 million in 2010, associated
with impairments recognized on development and production assets in 2010;
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | a decline in unrealized foreign exchange and other gains of $19.4 million from 2010, further to
the strengthening of the Canadian dollar year over year and the reduction of outstanding Senior Term Notes; and
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | an unrealized risk management loss of $4.4 million compared to a gain of $9.2 million in 2010,
following the expiry of several hedging positions in 2011.
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------



Net loss for the three months ended December
31, 2011 was $6.8 million, an improvement of $433.2 million when compared to the $440.0 million net loss in the same period for
2010. In addition to the factors that impacted cash flow, fourth quarter net loss was affected by:



| | · | an impairment expense of $2.0 million compared to $577.7 million in 2010;
| | - | -------------------------------------------------------------------------



| | · | lower depletion and depreciation expense of $13.8 million compared to $26.0 million in 2010;
| | - | --------------------------------------------------------------------------------------------



| | · | an unrealized risk management loss of $1.5 million compared to $6.2 million in 2010, following
the expiry of several hedging positions; and
| | - | -------------------------------------------------------------------------------------------------------------------------------------------



| | · | the elimination of exploration and evaluation expense in 2011 compared to $1.4 million in 2010,
relating to costs associated with exploratory wells drilled prior to 2010 determined to be uneconomic, and the expiry of undeveloped
lands.
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



These factors were partially offset by:



| | · | deferred tax recovery of $145.0 million in 2010,
associated with impairments recognized on development and production assets in 2010; and
| | - | -----------------------------------------------------------------------------------------------------------------------------------------



| | · | a decline in unrealized foreign exchange and other gains of $13.5 million from 2010, further to
the strengthening of the Canadian dollar year over year and the elimination of outstanding Senior Term Notes.
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 6







OPERATING
EARNINGS (LOSS)



Operating earnings 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
should not be considered to be more meaningful than nor an alternative to net earnings as determined in accordance with IFRS. The
following provides the calculation of operating earnings (loss) for 2011 and 2010.



|                                                     |  | 2011 |         |   | 2010 |  
|---------------------------------------------------- |  | ---- | ------- | - | ---- | -
|                                                     |  |      |         |   |      |  
|Net earnings (loss), as reported                     |  | $    | 17,279  |   |      | $
|Non-operation items                                  |  |      |         |   |      |  
|Unrealized foreign exchange and other (gains) losses |  |      | (9      | ) |      |  
|Unrealized mark to market hedging (gains) losses     |  |      | 4,435   |   |      |  
|Exploratory land expiries                            |  |      | 20,975  |   |      |  
|Impairment expense (reversals)                       |  |      | 1,580   |   |      |  
|Gain on Senior Term Notes extinguishment             |  |      | (55,175 | ) |      |  
|Other expenses                                       |  |      | -       |   |      |  
|Tax effect                                           |  |      | 7,471   |   |      |  
|Operating earnings (loss) 1                          |  | $    | (3,444  | ) |      | $
|basic2                                               |  | $    | (0.36   | ) |      | $
|diluted2                                             |  | $    | (0.36   | ) |      | $



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



| | (2) | Total shares outstanding changed from 263.6 million to 26.4 million on August 10, 2011 in accordance
with the Recapitalization
| | --- | ------------------------------------------------------------------------------------------------------------------------------



CAPITAL
EXPENDITURES



|                                    |  | 2011 |         |   | 2010 |  
|----------------------------------- |  | ---- | ------- | - | ---- | -
|                                    |  |      |         |   |      |  
|Exploration & evaluation            |  |      |         |   |      |  
|Land                                |  | $    | 5,619   |   |      | $
|Drilling and completions            |  |      | 1,905   |   |      |  
|                                    |  |      |         |   |      |  
|Development & production            |  |      |         |   |      |  
|Drilling and completions            |  |      | 29,344  |   |      |  
|Alberta Drilling Credits            |  |      | -       |   |      |  
|Production facilities and equipment |  |      | 13,254  |   |      |  
|Corporate and other                 |  |      | 347     |   |      |  
|Total capital investment            |  |      | 50,469  |   |      |  
|                                    |  |      |         |   |      |  
|Divestitures                        |  |      |         |   |      |  
|Property                            |  |      | (8,005  | ) |      |  
|Production facilities and equipment |  |      | (405    | ) |      |  
|Overriding royalty                  |  |      | -       |   |      |  
|Land                                |  |      | (2,311  | ) |      |  
|Divestitures                        |  |      | (10,721 | ) |      |  
|                                    |  |      |         |   |      |  
|Total capital expenditures          |  | $    | 39,748  |   |      | $



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 7







Capital spending, before acquisitions and divestments,
decreased by 17% in the year ended December 31, 2011. In order to maximize return on capital in 2011, Management focused its expenditures
towards higher return, liquids-rich natural gas at Niton and emerging oil properties in Southern Plains. During 2011, Compton participated
in 13 wells (10.4 net wells), as compared to a total of 31 wells (20.1 net wells) during 2010.



At Niton, Compton drilled and tied in two Rock
Creek wells during the first quarter of 2011, realizing first month average production rates of 932 Mcf/d with 185 bbl/d of liquids
and 3.2 mmcf/d and 87 bbls/d of liquids. Another Rock Creek horizontal well initially tested at 2.3 mmcf/d and 150 bbl/d of liquids.
Two Rock Creek horizontal wells were drilled late in the fourth quarter and were completed in early 2012. One achieved on initial
production rate of between 3.0 to 3.3 mmcf/d of gas plus 125 to 150 bbls/d of NGLs. The well is currently shut in awaiting facilities
upgrade. The second well had initial production rates of 1.4 mmcf/d of gas plus 250 to 300 bbls/d of oil. The well is currently
producing at approximately 800 mcf/d of gas plus 65 bbls/d of oil.



In 2011, the Corporation continued to
explore other prospective zones in the Niton area to further evaluate the area’s potential. In 2011, several Wilrich
Formation wells were drilled or participated in with encouraging results, reinforcing Compton’s decision to pursue this
play. During the third quarter of 2011, Compton participated in a non-operated Wilrich horizontal well. Located in the centre
of the Corporation’s core lands, the well was tied-in and had initial test rates of approximately 2.9 mmcf/d and 20
bbl/mmcf of liquids. In December 2011, two additional wells were drilled to define the potential of the Notikewin and
Wilrich Formations in the Niton area. The Wilrich well achieved an initial test production rate of 3.4 mmcf/d of natural gas
plus 60 bbls/d of oil and is currently on production. The Notikewin well had initial test production rates of 2.2 mmcf/d of
natural gas plus 1.9 bbls/d of NGLs. The well is awaiting completion.



In the Southern Plains,
further development of the Ellerslie, Mannville and Big Valley Formations began in 2011, which provides significant upside
potential for the Corporation. During the first quarter, an Ellerslie well was drilled in the Southern Plains area to
evaluate oil potential. The well currently produces approximately 500 mcf/d of natural gas and 30 bbl/d of oil. Future optimization of completion methods is expected to yield
improved production levels.



