COMPTON REPORTS YEAR-END 2010 RESULTS

CALGARY, Feb. 24 /CNW/ - Compton Petroleum Corporation (TSX: CMT) reports its financial and operating results for the year ended December 31, 2010. The Corporation's 2010 reserves evaluation results are provided in a separate release, disseminated to the market today.

The full text of Management's Discussion and Analysis ("MD&A") and the Corporation's audited consolidated financial statements can be found on the Corporation's website at www.comptonpetroleum.com and at www.sedar.com.

2010 in Review

Summary of Results:

    <<
    -   Cash flow was $42.8 million or $0.16 per diluted share
    -   Operating loss was $75.6 million, including a $502.9 million expense
        for depletion and depreciation
    -   Net loss was $330.9 million or $1.26 per diluted share, including a
        $367.0 million ceiling test write-down of assets due substantially
        lower natural gas prices
    -   Capital expenditures were $46.3 million, before acquisitions and
        divestitures

    Achievements:

    -   Met or exceeded annual guidance targets
    -   Average daily production was 17,402 boe/d
        -  Operational improvements largely mitigated natural declines: exit
           rates in 2010 decreased approximately 8% over 2009 after adjusting
           for dispositions
    -   Reduced operating and administrative expenses by a combined $24.3
        million from 2009
        -  Operating expenses were $66.1 million, which was 21% below 2009
           expenses
        -  Operating costs per boe were $10.41, which was below the 2009
           average of $11.07 per boe despite lower production
        -  Administrative expenses decreased by 21% to $22.7 million compared
           to 2009
    -   Substantially improved capital efficiencies:
        -  Improved drilling methods at Niton, resulting in approximately 25%
           higher average initial production rates and 15% to 20% lower
           drilling costs over the previous year
        -  Base volume performance was 5% or 870 boe/d higher than
           expectations due to production optimization
        -  Reinitiated development programs in High River with the refracture
           of two wells, resulting in combined average production of 450
           Mcf/d, which was 4.5-times previous levels
    -   Achieved a 80% success rate on the 31 wells drilled or participated
        in during the year
    -   Increased production rates at Niton: a Rock Creek well drilled during
        the fourth quarter had an initial test rate of 5.5 MMcf/d with 30
        bbl/MMcf of liquids. The well is currently on production at
        approximately 3.3 MMcf/d and 35 bbl/MMcf of liquids
    -   Successfully drilled a Spirit River vertical well in Niton that was
        brought on production at 1 MMcf/d. The results from this well support
        further development in the Spirit River Formation, reinforcing
        Niton's multi-zone potential
    -   Initiated oil prospect drilling with an Ellerslie well in the
        Southern Plains, which is awaiting completion. Initial indications
        are promising with approximately 700 metres of pay being encountered
        in the wellbore
    -   Completed the sale of $150.2 million in assets at Niton and Gilby
    -   Completed an exchange of existing Senior Term Notes (the "Notes")
        for a combination of cash from proceeds of asset sales and new term
        notes
    -   Reduced total Credit Facility (the "Facility") and Notes by 33% or
        $186.1 million compared to year-end 2009
    -   Renewed the Facility to an authorized credit limit of $170.0 million
        at December 31, 2010
    >>

Financial Review

    <<

                          Three Months Ended Dec 31       Year Ended Dec 31
    (000s, except per -------------------------------------------------------
     share amounts)              2010         2009         2010         2009
    -------------------------------------------------------------------------
    Total revenue          $   43,917   $   57,595   $  216,069   $  227,876
    Cash flow(1)(2)(3)     $    2,644   $    6,513   $   37,258   $   45,439
    Per share - basic      $     0.01   $     0.03   $     0.14   $     0.29
            - diluted      $     0.01   $     0.03   $     0.14   $     0.29
    Operating earnings
     (loss)(1)(2)          $  (28,574)  $  (25,509)  $  (75,576)  $  (59,592)
    Net earnings (loss)(4) $ (291,212)  $  (23,800)  $ (330,854)  $   (8,330)
    Per share - basic      $    (1.10)  $    (0.09)  $    (1.26)  $    (0.05)
            - diluted      $    (1.10)  $    (0.09)  $    (1.26)  $    (0.05)
    Capital expenditures
     before acquisitions
     and divestments       $   19,107   $   30,726   $   46,309   $   68,303

