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
2009
Natural
Oil Gas NGL Sulphur
December 31, (MBbl) (MMcf) (MBbl) (MLt)
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Proved
Producing 3,688 370,386 7,184 1,770
Non-producing 37 35,502 449 56
Undeveloped 54 90,656 1,633 141
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Total Proved 3,779 496,544 9,266 1,966
Probable 2,808 340,388 6,174 862
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Total Proved +
Probable 6,587 836,932 15,440 2,828
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2009 2008
Total Proved Total Proved
December 31, (MBoe) % (MBoe) %
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Proved
Producing 74,372 76% 87,844 71%
Non-producing 6,459 7% 8,062 6%
Undeveloped 16,937 17% 28,418 23%
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Total Proved 97,768 100% 124,324 100%
Probable 66,575 91,164
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Total Proved +
Probable 164,343 215,488
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(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)
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2008 17,591 11,329 640 479
Extensions 24 216 4 7
Improved Recovery - - - -
Technical
Revisions (572) (1,238) (90) (102)
Discoveries - - - -
Acquisitions - - - -
Dispositions (679) (415) (13) (42)
Economic (136) (48) (7) (2)
Production (1,217) - (39) -
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2009 15,011 9,844 497 340
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Total
Proved +
Proved Probable Probable
December 31, (MBoe) (MBoe) (MBoe)
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2008 124,324 91,164 215,488
Extensions 611 1,355 1,966
Improved Recovery - - -
Technical
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)
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2009 97,768 66,575 164,343
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(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%
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Proved
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
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Total Proved $ 3,015,186 $ 1,127,499 $ 853,518 $ 1,634,575
Probable 1,840,044 567,018 368,029 934,202
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Total Proved +
Probable $ 4,855,230 $ 1,694,516 $ 1,221,547 $ 2,568,777
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(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
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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
Thereafter
escalating at: 2.0% 2.0% 2.00% 0.94
* as at December 31, 2009
Future Development Costs
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Proved Plus
Proved Probable
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Forecast Forecast
Prices and Prices and
Costs/Year Costs/Year
Year ($000s) ($000s)
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Undiscounted
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
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Total undiscounted 203,561 653,347
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Total discounted @
10% per year 149,589 484,541
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* 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.
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Advisories
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
For further information: Susan J. Soprovich, Director, Investor Relations, Ph: (403) 668-6732, Fax: (403) 237-9410, Email: [email protected], Website: www.comptonpetroleum.com
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