Late in 2011, the Corporation drilled
two vertical oil wells in the Southern Plains area, one in the Basal Quartz and a second in the Ellerslie Formation. These
wells are expected to be put on production late in the first and second quarters of 2012, respectively. A second horizontal Ellerslie oil
well is currently drilling, with results expected later in the first quarter of 2012. Compton also began to pursue the
development of its 24 net prospective sections of Alberta Bakken oil prospects, targeting the Big Valley Formation. In 2011,
the Corporation completed the acquisition of 25 sections of land in the Southern Plains area, prospective for the
Big Valley/Bakken Formation. Compton has secured all prospective land holdings for developing the new play, which has
the potential to expand into approximately 90 locations.



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 8







During the year, the Corporation announced the
signing of a farmout and joint venture agreement related its 79,000 net acres of undeveloped land holdings in northern Montana.
The farmout joint venture grants the joint venture partner the ability to earn a 50% interest in this area by undertaking an exploration
and development work program at 100% cost. The joint venture partner has committed to completion of a minimum $2.0 million work
program on or before July 31, 2012 and the drilling of a test well targeting the Bakken Formation on or before December 31, 2012.



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 2011 free cash
flow deficit of $8.0 million has improved compared to the deficit of $14.2 million in 2010.



|                                |  | 2011 |         |   | 2010 |  
|------------------------------- |  | ---- | ------- | - | ---- | -
|                                |  |      |         |   |      |  
|Cash flow                       |  | $    | 42,497  |   |      | $
|Less:  capital investment       |  |      | 50,469  |   |      |  
|Free cash flow                  |  | $    | (7,972  | ) |      | $
|                                |  |      |         |   |      |  
|Production volumes and revenues |  |      |         |   |      |  
|Average production              |  |      |         |   |      |  
|Natural gas (mmcf/d)            |  |      | 67      |   |      |  
|Liquids (bbls/d)                |  |      | 2,191   |   |      |  
|Total (boe/d)                   |  |      | 13,347  |   |      |  
|                                |  |      |         |   |      |  
|Benchmark prices                |  |      |         |   |      |  
|AECO ($/GJ)                     |  |      |         |   |      |  
|Monthly index                   |  | $    | 3.48    |   |      | $
|Daily index                     |  | $    | 3.43    |   |      | $
|WTI (US$/bbl)                   |  | $    | 95.10   |   |      | $
|Edmonton sweet light ($/bbl)    |  | $    | 95.07   |   |      | $
|                                |  |      |         |   |      |  
|Realized prices                 |  |      |         |   |      |  
|Natural gas ($/mcf)             |  | $    | 3.92    |   |      | $
|Liquids ($/bbl)                 |  | $    | 80.39   |   |      | $
|Total ($/boe)                   |  | $    | 32.84   |   |      | $
|                                |  |      |         |   |      |  
|Sales Revenue1,2                |  |      |         |   |      |  
|Natural gas                     |  | $    | 95,685  |   |      | $
|Liquids                         |  |      | 70,994  |   |      |  
|Total                           |  | $    | 166,679 |   |      | $



| | (1) | Sales revenues are before crown and freehold royalties
| | --- | ------------------------------------------------------



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



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 9







Production volumes were 23% lower than in 2010
primarily due to natural declines, a reduced asset base following property dispositions in 2010 and 2011 and limited new production
additions in 2011.



Compared to 2010, sales revenue decreased by
$49.4 million as a result of lower production volumes and realized natural gas prices, offset by increased realized liquids prices
in 2011. Realized prices and revenues are before any hedging gains or losses. The impact from hedging on realized natural gas prices
in 2011 was $0.55 per mcf compared to $0.38 per mcf in 2010.



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
IFRS.



The following provides the calculation of field
netback and funds flow netback.



|                              |  | 2011 |       |   | 2010 |  
|----------------------------- |  | ---- | ----- | - | ---- | -
|($/boe)                       |  |      |       |   |      |  
|Realized price1               |  | $    | 32.84 |   |      | $
|Processing revenue            |  |      | 1.38  |   |      |  
|Realized commodity hedge gain |  |      | 2.79  |   |      |  
|Royalties                     |  |      | (7.26 | ) |      |  
|Operating Expenses            |  |      | (9.74 | ) |      |  
|Transportation                |  |      | (1.22 | ) |      |  
|Field netback                 |  | $    | 18.79 |   |      | $
|                              |  |      |       |   |      |  
|Administrative                |  | $    | (3.15 | ) |      | $
|Interest                      |  |      | (6.09 | ) |      |  
|Funds flow netback            |  | $    | 9.55  |   |      | $



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



ROYATIES



|                                  |  | 2011 |        |   | 2010 |  
|--------------------------------- |  | ---- | ------ | - | ---- | -
|Crown royalties                   |  | $    | 17,314 |   |      | $
|Freehold royalties                |  |      | 7,369  |   |      |  
|Royalties included in revenue     |  |      | 24,683 |   |      |  
|                                  |  |      |        |   |      |  
|Overriding royalty 2              |  |      | 7,101  |   |      |  
|Other royalties                   |  |      | 1,987  |   |      |  
|Freehold mineral taxes            |  |      | 1,603  |   |      |  
|Other royalty obligations expense |  |      | 10,691 |   |      |  
|                                  |  |      |        |   |      |  
|Total royalties                   |  | $    | 35,374 |   |      | $
|                                  |  |      |        |   |      |  
|Percentage of sales revenue       |  |      | 21     | % |      |  



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 10







| | (1) | Gas cost allowance received on crown volumes are presented as a reduction of Operating Expenses
| | --- | -----------------------------------------------------------------------------------------------



| | (2) | The overriding royalty obligation represents a 5% commitment of the Corporation’s future gross production revenue, less
certain transportation costs and marketing fees, on the existing land base at September 26, 2009
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Total royalty expense decreased by 20% for the
year of 2011 compared to 2010, largely due to decrease in production volume and natural gas prices in 2011. Royalty rates as a
percentage of sales revenue were unchanged.



OPERATING
EXPENSES



|                           |  | 2011 |        |  | 2010 |  
|-------------------------- |  | ---- | ------ |  | ---- | -
|                           |  |      |        |  |      |  
|Operating expenses         |  | $    | 47,447 |  |      | $
|Operating expenses ($/boe) |  | $    | 9.74   |  |      | $



Operating expense in 2011 decreased by $5.4
million, or 10% compared to 2010, while per boe costs increased by 17% from 2010. The decrease on a total dollar basis was a result
of reduced volumes and cost control initiatives, partially offset by higher electricity and power costs. The increase in per boe
operating costs reflects that fixed costs are being borne on a per barrel basis by lower production volumes.



TRANSPORTATION



|                             |  | 2011 |       |  | 2010 |  
|---------------------------- |  | ---- | ----- |  | ---- | -
|                             |  |      |       |  |      |  
|Transportation costs         |  | $    | 5,926 |  |      | $
|Transportation costs ($/boe) |  | $    | 1.22  |  |      | $



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 expense in 2011 decreased by
$1.0 million, or 14% compared to 2010, while per boe costs increased by 12% from 2010. The decrease in transportation costs is
attributable to reduced production in 2011, partially offset by an increase in pipeline tariffs of approximately 25%. Increased
per boe costs are a result of lower production volumes and higher tariffs.



