Compton reports first quarter 2010 results

CALGARY, May 12 /CNW/ - Compton Petroleum Corporation (TSX - CMT, NYSE - CMZ) reports its financial and operating results for the first quarter ended March 31, 2010.

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, at and at

Q1 2010 in Review

Summary of Results:

    -   Cash flow was $20.4 million or $0.08 per diluted share
    -   Operating loss was $4.8 million or $0.02 per diluted share
    -   Net earnings were $17.0 million or $0.06 per diluted share
    -   Capital expenditures were $14.5 million, before acquisitions and


    -   Strengthened capital structure through further debt reduction
        compared to December 31, 2009:
        -  Bank debt decreased by 15% to $90.7 million
        -  Total bank debt and senior notes decreased by 5% to $539.0 million
    -   Average production was 19,411 boe/d, which was comparable to 19,351
        boe/d for the fourth quarter of 2009
    -   Reduced internal cost structures through focused cost control
        initiatives as compared to the first quarter of 2009:
        -  Operating expenses decreased by 15% or $3.3 million
        -  Administrative expenses decreased by 8% or $0.5 million
    -   Reduced operating costs per boe to $10.53 per boe versus $11.29 per
        boe for 2009 (full year average), despite production declines
    -   Improved average initial production rates of horizontal multi-stage
        fractured wells at Niton while reducing drilling costs

Throughout the first quarter of 2010, Management maintained its philosophy of living within cash flow, taking a prudent approach in its capital investment decisions and focusing its development strategy to optimize asset value, emphasize cost reduction, and carefully manage its capital structure. Compton focused its field activities on optimizing production from existing wells and drilling processes in order to improve operating efficiencies and well economics.

"The first quarter operating results have exceeded our expectations due to improved well performance and lower costs," said Tim Granger, President and Chief Executive Officer. "As a result, we expect to be at the upper end of our volume guidance with lower capital, operating and administrative costs than anticipated. Our efforts over the past quarters to realign business processes are now being realized, resulting in improved capital efficiencies for our shareholders. We expect that continued work throughout the remainder of 2010 will further demonstrate the value of our asset base."

Financial Review

                                                  Three Months Ended Mar. 31
    (000s, except per share amounts)            2010        2009    % Change

    Total revenue                         $   71,267  $   68,899          3%
    Cash flow(1)(2)                       $   20,350  $   22,041         (8%)
    Per share - basic(1)(2)               $     0.08  $     0.18        (55%)
              - diluted(1)(2)             $     0.08  $     0.18        (55%)
    Operating loss(1)(2)                  $   (4,773) $   (2,904)       (64%)
    Net earnings (loss)                   $   16,957  $  (17,368)       198%
    Per share - basic                     $     0.06  $    (0.14)       143%
              - diluted                   $     0.06  $    (0.14)       143%
    Capital expenditures before
     acquisitions and divestments         $   14,496  $   16,639        (13%)

                                             Mar. 31,    Dec. 31,
    As at                                       2010        2009    % Change
    Total bank debt & senior notes        $  539,029  $  568,924         (5%)
    Shareholders equity                   $1,009,540  $  992,237          2%
    Shares outstanding                       263,573     263,573           -

    (1) Prior periods have been revised to conform to current period
    (2) Cash flow and operating loss are non-GAAP measures and are addressed
        in detail in the MD&A

Revenue increased in the first quarter of 2010 due to higher realized commodity prices, particularly liquids prices, despite reduced sales volumes compared to the first quarter of 2009. The reduction in sales volumes also impacted cash flow, which was 8% lower in the first quarter of 2010 compared to the same period in 2009.

Net earnings increased in 2010 to $17.0 million from a loss of $17.4 million in the first quarter of 2009 due to non-cash unrealized foreign exchange and risk management gains. Operating loss increased in the first quarter of 2010 compared to 2009 due to reduced production volumes and depletion and depreciation expenses.