    As at                                         Dec. 31, 2010 Dec. 31, 2009
                                              -------------------------------
    Total Facility & Notes                           $  382,796   $  568,924
    Shareholders equity                              $  664,035   $  992,237
    Shares outstanding                                  263,579      263,573

    (1) Cash flow and operating earnings (loss) are non-GAAP measures and are
        addressed in detail in the 'Advisories' section
    (2) Prior periods have been revised to conform to current period
        presentation
    (3) 2010 includes non-recurring costs of $14.3 million related to
        terminated office lease costs
    (4) A $367.0 million ceiling test impairment on petroleum and natural gas
        assets was recorded at December 31, 2010
    >>

Revenue decreased in 2010 compared to 2009 due to reduced production volumes. Cash flow for 2010 decreased 18% for the same reason as well as the impact of the costs of terminated office leases and an increase in asset retirement expenditures. Compton reported a net loss for 2010 of $330.9 million versus a loss of $8.3 million in 2009 largely due to a ceiling test impairment of $367.0 million on petroleum and natural gas assets in 2010, due to a reduction in the estimated discounted cash flows of proved plus probable reserves.

Operating loss increased by 27% from $59.6 million in 2009 to a loss of $75.6 million in 2010 primarily due to higher depletion and depreciation as a result of the ceiling test impairment. Operating earnings is a non-GAAP measure that adjusts net earnings by non-operating items that, in Management's opinion, reduces the comparability of underlying financial performance between periods. These non-operating items are largely non-cash in nature or one-time non-recurring items, and include those referred to above.

The low natural gas price environment experienced throughout 2010 and reduced production volumes continued to impact the amount of internally generated cash flow available to invest in drilling activities. As a result, capital spending, before acquisitions, divestitures and corporate expenses decreased by 32% in 2010. Despite this reduction, the Corporation drilled or participated in 31 wells in 2010 (drilled 18: participated 13) as compared to 20 in 2009 (drilled 6: participated 14). Other factors that influenced 2010 capital expenditures included the reduced costs of drilling, the deferral of capital expenditures as a result of weather related constraints, the implementation of the Alberta Drilling Credit program in 2010, and higher asset retirement costs.

Capital spending during the year was primarily directed towards the drilling and/or completion of 13 horizontal multi-stage fracture wells in Niton and the development of natural gas plays in the Southern Plains. Funds were also allocated to the refracture of two wells in High River.

Fourth Quarter

During the fourth quarter of 2010 revenue decreased 24% compared to the same period in 2009 due to a 23% decrease in production, which reflects the sale of a portion of the Corporation's Niton and its Gilby assets, as well as natural declines.

Although fourth quarter 2009, cash flow and operating earnings were unfavourably impacted by lower production volumes, this was partially offset by reductions in operating, interest and administrative expenses.

Operations Review

    <<
                       Three Months Ended Dec 31        Year Ended Dec 31
                      -------------------------------------------------------
                                              %                           %
                          2010      2009   Change     2010      2009   Change
    -------------------------------------------------------------------------
    Average daily
     production
      Natural gas
       (MMcf/d)             75        98    (23%)       88       106    (17%)
      Liquids
       (bbls/d)          2,411     3,055    (21%)    2,791     3,335    (16%)
    -------------------------------------------------------------------------
      Total (boe/d)     14,852    19,351    (23%)   17,402    20,922    (17%)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Realized prices
      Natural gas
       ($/mcf)        $   3.87  $   4.38    (12%) $   4.43  $   4.16      7%
      Liquids
       ($/bbl)        $  69.30  $  57.10     21%  $  65.71  $  49.79     32%
    -------------------------------------------------------------------------
    Total ($/boe)     $  30.70  $  31.16     (1%) $  32.87  $  28.90     14%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Field
     netback(1)(2)
     ($/boe)          $  22.74  $  15.63     45%  $  19.68  $  18.35      7%
    -------------------------------------------------------------------------
    (1) Field netback is a non-GAAP measures and is addressed in detail in
        the MD&A
    (2) Prior periods have been revised to conform to current period
        presentation
    >>

Production for 2010 decreased 17% from 2009 largely due to asset sales. Natural declines and limited capital expenditures impacted the Corporation's ability to grow. Excluding dispositions, Compton largely replaced production in 2010 with year-end exit rates decreasing by 8% from 2009 levels, despite the reduced capital expenditure program.

