Compton reports year-end 2009 reserves

CALGARY, Feb. 26 /CNW/ - Compton Petroleum Corporation (TSX - CMT, NYSE - CMZ) reports estimated reserve volumes together with the net present value of its reserves as at December 31, 2009. Netherland, Sewell & Associates, Inc., Compton's independent reserve evaluators, have completed an evaluation of 100% of the Corporation's petroleum and natural gas reserves as at December 31, 2009 in accordance with the provisions of National Instrument 51-101.

Summary Results:

Reserves experienced a downward revision mainly due to Compton's investment strategy of managing its capital expenditure program within available cash flow. In addition, some proved undeveloped producing and probable reserves in the Plains Belly River area were moved to the possible category until Management completes a reserve review to determine optimal drainage requirements. These technical revisions had a minor impact on reserve values. Value changes were mainly due to changes in the commodity price deck and the inclusion of a 5% overriding royalty in 2009.


    -   Total proved reserves declined by 21% while reserve
        value declined by 31% from 2008:

        -  The reserve reduction was due 52% to performance and 30% to the
           Plains Belly River reductions;

        -  The value reduction was due 58% to the change in price deck
           and 30% to the inclusion of the overriding royalty;

    -   Proved plus probable reserves declined by 24% with an associated
        value reduction of 34%:

        -  Performance accounted for 30% of the reserve reduction with 48%
           attributed to the Plains Belly River reductions;

        -  53% of the value reduction was due to the revised price deck
           with another 31% due to the inclusion of the overriding royalty;

    -   Proved reserves comprise 59% of total proved plus probable reserves,
        a slight increase from 2008;

    -   Extensions added 0.7 MMBoe to proved reserves and 2.0 MMBoe to proved
        plus probable reserves;

    -   Proved reserve life index ("RLI") is 13.6 years and proved plus
        probable RLI is 22.9 years;

    -   Average production was 20,922 boed for 2009;

    -   Undeveloped land of 595,158 net acres was valued at $63.0 million
        by an independent land evaluator; and

    -   Net asset value was $1.91 per basic common share on a proved
        basis and $4.07 per basic common share on a proved plus probable
        basis, based on the independently estimated reserve value,
        outstanding debt as of December 31, 2009 and the number of
        outstanding shares at that time.

"Our reserve valuation was impacted by lower gas price forecasts," said Tim Granger, President and Chief Executive Officer. "In addition, 2009's limited drilling activity and our management strategy to live within cash flow changed the investment profile in the reserve report, which reduced the number of undeveloped locations categorized in proved and probable reserves. A detailed review of the assets led to technical revisions to the reserves. We are confident that our year-end 2009 report represents a solid reserve evaluation that prudently reflects the value of our assets."

2009 Reserves

Summary of Estimated Reserve Volumes - Company Working Interest

                               Oil           Gas           NGL       Sulphur
    December 31,             (MBbl)        (MMcf)        (MBbl)         (MLt)
      Producing              3,688       370,386         7,184         1,770
      Non-producing             37        35,502           449            56
      Undeveloped               54        90,656         1,633           141
    Total Proved             3,779       496,544         9,266         1,966
      Probable               2,808       340,388         6,174           862
    Total Proved +
     Probable                6,587       836,932        15,440         2,828

                                  2009                        2008

                             Total        Proved         Total        Proved
    December 31,             (MBoe)            %         (MBoe)            %
      Producing             74,372           76%        87,844           71%
      Non-producing          6,459            7%         8,062            6%
      Undeveloped           16,937           17%        28,418           23%
    Total Proved            97,768          100%       124,324          100%
      Probable              66,575                      91,164
    Total Proved +
     Probable              164,343                     215,488

    (1) Forecast prices and costs; numbers may not add due to rounding.

Compton's total proved reserve base is comprised of 85% natural gas and 15% liquids. Proved producing reserves comprise 76% of total proved reserves, while total proved reserves account for 59% of the proved plus probable reserves. The Corporation has a total proved RLI of 13.6 years and a proved plus probable RLI of 22.9 years, based on current production of 19,700 boe/d.

After giving effect to property sales, production, extensions and revisions, 2009 reserves decreased by approximately 27 MMBoe or 21% on a proved basis, and 51 MMBoe or 24% on a proved plus probable basis as compared to 2008. During 2009, Compton produced 7.6 MMBoe and sold approximately 10.1 MMBoe of proved reserves.

    Reserve Reconciliation - Company Working Interest

                          Oil, NGLs & Sulphur              Natural Gas

                            Proved      Probable        Proved      Probable
    December 31,            (MBbls)       (MBbls)         (Bcf)         (Bcf)

    2008                    17,591        11,329           640           479
    Extensions                  24           216             4             7
    Improved Recovery            -             -             -             -
     Revisions                (572)       (1,238)          (90)         (102)
    Discoveries                  -             -             -             -
    Acquisitions                 -             -             -             -
    Dispositions              (679)         (415)          (13)          (42)
    Economic                  (136)          (48)           (7)           (2)
    Production              (1,217)            -           (39)            -

    2009                    15,011         9,844           497           340

                                                      Proved +
                            Proved      Probable      Probable
    December 31,             (MBoe)        (MBoe)        (MBoe)

    2008                   124,324        91,164       215,488
    Extensions                 611         1,355         1,966
    Improved Recovery            -             -             -
     Revisions             (15,530)      (18,203)      (33,733)
    Discoveries                  -             -             -
    Acquisitions                 -             -             -
    Dispositions            (2,773)       (7,346)      (10,119)
    Economic                (1,226)         (396)       (1,622)
    Production              (7,637)            -        (7,637)

    2009                    97,768        66,575       164,343

    (1) Forecast prices and costs; numbers may not add due to rounding.