ADMINISTRATIVE EXPENSES



|                                    |  | 2011 |        |   | 2010 |  
|----------------------------------- |  | ---- | ------ | - | ---- | -
|                                    |  |      |        |   |      |  
|Gross administrative expenses       |  | $    | 21,185 |   |      | $
|Capitalized administrative expenses |  |      | (2,109 | ) |      |  
|Operator recoveries                 |  |      | (3,711 | ) |      |  
|Administrative expenses             |  | $    | 15,365 |   |      | $
|Administrative expenses ($/boe)     |  | $    | 3.15   |   |      | $



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 11







Administrative expenses per boe decreased 12%
compared to 2010 due to total administrative cost reductions of 32% on gross expenditures, offset by reduction in capitalized costs
and operator recoveries. The decreases were a result of cost containment initiatives as well as reduced staff levels following
the 2010 restructuring.



SHARE
BASED COMPENSATION



|                             |  | 2011 |        |   | 2010 |  
|---------------------------- |  | ---- | ------ | - | ---- | -
|                             |  |      |        |   |      |  
|Stock option plan            |  | $    | (1,385 | ) |      | $
|Employee long term incentive |  |      | 397    |   |      |  
|Deferred share unit plan     |  |      | 215    |   |      |  
|Retention share plan         |  |      | 325    |   |      |  
|Share purchase plan          |  |      | 894    |   |      |  
|                             |  |      |        |   |      |  
|Share based compensation     |  | $    | 446    |   |      | $



At June 30, 2011, substantially all of the outstanding
stock options were voluntarily surrendered by employees. As a result, Compton realized a significant recovery of the expense for
the year ended December 31, 2011.



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 share based compensation arrangements are presented in Note 12 to the audited consolidated financial statements. Management
and the Board of Directors are currently reviewing the share based compensation plans following the Recapitalization.



IMPAIRMENTS



Management has assessed both internal and external
economic factors to determine if any indicators of asset impairment exist at the year-end. When indictors exist, an impairment
test is completed, at the cash generating unit (“CGU”) level, to determine if any asset impairment exists. Each identified
CGU has largely independent cash flows and is geographically integrated.



In conjunction with the Recapitalization and
in accordance with an optional IFRS deemed cost election, the fair value of the Corporation’s assets and liabilities established
their respective deemed cost. The optional IFRS election, made effective September 30, 2011, is available in the year of transition
to IFRS and with the presence of a market event, such as the Recapitalization, that gives rise to an externally derived fair value.
Under the election, the Corporation recognized a write-down of $127.5 million to development and production assets, and a net $16.2
million increase to exploration and evaluation assets. The deemed cost of development and production assets totalled $570.2 million,
and exploration and evaluation assets totalled $62.1 million. This election has established the cost basis of assets and eliminated
any potential reversal of impairments previously recognized under IFRS since transition on January 1, 2010.



At December 31, 2011, a further write down of
development and production assets of $1.6 million was recorded to their estimated recoverable amount. The recoverable amount represents
the assets value based on the projected cash flows generated by the assets discounted at 10%. In 2010, an impairment of $695.4
million was recognized on development and production assets.



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 12







No further impairment was recognized in exploration
and evaluation assets at December 31, 2011.



EXPLORATION
AND EVALUATION



|                           |  | 2011 |        |  | 2010 |  
|-------------------------- |  | ---- | ------ |  | ---- | -
|                           |  |      |        |  |      |  
|Exploration and evaluation |  | $    | 20,975 |  |      | $
|Total costs ($/boe)        |  | $    | 4.31   |  |      | $



Exploration and evaluation expense relate to
costs of prospecting and geophysical work prior to the acquisition of mineral land rights, uneconomic exploratory wells and expired
mineral land rights. During the year, it was determined that the value of certain natural gas exploratory drilling costs and mineral
land leases would not be recovered in the near term and were written off based on current price forecasts for natural gas and
the Corporation’s development strategy.



INTEREST
AND FINANCE CHARGES



|                                                     |  | 2011 |        |  | 2010 |  
|---------------------------------------------------- |  | ---- | ------ |  | ---- | -
|                                                     |  |      |        |  |      |  
|Interest on senior notes                             |  | $    | 14,910 |  |      | $
|Interest on credit facility                          |  |      | 7,482  |  |      |  
|Interest on finance leases                           |  |      | 94     |  |      |  
|Interest on MPP term financing                       |  |      | 4,374  |  |      |  
|Interest expense                                     |  | $    | 26,860 |  |      | $
|Finance charges and amortization of transaction cost |  |      | 2,826  |  |      |  
|Total Interest and finance charges                   |  | $    | 29,686 |  |      | $
|Total interest and finance charges ($/boe)           |  | $    | 6.09   |  |      | $



| | (1) | Accretion of decommissioning liabilities totalling $4,818 (2010 – $4,504) have been excluded from the above
| | --- | -----------------------------------------------------------------------------------------------------------



Interest expense decreased by 39% for 2011 compared
to the same period in 2010. Interest paid on the Senior Term Notes was reduced substantially through the October 2010 and August
2011 restructuring and the related reduction of the amount outstanding, partially offset by an increase of interest on the credit
facility. In addition, the strengthening of the Canadian dollar in relation to the US dollar has reduced the Canadian dollar equivalent
amount paid. The expiry of certain finance leases in 2010 also reduced the interest component of lease obligations recognized.



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 13







Finance charges and amortization of transaction
costs for the year of 2011 decreased by $3.3 million or 54% compared to the same period in 2010, as a result of lower fees for
unutilized credit and amortization of deferred financing costs.



Interest and finance charges decreased on a
per boe basis due to lower overall borrowing costs, despite reduced production volumes.



The Corporation’s capital structure following the 2011 Recapitalization
is expected to significantly reduce interest and finance charges and related rates in 2012. (See “Forward Looking Statements”
in the “Advisory” section of this MD&A.)



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



|                                                   |  | 2011 |         |   | 2010 |  
|-------------------------------------------------- |  | ---- | ------- | - | ---- | -
|                                                   |  |      |         |   |      |  
|Credit Facility                                    |  | $    | 129,811 |   |      | $
|Effective interest rate                            |  |      | 5.76    | % |      |  
|                                                   |  |      |         |   |      |  
|2013 Senior Term Notes (US$)                       |  | $    | -       |   |      | $
|Coupon Rate (US$)                                  |  |      | -       |   |      |  
|Effective interest rate (Cdn$)                     |  |      | -       |   |      |  
|                                                   |  |      |         |   |      |  
|2011 Mandatory convertible senior term notes (US$) |  | $    | 28,973  |   |      | $
|Coupon Rate (US$)                                  |  |      | 10.00   | % |      |  
|Effective interest rate (Cdn$)                     |  |      | 9.71    | % |      |  
|                                                   |  |      |         |   |      |  
|2017 Senior Term Notes (US$)                       |  | $    | 124,582 |   |      |  
|Coupon Rate (US$)                                  |  |      | 10.00   | % |      |  
|Effective interest rate (Cdn$)                     |  |      | 9.71    | % |      |  



RISK
MANAGEMENT



|                                  |  | 2011 |         |   | 2010 |  
|--------------------------------- |  | ---- | ------- | - | ---- | -
|                                  |  |      |         |   |      |  
|Commodity contracts               |  |      |         |   |      |  
|Realized (gain) loss              |  | $    | (13,586 | ) |      | $
|Unrealized (gain) loss            |  |      | 4,488   |   |      |  
|Foreign currency contracts        |  |      |         |   |      |  
|Unrealized (gain) loss            |  |      | (53     | ) |      |  
|Total risk management (gain) loss |  | $    | (9,151  | ) |      | $
|                                  |  |      |         |   |      |  
|Realized (gain) loss              |  | $    | (13,586 | ) |      | $
|Unrealized (gain) loss            |  |      | 4,435   |   |      |  
|Total risk management (gain) loss |  | $    | (9,151  | ) |      | $



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).