Capital spending, before acquisitions and divestitures, decreased by 13% in the first quarter of 2010 compared with the first quarter of 2009. Capital spending was somewhat lower than anticipated for the quarter, largely due to the reduced cost of drilling and the deferral of some drilling into the second quarter of 2010. The majority of the drilling capital was focused on horizontal multi-stage fracture wells in Niton and Gilby. The Corporation drilled or participated in 13 wells over the quarter as compared to nine wells in 2009.

Operations Review

                                                Three Months Ended Mar. 31
                                                2010        2009    % Change

    Average daily production
      Natural gas (MMcf/d)                        97         117        (17%)
      Liquids (bbls/d)                         3,237       3,655        (11%)
      Total (boe/d)                           19,411      23,194        (16%)

    Realized prices
      Natural gas ($/mcf)                 $     5.67  $     5.18         10%
      Liquids ($/bbl)                     $    67.59  $    38.35         76%
      Total ($/boe)                       $    39.62  $    32.20         23%
    Field netback (1) ($/boe)             $    22.47  $    20.75          8%
    (1) Field netback is a non-GAAP measures and is addressed in detail in
        the MD&A

Production volumes for the first three months of 2010 were 16% lower than in 2009 primarily due to natural declines, limited development in 2009 and minor property dispositions. First quarter 2010 volumes were relatively stable at 19,411 boe/d compared to 19,351 boe/d for the fourth quarter of 2009.

The excellent drilling and economic results achieved in Niton in the fourth quarter of 2009 continued into the first quarter of 2010. Five Rock Creek wells (4.6 net to the Corporation) were brought on production in the first quarter. The average initial first month rates were 2.3 MMcf/d per well plus in excess of 26 bbls of condensate per MMcf of gas, which exceeded the expectations of 1.9 MMcf/d. These better than predicted initial production rates coupled with strong base performance resulted in the quarter's volumes exceeding budget by more than 1,300 boed. At an average capital cost of $3.3 million per well, Compton's Niton investments are generating a 25% pre-tax rate-of-return (before drilling credits) and a recycle ratio of 2.3 at current realized commodity prices. With the successful drilling program, volumes were held constant from last quarter.

Compton reduced individual well drilling costs by 15% to 20% compared to historic drilling programs while increasing the length of the horizontal sections. The average horizontal section is now 1,030 metres compared to 860 metres, which resulted in better well performance. For the remainder of the year, drilling in Niton will continue as per plan with approximately three gross wells to be drilled by year-end. In addition, following an analysis of Compton's Cardium rights at Niton, the Corporation plans to drill three Cardium wells in the third quarter of 2010 to further evaluate the area potential.

The shift in focus to deeper, higher rate targets in the Southern Plains area (formally known as Plains Belly River) has commenced with three successful operations. One Glauconite drill and two Glauconite recompletions yielded better than anticipated results. The drill had an initial rate of 1.5 MMcf/d and the recompletions averaged 0.75 MMcf/d. With this success, Compton will continue to focus its investment on deeper targets in the Southern Plains, providing additional opportunities for the Corporation. Drilling in the Belly River Formation commenced in the first quarter and continues with six wells to be completed and tied-in during the second quarter of 2010.

At High River, refracture and drilling programs targeting the Basal Quartz sand are scheduled for the third quarter. Knowledge and efficiencies gained from horizontal drilling in Niton will be applied to High River, which is expected to result in wells with more favourable economics. Additionally, surface acquisition is well underway for wells in the Callum/Cowley/Todd Creek Foothills area. Drilling of three wells is planned for the second half of the year in the Foothills area.

Despite lower than anticipated commodity prices, improved efficiencies have enabled the Corporation to maintain its drilling plans. Compton anticipates that its 2010 development capital expenditure program may range between $50 and $60 million, depending on the natural gas forward strip price. Including corporate costs, a total capital budget of between $60 and $70 million is now anticipated for 2010. The volume guidance of 17,900 boed to 18,500 boed remains intact with the current forecast at the high end of guidance despite less capital being deployed. Compton's drilling program is benefiting from the higher than anticipated volumes and initial production rates as well as reduced costs, allowing the Corporation to continue its program despite lower realized natural gas prices.