The evaluation and technical property analysis that was completed in late 2009 and early 2010 resulted in strong results for the Corporation, emphasizing the underlying value of Compton's asset base. Operational activities in 2010 included longer horizontal sections (20% increase), higher initial production rates (25% increase), reduced drilling costs (15% to 20% decrease) and lower operational costs (21% decrease) than experienced in 2009. Despite lower than anticipated commodity prices, improved efficiencies enabled the Corporation to execute its drilling plans and further develop the potential of its asset base.

Compton expanded its opportunity base by drilling into new formations and applying new technologies to existing areas. In 2010, the Corporation tested formations above and below the Rock Creek Formation in Niton, refractured two wells in High River with strong results, and drilled one oil well targeting the Ellerslie Formation in the Southern Plains.

The continued strength from operations in the Niton area was the major contributor to sustained volumes. The strong drilling and economic results achieved in 2009 continued into 2010, resulting in volume performance that exceeded expectations. In addition, the Corporation's focus on internal cost reduction and improved drilling techniques resulted in higher initial production rates than previously experienced and well costs that were 15% to 20% lower than previous horizontal multi-stage fractured wells drilled in the area. Overall, Compton drilled six Rock Creek wells during 2010 with strong results. The most recent Rock Creek well drilled during the fourth quarter had an initial test rate of 5.5 MMcf/d with 30 bbl/MMcf of liquids. The well is currently on production at approximately 3.3 MMcf/d and 35 bbl/MMcf of liquids.

Compton initiated the drilling of other Niton formations such as the Spirit River during 2010 with encouraging results. The Spirit River vertical well was completed and brought on production at 1 MMcf/d. The results from this well support further development in the Spirit River Formation, reinforcing Niton's multi-zone potential.

At High River, 2010 activities were focused on transferring the knowledge and efficiencies gained at Niton to the Basal Quartz area to improve economics in the area. Two Basal Quartz vertical wells were refractured late in the year, resulting in combined average production of 450 Mcf/d, which was 4.5-times previous levels. As the cost to refracture wells is considerably less than drilling, the economic return of production gains through refracturing is significant. With this success, additional refracture locations may be identified from the inventory of over 100 producing vertical wells in the area. In addition, one new horizontal well was drilled in the formation late in 2010, although it was later abandoned due to drilling issues.

In addition to drilling six successful Belly River Formation wells in the Southern Plains area, Compton expanded its focus to new horizons during the year. One Glauconite drill yielded an initial rate of 1.5 MMcf/d and two Glauconite recompletions averaged 0.75 MMcf/d. With this success, Compton will focus its investment on deeper targets in the Southern Plains, providing additional opportunities for the Corporation. In addition, a horizontal oil well was drilled late in the fourth quarter targeting the Ellerslie Formation. Initial results are promising and Compton is in the process of completing the well, anticipating results by the end of the first quarter of 2011.

In the Foothills area, Compton drilled two gas wells in Cowley that targeted the thrusted Belly River Formation. Results were lower than expected although one zone produced oil, which resulted in initial production of 40 bbl/d. After evaluation, Compton may consider pursuing this oil zone horizontally.

In 2010, the Alberta Bakken Fairway, which runs through Alberta and Montana, garnered much attention by companies such as Shell, Murphy, Rosetta and Newfield. Compton holds 123 net sections of land in Montana as well as 25 net sections in the Southern Plains area around Okotoks. Further exploration and evaluation of this area is necessary to determine the potential of this play. Compton intends to continue the preliminary evaluation of the area that was begun in the fourth quarter of 2010 in order to determine potential next steps. A test well targeting the Alberta Bakken Formation in Southern Plains is planned in 2011 to evaluate the potential of this zone.

Operating Efficiency Program

Compton successfully improved its operating efficiencies over 2010 through its focus on cost optimization and operational reliability. As a result, Management further reduced operating costs by an additional $13.9 million below 2010 operating cost guidance. Operating expenses for 2010 were $66.1 million, which is a reduction of 21% below 2009 expenses. This translates into unit operating costs of $10.41/boe, a 6% decrease over $11.07/boe in 2009.

Compton will continue to implement programs to identify cost savings across its operations.

2011 Capital Program

In 2011, operational activities will be concentrated on those areas that provide the highest economic return or that will help identify additional future development opportunities for the Corporation. Compton will focus primarily on liquids-rich, high return natural gas in Niton, and on developing its emerging oil prospects. At Niton, Compton will focus on drilling several Rock Creek wells as well as testing other zones including the Ellerslie, Cardium (oil), Notikewan and Spirit River Formations. Success in these formations would provide additional potential for growth. In the Southern Plains, the Corporation expects to drill additional Ellerslie Formation oil wells as well as a test well targeting the Alberta Bakken Formation to evaluate the potential of this zone. Should a recovery in natural gas prices occur, additional activities may be considered with increases in available capital.