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 14







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 natural gas
denominated in gigajoules (“GJ”) and million British thermal units (“MMBtu”), oil denominated in barrels
and electricity denominated in megawatt hours (“MWH”) to stabilize fluctuations in commodity pricing. Compton’s
outstanding hedging instruments at December 31, 2011, are as follows, expressed in Canadian dollars unless otherwise noted:



|Commodity       |  | Term                |  | Volume         |  | Strike Price |  | Index
|--------------- |  | ------------------- |  | -------------- |  | ------------ |  | -----
|                |  |                     |  |                |  |              |  |      
|Natural Gas     |  |                     |  |                |  |              |  |      
|US$ Swap        |  | Jul 2011 – Dec 2012 |  | 10,000 MMBtu/d |  | $4.65/MMBtu  |  | AECO 
|                |  |                     |  |                |  |              |  |      
|Oil             |  |                     |  |                |  |              |  |      
|US$ Call Option |  | Jan 2012 – Dec 2012 |  | 1,000 Bbl/d    |  | $100.00/Bbl  |  | WTI  
|                |  |                     |  |                |  |              |  |      
|Electricity     |  |                     |  |                |  |              |  |      
|Swap            |  | Jan 2011 – Dec 2013 |  | 72 MWh/d       |  | $75.13/MWh   |  | AESO 



DEPLETION
AND DEPRECIATION



|                                   |  | 2011 |        |  | 2010 |  
|---------------------------------- |  | ---- | ------ |  | ---- | -
|                                   |  |      |        |  |      |  
|Total depletion and depreciation   |  | $    | 58,076 |  |      | $
|Depletion and depreciation ($/boe) |  | $    | 11.92  |  |      | $



Total depletion and depreciation expense decreased
35% during the year as compared to 2010, largely due to a decrease in the asset base following impairments recognized under IFRS,
and the reduction in overall production volumes. Depletion and depreciation expense per boe during 2011 decreased by 15% compared
to 2010.



FOREIGN EXCHANGE AND OTHER (GAINS)
AND LOSSES



|                                            |  | 2011 |         |   | 2010 |  
|------------------------------------------- |  | ---- | ------- | - | ---- | -
|                                            |  |      |         |   |      |  
|Foreign exchange on translation of US$ debt |  | $    | (1,326  | ) |      | $
|Gain on extinguishment of US$ debt          |  |      | (55,175 | ) |      |  
|(Gain)/loss on disposition of assets        |  |      | (14,747 | ) |      |  
|Other                                       |  |      | (9      | ) |      |  
|                                            |  |      |         |   |      |  
|Foreign exchange and other (gains) losses   |  | $    | (71,257 | ) |      | $



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 15







Foreign exchange and other gains and losses
recognized in 2011 relate primarily to the Recapitalization including the conversion of the Senior Term Notes to equity, resulting
in a net $55.2 million gain on extinguishment. Comparative periods were most significantly impacted by translation gains recognized
on the US denominated Senior Term Notes and losses recorded in association with property dispositions.



INCOME TAXES



Income taxes are recorded using the liability
method of accounting. Deferred income taxes are calculated based on the temporary difference between the accounting and income
tax basis of an asset or liability. Deferred income tax assets and liabilities are considered long term in nature under IFRS reporting.



A deferred income tax expense of $10.1 million
was recognized during 2011 as compared to a recovery of $179.3 million for the comparable period in 2010.



At December 31, 2011, the Corporation had available
deferred income tax assets of $13.0 million that were not recorded in the financial statements due to the uncertainties associated
with historical earnings performance, and its ability to utilize these balances in the future. The benefit of these balances does
not deteriorate over time and will be available to the Corporation in the future with the improvement of natural gas prices and
the generation of taxable income.



Recoveries arise as a result of the change in
timing for settlement of deferred tax assets and liabilities, and the change in tax rates applied. The impact of adjustments and
temporary differences related to IFRS has been adjusted for in deferred tax balances at December 31, 2011.



CORPORATE TAX RATES



|               |  | 2011 |      |   | 2010 |  |      | 2009 | 
|-------------- |  | ---- | ---- | - | ---- |  | ---- | ---- | 
|               |  |      |      |   |      |  |      |      | 
|Statutory rate |  |      | 26.5 | % |      |  | 28.0 | %    | 



A reconciliation of the effective tax rate to the statutory
rate may be found in Note 18 to the consolidated financial statements.



| | IV. | LIQUIDITY AND CAPITAL RESOURCES
| | --- | -------------------------------



CAPITAL
STRUCTURE



The Corporation’s capital structure is
comprised of bank debt, working capital, MPP term financing and equity. Compton’s objectives when managing its capital structure
are to:



| | · | Ensure the Corporation can meet its financial obligations;
| | - | ----------------------------------------------------------



| | · | Retain an appropriate level of leverage relative to the risk of Compton’s underlying assets;
and
| | - | ------------------------------------------------------------------------------------------------



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 16







| | · | Finance internally generated growth and potential acquisitions.
| | - | ---------------------------------------------------------------



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 issuing new debt or equity.



The Corporation monitors its
capital structure and financing requirements using non-GAAP measures consisting of total net debt to adjusted EBITDA and
total net debt to capitalization to steward its debt position as measures of Compton’s overall financial strength. The
former ratio is considered by Management to be more significant for monitoring purposes.



Adjusted EBITDA is a non-GAAP measure defined
as net earnings (loss) before interest and finance charges, income taxes, depletion and depreciation, accretion of decommissioning
liabilities, unrealized foreign exchange and other gains (losses), and unrealized risk management gains (losses). The Corporation
targets a total net debt to adjusted EBITDA of 2.5 to 3.0 times.



