CALGARY, March 4 /PRNewswire-FirstCall/ -- Compton Petroleum
Corporation (TSX - CMT, NYSE - CMZ) reports estimated reserve
volumes together with the net present value of its reserves as at
December 31, 2008. Netherland, Sewell & Associates, Inc.,
Compton's independent reserve evaluators, have completed an
evaluation of 100% of the Company's petroleum and natural gas
reserves as at December 31, 2008 in accordance with the provisions
of National Instrument 51-101. Summary Results: - Discoveries,
extensions and improved recoveries added 14.6 MMboe to proved
reserves, which is 1.4 times 2008 production; - Proved developed
producing reserves increased approximately 6 MMBoe or 7.3% before
production and property sales; - Reserves decreased 16% on a proven
and 20% on a proved plus probable basis from 2007, primarily due to
dispositions, production and technical revisions - Finding and
development (F&D) costs were $20.14 per boe in 2008 on a proved
basis, which is lower than the three-year average, including
revisions, of $28.07 per boe; and - Undeveloped land of 858,788 net
acres is valued at $118 million. 2008 Reserves ------------- 2008
Reserve Summary Company Working Interest before Royalties
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December 31, 2008 Oil Gas NGL Sulphur Total MBbl MMcf MBbl MLt MBoe
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Proved Producing 4,433 440,375 8,087 1,928 87,844 Non-producing 37
44,076 613 66 8,062 Undeveloped 317 155,946 1,960 151 28,418
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Total Proved 4,786 640,396 10,660 2,145 124,324 Probable 3,156
479,013 7,230 944 91,164
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Total Proved + Probable 7,942 1,119,409 17,889 3,089 215,488
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Net Present Value of Reserves
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December 31, 2008 Future net revenue before income taxes discounted
at a rate of -------------------------------------- 0% 10% 15%
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($000) ($000) ($000) Proved Producing $ 3,050,340 $ 1,180,781 $
922,967 Non-producing $ 333,779 $ 135,560 $ 101,110 Undeveloped $
985,397 $ 318,235 $ 204,504
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Total proved $ 4,369,516 $ 1,634,575 $ 1,228,581 Probable $
2,985,501 $ 934,202 $ 599,571
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Total proved plus probable $ 7,355,017 $ 2,568,777 $ 1,828,152
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Price forecasts as of December 31, 2008 used in the above
evaluation are an average of the forecasts of four major
engineering firms in Calgary, Alberta. Forecast Pricing, Inflation
Rate, and Exchange Rate Assumptions as of December 31, 2008 Year
Crude Oil Nat. Gas Inflation Exchange ---- --------- --------
--------- -------- Edmonton Par AECO %/Year $Cdn/$US ($Cdn/MMbtu) C
Spot ($Cdn/Bbl) 2009 67.24 7.20 2.0 0.80 2010 80.48 7.89 2.0 0.85
2011 87.85 8.21 2.0 0.85 2012 93.92 8.72 2.0 0.90 2013 99.81 9.24
2.0 0.95 2014 101.82 9.44 2.0 0.95 2015 103.88 9.64 2.0 0.95 2016
105.97 9.83 2.0 0.95 2017 108.06 10.04 2.0 0.95 2018 110.26 10.24
2.0 0.95 2019 112.46 10.45 2.0 0.95 Thereafter escalating at: 2.0%
2.0% 2.0 0.95 Summary Reserve Comparison
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As at December 31, 2008
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Crude Oil, Natural NGLs & Total Gas Sulphur (6:1) % Proved
--------------------------------------------------- (Bcf) (MBbls)
(MBoe)
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Proved Producing 440 14,448 87,844 71% Non-producing 44 716 8,062
6% Undeveloped 156 2,427 28,418 23%
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Total proved 640 17,591 124,324 100% Probable 479 11,329 91,164
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Total proved plus probable 1,119 28,920 215,488
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Boe per share 1.71
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------------------------------------------------ 2007
------------------------------------------------ Total (6:1) %
Proved -------------------------- (MBoe)
------------------------------------------------ Proved Producing
103,881 69% Non-producing 10,464 7% Undeveloped 35,215 24%
------------------------------------------------ Total proved
149,564 100% Probable 121,255
------------------------------------------------ Total proved plus
probable 270,819 ------------------------------------------------