Based on forecast natural gas prices, Compton anticipates that it will invest between $70 and $75 million in capital development in 2011, utilizing available cash flow and funds from other sources. This level of expenditure is expected to largely maintain production, after accounting for 2010 dispositions. With drilling more focused on oil in 2011, the Corporation expects its production to shift towards oil. Success with 2011 oil development could result in a significant shift to oil projects in 2012. Management will monitor economic conditions as they develop and adjust the capital program accordingly.

The planned allocation of 2011 capital program is as follows:

    <<
    By Area (excluding Corporate* portion)
    (%)
      Niton - Central Alberta                                             50%
      High River - Southern Alberta                                        -
      Southern River - Southern Alberta                                   36
      Foothills (Callum, Cowley, Todd Creek) - Southern Alberta            7
      Other properties                                                     7
    -------------------------------------------------------------------------
                                                                         100%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    * Corporate includes funds used for information technology and office
        improvements

    Drilling & Completions
    (gross wells)
      Niton - Central Alberta                                             13
      High River - Southern Alberta                                        -
      Southern River - Southern Alberta                                    7
      Foothills (Callum, Cowley, Todd Creek) - Southern Alberta            1
      Other properties                                                     1
    -------------------------------------------------------------------------
                                                                          22
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    >>

Outlook

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

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

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

    <<
    -------------------------------------------------------------------------
    Average daily production (boe/d)                          13,250 - 13,750
    Administrative expenses ($ millions)                        $15.5 - $16.5
    Operating costs(1) ($ millions)                             $47.0 - $50.0
    Cash flow(2) ($ millions)                                   $27.0 - $30.0
    Capital expenditures(3) ($ millions)                        $70.0 - $75.0
    2011 Pricing:
      Natural gas - AECO (Cdn$/GJ)                                      $3.58
      Crude oil - Edmonton Sweet (Cdn$/bbl)                            $89.43
      Exchange rate(Cdn$/US$)                                           $1.01
    (1) Net of $11.7 million of gas cost allowance
    (2) A $0.25 change in the AECO natural gas price is expected to result in
        a $2.5 million change in cash flow
    (3) Includes development and corporate capital expenditures; total
        capital expenditure amount is dependent upon available capital above
        cash flow
    >>

To reduce cash flow volatility, Compton will continue its hedging program with approximately 50% of production expected to be hedged to the middle of 2011, with a portion hedged to October 2011. Management is focused on identifying additional hedging opportunities as they appear. Should additional funds become available due to better than projected natural gas prices or reductions in the Corporation's cost structure, Management will consider allocating funds to further reduce debt or increase capital expenditures as appropriate.

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

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

Additional Information

Compton has filed its audited Consolidated Financial Statements for the year ended December 31, 2010 and related Management's Discussion and Analysis with Canadian securities regulatory authorities. Copies of these documents may be obtained via www.sedar.com or the Corporation's website, www.comptonpetroleum.com. To order printed copies of the filed documents free of charge, email the Corporation at investorinfo@comptonpetroleum.com.

2010 Year-End Conference Call

Compton will host a conference call and web cast on Friday, February 25, 2011 at 8:00 a.m. MST (10:00 a.m. EST) to discuss the Corporation's 2010 financial, operating and reserves results. The format of the call will be as a question and answer session for analysts and investors after a brief summary of results and strategy. To participate in the conference call, please contact the Conference Operator ten minutes prior to the call at 1-888-231-8191 or 1-647-427-7450. To participate in the web cast, please visit: www.comptonpetroleum.com. The web cast will be archived two hours after the presentation at the website listed above. For a replay of this call, please dial: 1-800-642-1687 or 1-416-849-0833 and enter access code 45132684No. until March 4, 2011.

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, cash flow per share, adjusted EBITDA, field netback, funds flow netback, debt and capitalization. Non-GAAP measures do not have any standardized meaning and therefore reported amounts may not be comparable to similarly titled measures reported by other companies. These measures have been described and presented in this document in order to provide shareholders and potential investors with additional information regarding the Company's liquidity and its ability to generate funds to finance its operations.