Capitalization is a non-GAAP measure defined
as working capital, long-term debt including current portion, MPP term financing, and equity. Compton targets at total net debt
to Capitalization ratio of between 40% and 50%.



|                                       |  | December 31 2011 |         |   | December 31 2010 |   |         | January 1 2010 | 
|-------------------------------------- |  | ---------------- | ------- | - | ---------------- | - | ------- | -------------- | 
|                                       |  |                  |         |   |                  |   |         |                | 
|Working capital (surplus) deficiency1  |  | $                | 17,070  |   |                  | $ | 23,428  |                | 
|Credit facility2                       |  |                  | 112,608 |   |                  |   | 145,584 |                | 
|MPP term financing3                    |  |                  | 31,369  |   |                  |   | 45,620  |                | 
|Senior term notes                      |  |                  | -       |   |                  |   | 237,212 |                | 
|Total net debt                         |  |                  | 161,047 |   |                  |   | 451,844 |                | 
|Total equity                           |  |                  | 321,835 |   |                  |   | 187,198 |                | 
|Total capitalization                   |  | $                | 482,882 |   |                  | $ | 639,042 |                | 
|Total net debt to capitalization ratio |  |                  | 33.4    | % |                  |   | 70.7    | %              | 
|Total net debt to adjusted EBITDA      |  |                  | 2.0     | x |                  |   | 4.0     | x              | 



| | (1) | Adjusted working capital excludes risk management, current MPP term financing and facility
| | --- | ------------------------------------------------------------------------------------------

| | (2) | Includes unamortized transaction costs of $879 (December 31, 2010 - $1,692; January 1, 2010 –
$1,279)
| | --- | -----------------------------------------------------------------------------------------------------

| | (3) | Includes unamortized financing fees of $360 (December 31, 2010 - $520; January 1, 2010 –
$680)
| | --- | ----------------------------------------------------------------------------------------------





As a result of the Recapitalization
reducing Senior Term Notes by $238.5 million, the Corporation was below the targeted net debt to capitalization ratio, as
well as the net debt to adjusted EBITDA target at December 31, 2011. Previously, both metrics had increased outside of
Management’s target ranges.



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 17







During 2011, property sales for gross proceeds
of $26.2 million were used to repay a portion of the facility with the balance applied to working capital. In addition, the extinguishment
of the Senior Term Notes, and gross share issuance proceeds of $50.0 million significantly reduced total net debt.



Equity was reduced as part of the transition
to IFRS and the resulting adjustments recorded during 2010 negatively impacted net loss and deficit. These adjustments are disclosed
in more detail in Note 23 – “Transition to IFRS” of the consolidated financial statements.



WORKING
CAPITAL



Compton had a working capital deficiency of
$17.1 million at December 31, 2011, as compared to a deficiency of $23.4 million as at December 31, 2010. In the oil and gas industry,
there is typically 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. (See “Forward Looking Statements” in the “Advisory” section of this MD&A.)



CREDIT
FACILITY



The Corporation’s outstanding bank debt
at December 31, 2011 was $112.6 million.



On September 27, 2011, Compton reached an
agreement with a new syndicate of lenders for a credit facility of $160.0 million, including a working capital facility of
$15.0 million and a syndicated facility of $145.0 million. The semi-annual review of Compton’s borrowing base under its
reserve-based credit facility was completed subsequent to year-end. Given the near-term outlook for natural gas prices,
Compton’s Facility has been set at $140.0 million, comprised of a working capital facility of $15.0 million and a
syndicated facility of $125.0 million. The Facility term ends February 8, 2013, with the usual semi-annual lenders review at
the end of March and September 2012; the review may change the amount available thereafter. The borrowing base 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 adjusted EBITDA ratio. The credit facility
is secured by a fixed and floating charge debenture on the assets of the Corporation.



SENIOR
TERM NOTES



The US $238.5 million Senior Term Notes were
fully extinguished on August 23, 2011 as part of the approved Recapitalization. The Senior Term Notes were converted entirely to
equity with the issuance of common shares, cashless warrants, and share purchase rights.



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 $31.4 million was 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 12.1% 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.



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 18







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 for the balance of the contract period. 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 repayment 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, 2011, the threshold throughput
volume was reduced to 53.04 mmcf/d. The cumulative prepayments of the purchase option are $10.4 million (2011 – $9.2 million,
2010 - $1.2 million, 2009 - $nil), reducing the amount of the MPP term financing liability. Subsequent to year-end, Compton made
an additional minimum payment of $0.9 million. Internal estimates indicate that dedicated reserves will not exceed the minimum
reserve test threshold at December 31, 2011. The amount of any resulting prepayment, subject to third party verification, may approximate
$4.3 million, which would be due prior to June 30, 2012.



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, 2011.



|                    |  | 2012 |        |  | 2013 |   |         | 2014 |  |   | 2015   |  |  | 2016 |       |  | Thereafter |  
|------------------- |  | ---- | ------ |  | ---- | - | ------- | ---- |  | - | ------ |  |  | ---- | ----- |  | ---------- | -
|Credit facility     |  | $    | -      |  |      | $ | 113,487 |      |  | $ | -      |  |  | $    | -     |  |            | $
|MPP term financing1 |  |      | 14,756 |  |      |   | 9,592   |      |  |   | 15,430 |  |  |      | -     |  |            |  
|Accounts payable    |  |      | 40,156 |  |      |   | -       |      |  |   | -      |  |  |      | -     |  |            |  
|Finance leases      |  |      | 1,030  |  |      |   | 224     |      |  |   | 224    |  |  |      | -     |  |            |  
|Office facilities   |  |      | 1,581  |  |      |   | 1,631   |      |  |   | 1,609  |  |  |      | 1,637 |  |            |  
|                    |  | $    | 57,523 |  |      | $ | 124,934 |      |  | $ | 17,263 |  |  | $    | 1,637 |  |            | $



| | (1) | Represents monthly fixed base fee payments. The 2012 amount
includes purchase option prepayment of $5.2 million.
| | --- | ----------------------------------------------------------------------------------------------------------------



| | V. | OUTLOOK
| | -- | -------



North American natural gas prices are at historic
lows and industry analysts predict that they will remain depressed throughout 2012. The current depressed natural gas market has
resulted from increasing production volumes and supply levels that have outpaced consumer demand. As natural gas comprises approximately
83% of Compton’s production, the Corporation’s 2012 program is impacted by the current natural gas price outlook.



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 19







As a result, Management has taken a
prudent approach to the Corporation’s 2012 strategy, the objective of which is to maintain and optimize
current production by utilizing internally generated cash flow. In addition, Compton will continue to use its risk management
program to reduce cash flow volatility, identifying additional opportunities to hedge to a maximum of 50% of production. In
2012, Compton will focus on completing recently drilled liquids-rich gas wells in the Niton area and new oil wells in the
Southern Plains area to partially offset the impact of continued low prices. If natural gas prices strengthen and
the Corporation’s cash flow increases, Management may adjust the capital program to undertake further
development activity.



Compton’s assets provide significant upside
potential through their multiple zone development opportunities, contiguous land blocks and impact of horizontal multi-stage fracture
technology. Management continues to review strategies designed to maximize shareholder value in 2012, considering the current natural
gas environment and cash flow limitations. In the context of the current price environment, Compton will focus on the development
of its asset base and identifying and executing on selected opportunities for future growth.



| | VI. | 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(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.



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 20







As indicated in certifications filed with the
SEC and CSA, Compton completed an evaluation of the effectiveness of the design and operation of 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 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, the 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 financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. These controls include policies and procedures that:



| | · | Pertain to the maintenance of records, that accurately and fairly reflect the transactions affecting
Compton’s assets;
| | - | ----------------------------------------------------------------------------------------------------------------------



| | · | Provide reasonable assurance that transactions are recorded to be able to prepare financial statements
in accordance with IFRS, 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 consolidated 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 Compton’s internal control over financial reporting
was effective as of December 31, 2011.



The effectiveness of internal control over financial
reporting as of December 31, 2011, 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 Auditor’s
Report which is included in this document following the MD&A.



INTERNAL
AUDIT FUNCTION



Effective January 1, 2011, the Corporation engaged
a third party service provider to support the development and testing of internal controls over financial reporting. Reporting
directly to the Audit, Finance and Risk Committee, the third party service provider 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.