Compton's operating costs benefited in the first quarter of 2010 as a result of implemented cost reductions. Operating costs were $10.53 per boe for the first quarter in 2010 compared to $11.29 per boe for the full year of 2009. Compton continued to focus on targeting cost optimization and maximizing reliability during the quarter. As a result, progress is being realized towards Management's internal target to further reduce operating costs by an additional $10 million (annualized) beyond 2010 guidance of $80 to $85 million.


The current level of activity and storage levels of natural gas in North America continues to affect the price for natural gas. Management believes this to be at a low point of the price cycle. Within this economic environment, cash flows are expected to remain below normalized levels. Management will maintain its philosophy of living within cash flow, taking a prudent approach in its capital investment decisions and focusing its development strategy to optimize asset value, emphasize cost reduction, increase drilling economics and carefully manage its capital structure.

Compton's cash flow is expected to benefit from higher than anticipated volumes and initial production rates as well as reduced costs, which are expected to somewhat offset the impact of lower natural gas prices. While capital expenditure guidance exceeds expected cash flow at this time, Management will monitor these two areas throughout 2010 and adjust when there is more clarity. Actual capital expenditures will depend on production volume, natural gas prices and internal efficiencies, and will be modified according to cash flow generated from operations and other sources.

Compton's guidance for 2010 anticipated natural gas prices of $6.00/GJ (AECO) compared to Management's current expectations of $4.70/GJ (AECO). As a result, the following update is made to Compton's guidance for 2010:

                                       Revised Guidance    Previous Guidance
    Average daily production (boe/d)   Top of range        17,900 - 18,500
    Administrative expenses
     ($ millions)                      Lower end of range  $25 - $27
    Operating costs ($ millions)       Lower end of range  $80 - $85
    Cash flow ($ millions)             $40 - $50           $70 - $80
    Capital expenditures*
     ($ millions)                      $60 - $70           $70 - $80

    * Capital expenditures will be adjusted according to cash flow
        generated from operations and other sources.

Compton's updated 2010 guidance is based on forecast prices of $4.70/GJ of natural gas (AECO), $78.39 per barrel of crude oil (Edmonton Sweet Light), and a foreign exchange rate of $0.99. A $0.25 change in the AECO natural gas price is expected to result in a $6.3 million change in cash flow.

Management is progressing with identifying further steps to reduce debt. Compton will selectively enter into transactions that de-lever the balance sheet to improve capital structure and reduce overall financial risk.

Over the past two quarters, Compton has demonstrated that its large focused asset base can provide solid growth potential as evidenced by the results of newly completed horizontal multi-stage fractured wells at Niton. The Corporation has shown improved results operationally, exemplifying its ability to strengthen efficiencies and economics. Compton is positioning itself for growth in production and cash generation. Through its activities in 2010, Compton expects to identify new opportunities, realize the underlying value of its properties and deliver long-term value to its shareholders.


Additional Information

Compton has filed its Consolidated Financial Statements for the three months ended March 31, 2010 and related Management's Discussion and Analysis with Canadian securities regulatory authorities. Copies of these documents may be obtained via, or the Corporation's website, To order printed copies of the filed documents free of charge, email the Corporation at

2010 First Quarter Conference Call

Compton will host a conference call and webcast on Thursday, May 13, 2010 at 8:00 a.m. MST (10:00 a.m. EST) to discuss the Corporation's 2010 first quarter financial and operating results. 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 webcast, please visit: The webcast 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 72589654 followed by the pound sign until May 20, 2010.


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 March 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 Corporation's operations are located in the Deep Basin fairway of the Western Canada Sedimentary Basin. In this large geographical region, we pursue three deep basin natural gas plays: the Gething/Rock Creek sands at Niton and Gilby in central Alberta, the Basal Quartz sands at High River in southern Alberta, and the shallower Southern Plains sand play in southern Alberta. In addition, we have 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. Natural gas represents approximately 84% of reserves and production. Compton's shares are listed on the Toronto Stock Exchange under the symbol CMT and on the New York Stock Exchange under the symbol CMZ.

%CIK: 0001043572

SOURCE MFC Energy Corporation

For further information: 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:, Website:

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