Cash flow should not be considered an alternative to, or more meaningful than, cash provided by operating, investing and financing activities or net earnings as determined in accordance with Canadian GAAP, as an indicator of the Corporation's performance or liquidity. Cash flow is used by Compton to evaluate operating results and the Corporation's ability to generate cash to fund capital expenditures and repay debt.

Operating earnings (loss) is used by the Corporation to facilitate comparability of earnings between periods. Operating earnings (loss) represents net earnings excluding certain items that are largely non-operational in nature, primarily of a non-cash nature or one-time non-recurring items, and should not be considered an alternative to, or more meaningful than, net earnings as determined in accordance with Canadian GAAP.

Adjusted EBITDA is a non-GAAP measure defined as net earnings, before interest and finance charges, income taxes, depletion and depreciation, accretion of asset retirement obligations, and foreign exchange and other gains and losses.

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 including general and administrative costs and interest costs. Field netback and funds flow netback are non-GAAP measures that management uses to analyze operating performance.

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.

Debt is comprised of floating rate bank debt and fixed rate senior term notes. Capitalization is defined as bank debt plus shareholder's equity.

Use of Boe Equivalents

The oil and natural gas industry commonly expresses production volumes and reserves on a barrel of oil equivalent ("boe") basis whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. The intention is to sum oil and natural gas measurement units into one basis for improved measurement of results and comparisons with other industry participants. We use the 6:1 boe measure which is the approximate energy equivalency of the two commodities at the burner tip. However, boes do not represent a value equivalency at the 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. Forward-looking statements include estimates, plans, expectations, opinions, forecasts, projections, guidance, or other statements that are not statements of fact, including statements regarding (i) cash flow and capital and operating expenditures, (ii) exploration, drilling, completion, and production matters, (iii) results of operations, (iv) financial position, and (v) other risks and uncertainties described from time to time in the reports and filings made by Compton with securities regulatory authorities. Although Compton believes that the assumptions underlying, and expectations reflected in, such forward-looking statements are reasonable, it can give no assurance that such assumptions and expectations will prove to have been correct. There are many factors that could cause forward-looking statements not to be correct, including risks and uncertainties inherent in the Corporation's business. These risks include, but are not limited to: crude oil and natural gas price volatility, exchange rate fluctuations, availability of services and supplies, operating hazards, access difficulties and mechanical failures, weather related issues, uncertainties in the estimates of reserves and in projection of future rates of production and timing of development expenditures, general economic conditions, and the actions or inactions of third-party operators, and other risks and uncertainties described from time to time in the reports and filings made with securities regulatory authorities by Compton. Statements relating to "reserves" and "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future.

The forward-looking statements contained herein are made as of the date of this news release solely for the purpose of generally disclosing Compton's views of its financial and operational results as of December 31, 2010, and prospective activities. Compton may, as considered necessary in the circumstances, update or revise the forward-looking statements, whether as a result of new information, future events, or otherwise, but Compton does not undertake to update this information at any particular time, except as required by law. Compton cautions readers that the forward-looking statements may not be appropriate for purposes other than their intended purposes and that undue reliance should not be placed on any forward-looking statement. The Corporation's forward-looking statements are expressly qualified in their entirety by this cautionary statement.

About Compton Petroleum Corporation

Compton Petroleum Corporation is a public company actively engaged in the exploration, development and production of natural gas, natural gas liquids, and crude oil in western Canada. Our strategy is focused on creating value for shareholders by providing appropriate investment returns through the effective development and optimization of assets. The majority of the Corporation's operations are located in the Deep Basin fairway of the Western Canada Sedimentary Basin. In this large geographical region, we pursue four deep basin natural gas plays: the Rock Creek sands at Niton in central Alberta, the Basal Quartz sands at High River in southern Alberta, the shallower Southern Plains sand play in southern Alberta and an exploratory play at Callum/Cowley in the Foothills area of southern Alberta. Being in the Deep Basin, all areas have multi-zone potential, providing future development and exploration opportunity. We are also focusing on developing our emerging oil potential in the Southern Plains area and in the Montana lands. Natural gas represents approximately 84% of production. Compton's shares are listed on the Toronto Stock Exchange under the symbol CMT.

SOURCE Compton Petroleum Corporation

For further information: Susan J. Soprovich, Director, Investor Relations, Ph: (403) 668-6732; C.W. Leigh Cassidy, Vice President, Finance & CFO, Ph: (403) 205-5812; Fax: (403) 237-9410, Email: investorinfo@comptonpetroleum.com, Website: www.comptonpetroleum.com

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