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 21







CHANGES
IN INTERNAL CONTROL OVER FINANCIAL REPORTING



The adoption of IFRS effected Compton’s
presentation of financial results and the accompanying disclosure. The impact on processes, controls and financial reporting systems
have been evaluated and modifications made to the control environment accordingly. There were no significant changes to internal
control over financial reporting during the period beginning January 1, 2011 and ending on December 31, 2011 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
which could negatively impact Compton’s business, financial condition, and 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 small 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 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 relies on its partners in jointly owned properties
that Compton does not operate.



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.



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 22







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.





Liquidity

Liquidity
risk is the risk that the Corporation is not able to meet its financial obligations as they fall due. If the credit facilities
are not renewed on February 8, 2013, Compton’s $140.0 million term credit facilities will mature. The lenders under the
credit facilities will reassess the borrowing base semi-annually on March 31 and September 30, which review may change the amount
that the Corporation may borrow under its credit facilities. As at December 31, 2011, Compton had $113.5 million outstanding under
its credit facilities.

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 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, 2011, 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 and 2011.



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 the consolidated statement of operations and comprehensive earnings (loss).



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 23







DEPLETION



Capitalized costs and estimated future expenditures
to develop proved reserves, including abandonment costs, are depleted based on the proportion of oil and natural gas reserves produced
during the year compared to estimated total proved and probable reserves.



In 2011, Compton incurred $58.1 million of depletion
and depreciation expense. If proved and probable reserves were to increase by 5%, depletion and depreciation expense would decrease
by $2.8 million and consolidated net earnings (loss) after tax would increase by $2.1 million. If proved and probable reserves
were to decrease by 5%, depletion and depreciation expense would increase by $3.1 million and consolidated net earnings (loss)
after tax would decrease by $2.3 million.



IMPAIRMENT TEST WRITE-DOWN



All costs related to the acquisition of, exploration
for and development of petroleum and natural gas reserves are capitalized on an area by area basis. The carrying value of long-term
assets is reviewed quarterly for indicators that the carrying value of an asset or cash-generating unit may not be recoverable.
If indicators of impairment exist, the recoverable amount of the asset or cash-generating unit is estimated. If the carrying value
of the asset or cash-generating unit exceeds the recoverable amount, the asset or cash-generating unit is written down with an
impairment recognized in net earnings (loss).



The recoverable amount of an asset or cash-generating
unit is the greater of its fair value less costs to sell and its value in use. Fair value is determined to be the amount for which
the asset could be sold in an arm's length transaction.



Fair value less costs to sell is a measure of
third party value, determined using discounted future net cash flows of proved and probable reserves using forecast prices and
costs, and considering various other market factors external to the Corporation.



Value in use is determined by estimating the
present value of the future net cash flows expected to be derived from the Corporation’s continued use of the asset or cash-generating
unit. Cash flows used in determining value in use will not consider all market factors but only those relevant to the Corporation.



Reversals of impairments are recognized when
there has been a subsequent increase in the recoverable amount. In this event, the carrying amount of the asset or cash-generating
unit is increased to its revised recoverable amount with an impairment reversal recognized in net earnings (loss). The recoverable
amount is limited to the original carrying amount less depreciation, depletion and amortization as if no impairment had been recognized
for the asset or cash-generating unit for prior periods.



As at December 31, 2011, the value in use calculated
was $1.6 million less than the carrying value of the costs capitalized. As a result, the carrying value of the costs capitalized
was written down by $1.6 million, using a 10.0% discount rate.



As at December 31, 2010, the value in use calculated
was $695.4 million less than the carrying value of the costs capitalized. As a result, the carrying value of the costs capitalized
was written down by $695.4 million, using a 10.0% discount rate.



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 24







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.



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, 2011. These valuations
are based on forward looking estimates including, but not limited to, volatility, interest rates and commodity prices.



DECOMMISSIONING LIABILITIES



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



At December 31, 2011, the
Corporation reviewed its estimated liability for decommissioning based on risk free interest rate
changes, current abandonment and reclamation cost information in the Corporation’s specific areas of operation and
other underlying assumptions. No material revision was required during the fourth quarter, however the cumulative revision of
estimate for 2011 resulted in a decrease of the decommissioning liability of $21.9 million.



A summary of the significant accounting policies
used by Compton can be found in Note 2 of the 2011 consolidated financial statements.



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 25







| | IX. | NEWLY AND FORTHCOMING ADOPTED ACCOUNTING POLICIES
| | --- | -------------------------------------------------



ADOPTION OF INTERNATIONAL FINANCIAL
REPORTING STANDARDS



The Corporation’s consolidated financial
statements for the year ended December 31, 2011 is the first audited consolidated financial statements under IFRS. These statements
were prepared in accordance with IFRS 1 and as such include the application of IFRS 1 “First –Time Adoption of International
Financial Reporting Standards”.



IFRS 1 requires all first-time adopters to retrospectively
apply all effective IFRS standards as of the transition date of January 1, 2010. However, it also provides certain optional exemptions
and certain mandatory exceptions for first time IFRS adopters.



The Corporation has taken the following key
optional exemptions upon transition to IFRS.



| | (a) | Deemed cost election for petroleum and natural gas assets
| | --- | ---------------------------------------------------------



The Corporation has development and production
assets recognized in the opening IFRS balance sheet. Under IFRS 1, the Corporation was allowed and elected to deem the value of
its petroleum and natural gas assets, at the date of transition, based on the historical cost under Previous GAAP.



| | (b) | Decommissioning liabilities included in the cost of development and production
| | --- | ------------------------------------------------------------------------------



Under Previous GAAP, decommissioning liabilities
were discounted at a credit adjusted risk free rate. Under IFRS, the estimated cash flow to abandon and remediate the wells and
fields has been risk adjusted; therefore, the provision recognized on the balance sheet has been discounted at a risk free rate.



| | (c) | Business combinations
| | --- | ---------------------



Compton has entered into business combinations
before the date of transition of January 1, 2010. Compton has not elected to adopt IFRS 3 “Business Combinations” retrospectively.
As a result, the classification of previous acquisitions under Previous GAAP will remain the same with no change in the recognition
of assets and liabilities, excluding goodwill.



The impact of accounting policy selections under
IFRS resulted in the following significant adjustments to the previously reported financial statement balances.



| | (i) | Deferred taxes
| | --- | --------------



Under Previous GAAP, the Corporation
has recognized deferred tax assets and liabilities, primarily associated with its E&E, D&P, and risk management activities.
Under IFRS, current deferred tax balances have been re-classed for presentation entirely as long term assets/liabilities.



In addition, each of the balances adjusted
through equity on transition to IFRS have been tax effected based on the Corporation’s estimated rate of reversal, which
approximates 25%. At January 1, 2010, the impact to deferred taxes was a decrease in the deferred tax liability of $91.5 million.
For the year ended December 31, 2010, the cumulative impact on the deferred tax liability was a decrease of $160.7 million. See
the reconciliation of equity for adjustments that required a tax effect.