Technical revisions relate to adjustments in performance forecasts based on current production profiles, lease expiries, changes in development upside based on new data obtained, and available capital. Aggregate negative technical revisions, related to December 31, 2009 reserve bookings, were 15.6 MMBoe on a proved basis and 18.1 MMBoe on a proved and probable basis.

Proved undeveloped producing reserves were reduced by 9%, primarily due to performance of producing Plains Belly River wells and High River Basal Quartz wells. Total proved reserves were reduced a total of 21%. In addition to the Belly River and Basal Quartz well performance, the number of PUD locations in the Belly River was reduced from four to two wells per section. Management took a prudent approach and reduced the current spacing, modifying the prior assumption that every section would require four wells to optimally drain reserves. As a result of Compton's reduced capital program, some proved undeveloped producing and probable reserves were moved to the possible category to better align with the timing of reserves as per the guidelines in COGEH, which are referenced in National Instrument 51-101.

Proved plus probable reserves declined by 24%. In addition to the removal of the Belly River proved undeveloped locations, the fourth well per section probable locations were removed. In aggregate, approximately 400 locations in the Plains Belly River area were eliminated, accounting for 48% of the proved plus probable reserve reduction.

    Net Present Value

                                            2009                    2008

    December 31                         Discount Rate           Discount Rate
     ($000s)                    0%           10%           15%           10%

      Producing       $  2,471,721  $    915,989  $    711,953  $  1,180,781
      Non-producing        208,483        86,224        63,808       135,560
      Undeveloped          388,983       125,285        77,757       318,235

    Total Proved      $  3,015,186  $  1,127,499  $    853,518  $  1,634,575
      Probable           1,840,044       567,018       368,029       934,202
    Total Proved +
     Probable         $  4,855,230  $  1,694,516  $  1,221,547  $  2,568,777

    (1) Forecast prices and costs; before income taxes; numbers may not add
        due to rounding.

Future net revenues are calculated based upon estimated revenue less royalties, operating costs, future development costs, and well abandonment costs. Estimated income taxes have not been deducted. The net present value should not be considered the current market value of Compton's reserves or the costs that would be incurred to obtain equivalent reserves.

At December 31, 2009, future net revenue from Compton's reserves decreased 31% from year-end 2008 on a total proved basis and 34% on a total proved and probable basis, discounted at 10%. The decrease in proved valuation is primarily due to the change in forecasted prices between the two years (58%) and the inclusion of the overriding royalty (30%). On a proved plus probable basis, these factors account for 53% and 31% of the decrease, respectively.

Price forecasts as of December 31, 2009 used in the above evaluation are the Consultants' Average of four major engineering firms in Calgary, Alberta: Sproule, GLJ, AJM and McDaniels.

Forecast Pricing, Inflation Rate, and Exchange Rate Assumptions*

                        Crude Oil   Natural Gas    Inflation      Exchange

                      Edmonton Par  AECO C Spot
                       ($Cdn/Bbl)  ($Cdn/MMbtu)     %/year        $Cdn/$US
    2010                 82.06          5.79         2.00%          0.94
    2011                 86.96          6.61         2.00%          0.94
    2012                 90.52          6.88         2.00%          0.94
    2013                 94.35          7.27         2.00%          0.94
    2014                 98.57          7.60         2.00%          0.94
    2015                102.58          7.80         2.00%          0.94
    2016                106.12          8.02         2.00%          0.94
    2017                108.26          8.32         2.00%          0.94
    2018                110.42          8.62         2.00%          0.94
    2019                112.65          8.84         2.00%          0.94
    2020                114.91          9.04         2.00%          0.94
     escalating at:       2.0%          2.0%         2.00%          0.94

    * as at December 31, 2009

    Future Development Costs

                                                              Proved Plus
                                     Proved                     Probable
                                    Forecast                    Forecast
                                   Prices and                  Prices and
                                   Costs/Year                  Costs/Year
    Year                             ($000s)                     ($000s)
      2010                            34,549                      73,200
      2011                            40,231                     112,712
      2012                            45,088                     145,199
      2013                            33,830                     178,347
      2014                            10,499                      73,022
      Remaining                       39,364                      70,866
    Total undiscounted               203,561                     653,347
    Total discounted @
     10% per year                    149,589                     484,541

    * Includes abandonment costs. Numbers may not add due to rounding.

Based on forecast prices, Compton estimates that its internally generated cash flow will be sufficient to fund the future development costs disclosed above. Compton typically has available three sources of funding to finance its capital expenditure program: (i) internally generated cash flow from operations; (ii) debt financing when appropriate; and (iii) new equity issues, if available on favourable terms. Compton does not expect that the costs of funding its capital expenditures will have a material effect on the economics of the programs.

Undeveloped Land

Compton had a total of 595,158 net acres of undeveloped land at December 31, 2009. Total land decreased from 2008 due to land expiries in areas viewed as less prospective by the Corporation, the majority of which was near the United States border. Based on the evaluation completed by "Independent Land Evaluations Inc.", this acreage is valued at $63.0 million. This amount is not included in the reserves evaluation.



Non-GAAP Financial Measures

Included in this document are references to terms used in the oil and gas industry such as cash flow. 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.

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 the results of its reserve evaluation. 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 Plains Belly River sand play in southern Alberta. In addition, we have an exploratory play at Callum/Cowley in the Foothills area of southern Alberta. 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, Fax: (403) 237-9410, Email:, Website:

Organization Profile

MFC Energy Corporation

More on this organization

Custom Packages

Browse our custom packages or build your own to meet your unique communications needs.

Start today.

CNW Membership

Fill out a CNW membership form or contact us at 1 (877) 269-7890

Learn about CNW services

Request more information about CNW products and services or call us at 1 (877) 269-7890