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 26







| | (ii) | Development and production
| | ---- | --------------------------



Under Previous GAAP, the Corporation
followed full cost accounting for its oil and natural gas assets. This methodology enabled the capitalization of amounts exceeding
those acceptable for IFRS. Under IFRS 1 on transition, the Corporation elected to allocate its full cost pool to its identified
CGU’s and then performed an impairment test.



Under the transitional election, an
impairment test of the Corporation’s assets was required at a CGU level subsequent to the allocation. The Corporation recognized
an impairment write-down of $263.9 million on its oil and natural gas assets at January 1, 2010. The write-downs were primarily
recognized in two Southern Alberta CGU’s with long reserve lives where the discount rates have the most impact on the value
in use assessment.



For the year ended December 31, 2010,
an impairment write-down of $695.4 million was recognized across all CGU’s. The impairments reflect the historically low
natural gas pricing environment and outlook. Under Previous GAAP, a $367.0 million ceiling test impairment was recognized on oil
and natural gas assets at December 31, 2010.



The restated IFRS balances also reflect
gains and losses on the derecognition of assets disposed of during 2010 at Niton and Gilby. The combined net losses of $5.3 million
have been included in the foreign exchange and other gains and losses presentation in net earnings. Under Previous GAAP, proceeds
on sales were deducted from the full cost pool without gain or loss recognition unless the disposition changed the depletion rate
by more than 20%.



| | (iii) | Exploration and evaluation
| | ----- | --------------------------



IFRS 6 “Exploration and Evaluation
of Mineral Resources” requires the separate recognition of exploration assets that have not yet established a determinable
future value in the form of technically feasible and commercially viable reserves. The $72.4 million of E&E costs recognized
under IFRS on transition at January 1, 2010 represent the Corporation’s interest in undeveloped lands and mineral rights,
and exploratory wells under evaluation.



For the year ended December 31, 2010,
the expiry of undeveloped mineral rights resulted in the derecognition of $2.1 million of E&E assets, and have been presented
as exploration expense in net earnings.



| | (iv) | Other assets
| | ---- | ------------



Under a transitional election contained
in IFRS 1, the Corporation eliminated unamortized actuarial gains of $0.2 million associated with the Mazeppa Processing Partnership
defined benefit pension plan. In addition, vested past service costs of the pension plan totaling $0.6 million were also adjusted
through equity on transition. The net result of both entries was a reduction in other assets of $0.4 million. There were no additional
adjustments at December 31, 2010.



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 27







Also on transition, the Corporation
adopted an accounting policy to recognize identifiable inventory items that are currently being marketed for sale or redeployment.
Identifiable inventory of $2.2 million was initially recognized on transition at January 1, 2010 and is included for presentation
purposes in other assets at the lower of cost and recoverable amounts. The recognition of inventory reduced D&P assets by $5.7
million, and a valuation allowance of $3.5 million was reflected in equity.



| | (v) | Provisions
| | --- | ----------



The estimated provision for decommissioning
liabilities associated with the Corporation’s oil and natural gas assets has been adjusted on transition to IFRS. The adjustment
reflects the application of a risk free rate for the discounting of the liability (based on the underlying assets), where previously
under Previous GAAP this was measured using a credit adjusted risk free rate. The adjustment to the discounted decommissioning
liability recognized at January 1, 2010 was $83.2 million. Under an IFRS 1 election, this adjustment has been offset directly to
equity on transition. The adjustment to the discounted decommissioning liability recognized at December 31, 2010 was $123.9 million.



In addition, a provision of $13.9 million
was recognized at January 1, 2010 for lease surrender costs payable, and a reduction of other corporate assets of $0.9 million
in related leasehold improvements. The provision reflects the lower estimated cost of surrender for a portion of the corporate
office space under lease, compared to the cost of fulfilling the contract. The undeveloped and unutilized space was determined
by Management to be an onerous contract. The entire adjustment of $14.8 million was reflected in equity on transition.



At December 31, 2010, the revision
of decommissioning liability cost estimates increased the liability provision by $59.0 million. The revisions related primarily
to well abandonment costs based on the historical costs of the Corporation. These assumptions were adjusted downward in 2011 to
better align with inflation adjusted regulatory guidance and updated information. See Note 9 – “Provisions”.



| | (vi) | Non-controlling interest
| | ---- | ------------------------



The presentation of non-controlling
interest has been changed on transition from Previous GAAP to IFRS. Under IFRS, non-controlling interest is considered a component
of equity and presentation reclassification was made. In 2010, adjustments were made relating to the recognition and depletion
of MPP facility assets, pension and decommissioning liabilities.



In the course of preparing these
consolidated financial statements, Management identified that adjustments to previous disclosure for the consolidation of MPP
were required pertaining to the transition to IFRS. As a result, non-controlling interest has been revised on the balance sheet
and statement of operations and comprehensive earnings (loss). The revision results in a decrease in the non-controlling
interest and a corresponding increase to majority shareholder’s equity.



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 28







At January 1, 2010, the impact of transitional
IFRS adjustments to the balance sheet non-controlling interest was $16.8 million, previously presented as $nil. At December 31,
2010, the cumulative impact of transitional IFRS adjustments to the balance sheet non-controlling interest was $15.2 million, previously
presented as $0.3 million.



| | (vii) | Royalties
| | ----- | ---------



The presentation of royalties under
IFRS has changed from previous disclosures under Previous GAAP. Previously, royalties were aggregated in a single line and shown
as a reduction of total revenue in net earnings. Under IFRS, crown and freehold royalties have been netted from revenues, all other
royalties have been presented as “Other royalty obligations” in the expenses. In addition, natural gas cost allowances
have been presented as a recovery of related processing fees included in operating expense.



| | (viii) | Leases
| | ------ | ------



On transition to IFRS at January 1,
2010, the classification of certain leases were changed to be recognized as finance leases under IFRS. These leases have been included
in trade and other accounts payable for financial statement purposes as they are not individually material. As a result of the
reclassification, D&P assets were increased by $9.9 million (net), capital lease obligations increased $8.9 million, and the
cumulative impact of interest and depreciation expense of $1.0 million related to the assets was offset to equity at January 1,
2010.



At December 31, 2010, D&P assets
were increased by $2.1 million (net), capital lease obligations increased $2.2 million, and the cumulative impact of interest and
depreciation expense of $1.6 million and $0.6 million, respectively, was recorded through net earnings.



| | (ix) | Share based payments
| | ---- | --------------------



Under Previous GAAP, share based payments
were recognized as an expense on a straight-line basis through the date of full vesting. Under IFRS, the expense is required to
be recognized over the individual vesting periods for graded vesting awards and based on estimated forfeiture rates. At January
1, 2010, this change in valuation resulted in a $0.9 million increase in “Other reserves”, and was offset directly
to equity.



For the year ended December 31, 2010,
an increase in share based compensation expense of $0.4 million resulted from the revised valuation methodology.



| | (x) | Depletion
| | --- | ---------



Upon transition to IFRS, the Corporation
adopted a policy of depleting its oil and natural gas assets on a unit of production basis over proved plus probable reserves,
by depletable component. The depletion policy under Previous GAAP was a unit of production over proved reserves in a single pool.
There was no impact on adoption of IFRS at January 1, 2010, as provided by the IFRS 1 deemed cost allocation election.



For the year ended December 31, 2010,
a decrease in depletion of $52.8 million resulted from the reduction of the Corporation’s oil and natural gas asset base
and the revised depletion methodology. Ceiling test impairments recognized under Previous GAAP were previously disclosed in depletion
and depreciation.



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 29







FORTHCOMING CHANGES IN ACCOUNTING
STANDARDS



All accounting standards effective for periods
on or after January 1, 2011 have been adopted as part of the transition to IFRS. The following new IFRS pronouncements have been
issued or are outstanding for 2011, and may have an impact on the Corporation in the future as discussed below.



As of January 1, 2015 , the Corporation will
be required to adopt IFRS 9 “Financial Instruments”, which is the result of the first phase of the International Accounting
Standards Board (“IASB”) project to replace IAS 39 “Financial Instruments: Recognition and Measurement”.
The new standard replaces the current multiple classification and measurement models for financial assets and liabilities with
a single model that has only two classification categories: amortized cost and fair value. Portions of the standard remain in development
and the full impact of the standard on the Corporation’s Consolidated Financial Statements will not be known until the project
is complete.



In May 2011, the IASB released the following
new standards: IFRS 10, “Consolidated Financial Statements”, IFRS 11, “Joint Arrangements”, IFRS 12, “Disclosures
of interests in other entities” and IFRS 13, “Fair Value Measurement”. Each of these standards is to be adopted
for fiscal years beginning January 1, 2013 with earlier adoption permitted. A brief description of each new standard follows below:



| | · | IFRS 10, “Consolidated Financial Statements” supersedes IAS 27 “Consolidation
and Separate Financial Statements” and SIC-12 “Consolidation – Special Purpose Entities”. This standard
provides a single model to be applied in control analysis for all investees including special purpose entities.
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | IFRS 11, “Joint Arrangements” divides joint arrangements into two types, joint operations
and joint ventures, each with their own accounting model. All joint arrangements are required to be reassessed on transition to
IFRS 11 to determine their type to apply the appropriate accounting.
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | IFRS 12, “Disclosure of Interests in Other Entities” combines in a single standard
the disclosure requirements for subsidiaries, associates and joint arrangements as well as unconsolidated structured entities.
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | IFRS 13, “Fair Value Measurement” defines fair value, establishes a framework for measuring
fair value and sets out disclosure requirements for fair value measurements. This standard defines fair value as the price that
would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the
measurement date.
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The Corporation is currently assessing the impact
of the new standards, but does not anticipate that the adoption of these standards will have a significant impact on the consolidated
financial statements.



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 30







| | X. | QUARTERLY INFORMATION
| | -- | ---------------------



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



|                              |  | 20111 |          |   | 20101 |  
|----------------------------- |  | ----- | -------- | - | ----- | -
|$millions, except where noted |  | Q4    |          |   | Q3    |  
|                              |  |       |          |   |       |  
|Total revenue                 |  | $     | 32.7     |   |       | $
|Cash flow                     |  | $     | 12.4     |   |       | $
|Per share - basic             |  | $     | 0.49     |   |       | $
|- diluted                     |  | $     | 0.49     |   |       | $
|Net earnings (loss)           |  | $     | (6.8     | ) |       | $
|Per share - basic             |  | $     | (0.26    | ) |       | $
|- diluted                     |  | $     | (0.26    | ) |       | $
|Operating earnings (loss)     |  | $     | (2.2     | ) |       | $
|Production                    |  |       |          |   |       |  
|Natural gas (mmcf/d)          |  |       | 63.6     |   |       |  
|Liquids (bbls/d)              |  |       | 2,126.0  |   |       |  
|Total (boe/d)                 |  |       | 12,725.3 |   |       |  
|Average price                 |  |       |          |   |       |  
|Natural gas ($/mcf)           |  | $     | 3.53     |   |       | $
|Liquids ($/bbl)               |  | $     | 88.31    |   |       | $
|Total ($/boe)                 |  | $     | 32.40    |   |       | $



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



| | (2) | Total shares outstanding changed from 263.6 million to 26.4 million on August 10, 2011 in accordance
with the Recapitalization
| | --- | ------------------------------------------------------------------------------------------------------------------------------



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
throughout 2010 and 2011. Despite this, cash flow has increased due to Management’s focus on continued cost reductions and
improvement to capital efficiencies. Seasonality of winter operating conditions results in production increases that are typically
higher in the third and fourth quarters.



Net earnings (loss) for each of the
last three quarters in 2010 include impairment adjustments for petroleum and natural gas assets following the transition to
IFRS, the most significant of which occurred in the fourth quarter. During the third quarter of 2011, net earnings were
increased following a gain on extinguishment of the Senior Term Notes.



Cash flow and operating earnings (loss) are
affected by realized commodity prices, changes in the US dollar against the Canadian dollar, and realized hedging.



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 31







| | X. | SELECTED ANNUAL INFORMATION
| | -- | ---------------------------



|                             |  | 2011 |         |  | 2010 |  
|---------------------------- |  | ---- | ------- |  | ---- | -
|                             |  |      |         |  |      |  
|Total revenue                |  | $    | 141,996 |  |      | $
|Net earnings (loss)          |  | $    | 17,279  |  |      | $
|Per share -  basic           |  | $    | 1.80    |  |      | $
|- diluted                    |  | $    | 1.47    |  |      | $
|Total assets1                |  | $    | 673,308 |  |      | $
|Total financial liabilities2 |  | $    | 351,473 |  |      | $



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



| | (2) | Includes Senior Term Notes and Credit Facility
| | --- | ----------------------------------------------



Total revenue was 24% lower than in 2010 due
to lower commodity prices in 2011 and an overall reduction in production volumes from the sale of non-core asset during the first
quarter of 2011. The 2011 net loss includes a $1.6 million impairment relating to development and production assets.



| | XI. | TRADING AND SHARE STATISTICS
| | --- | ----------------------------



As at March 7, 2012, there are 26,358,528 common
shares, 571,600 options, and 3,690,982 share purchase warrants outstanding.



|                                     |  | 2011       |           |  | 2010        |  |           | 2009       | 
|------------------------------------ |  | ---------- | --------- |  | ----------- |  | --------- | ---------- | 
|                                     |  | TSX ($Cdn) |           |  | NYSE1 ($US) |  |           | TSX ($Cdn) | 
|Average daily trading volumes        |  |            | 15.3      |  |             |  | -         |            | 
|Share price ($/share)                |  |            |           |  |             |  |           |            | 
|High                                 |  |            | 94.00     |  |             |  | -         |            | 
|Low                                  |  |            | 3.90      |  |             |  | -         |            | 
|Close                                |  |            | 4.37      |  |             |  | -         |            | 
|Market capitalization at December 31 |  |            | $Cdn158.9 |  |             |  | $Cdn247.8 |            | 
|Shares outstanding                   |  |            | 26,359    |  |             |  | 1,318     |            | 



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



| | (2) | Effective August 10, 2011, the Corporation completed a 200:1 consolidation of its common shares.
The share consolidation was affected prior to the issuance of common shares and cashless warrants under the Recapitalization
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 32







| | XII. | 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 as prescribed
by IFRS nor Previous GAAP 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, boe's 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 State 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 be 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.



Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 33







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 its 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.





Management’s Discussion and AnalysisCompton Petroleum – December 31, 2011Page 34