Boe per share 2.10 ------------------------------------------------
After giving effect to property sales, production, extensions and
revisions, our 2008 reserves decreased approximately 25 MMBoe or
16% on a proved basis and 55 MMBoe or 20% on a proved plus probable
basis as compared to 2007. During 2008 we produced 10.5 MMBoe and
sold approximately 11.6 MMBoe of proved reserves. Net of production
and property sales, reserves decreased by 5 MMBoe (3%) on a proved
basis and 29 MMBoe (11%) on a proved plus probable basis. We
drilled a total of 192 net wells during 2008, four of which were
classified as exploratory wells, as compared to 266 net wells in
2007 of which 25 were exploratory. Our 2008 drilling program
focused primarily on development activities and the advancement of
reserves from the proved undeveloped and probable categories to the
proved producing classification in contrast to the greater emphasis
placed on discoveries and extensions in prior years. As a result,
our proved developed producing reserves increased by approximately
6 MMBoe or 7.3% before production and property sales. Summary Net
Present Value Comparison
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As at December 31, 2008 2007
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Discount rate 10% 15% 10% 15%
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($000's) ($000's) ($000's) ($000's) Proved Producing $ 1,180,781 $
922,967 $ 1,304,364 $ 1,052,974 Non-producing $ 135,560 $ 101,110 $
160,474 $ 122,947 Undeveloped $ 318,235 $ 204,504 $ 344,872 $
222,290
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Total proved $ 1,634,575 $ 1,228,581 $ 1,809,710 $ 1,398,212
Probable $ 934,202 $ 599,571 $ 1,109,123 $ 708,309
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Total proved plus probable $ 2,568,777 $ 1,828,152 $ 2,918,833 $
2,106,520
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At December 31, 2008, future net revenue from our reserves
decreased 9.7% from 2007 on a total proved basis and 12% on a total
proved and probable basis, discounted at 10%. This decrease
reflects the reduced volumes and changes in forecasted prices
between the two years. Reserve Reconciliation Forecast Prices and
Costs
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Crude Oil, NGLs, & Sulphur Natural Gas
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Proved Probable Proved Probable
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(MBbl) (MBbl) (Bcf) (Bcf)
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December 31, 2007 25,477 17,154 745 625 Extensions 636 388 34 41
Improved Recovery 628 (628) 46 (46) Technical Revisions (1,905)
(2,930) (98) (123) Discoveries 34 8 0 0 Acquisitions 34 3 2 0
Dispositions (5,588) (2,665) (36) (19) Economic 0 0 0 0 Production
(1,726) 0 (53) 0
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December 31, 2008 17,591 11,329 640 479
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------------------------------------------------------------ Total
------------------------------------------------------------ Proved
+ Proved Probable Probable
------------------------------------------------------------ (MBoe)
(MBoe) (MBoe)
------------------------------------------------------------
December 31, 2007 149,564 121,255 270,819 Extensions 6,380 7,291
13,670 Improved Recovery 8,231 (8,231) 0 Technical Revisions
(18,272) (23,434) (41,707) Discoveries 38 11 49 Acquisitions 433 40
473 Dispositions (11,559) (5,766) (17,325) Economic 0 0 0
Production (10,491) 0 (10,491)
------------------------------------------------------------
December 31, 2008 124,324 91,164 215,488
------------------------------------------------------------ Proved
reserve extensions, improved recoveries, and discoveries totaled
14.6 MMBoe or 1.4 times 2008 production. Technical revisions
reflect adjustments to reserve estimates made in previous years and
relate to expected future well performance based upon additional
production history, the impact of current operating factors on
sales volumes including fuel gas usage associated with production
facilities, and land expiries. Aggregate negative technical
revisions, related to December 31, 2007 reserve bookings, were 18.3
MMBoe on a proved basis and 41.7 MMBoe on a proved and probable
basis. In the Niton and Hooker areas, a small number of wells
accounted for the majority of well performance related revisions.
Niton accounted for 4% of the proved revisions and 11% of the
proved and probable revisions. Approximately 75% of the proved
revisions at Niton are attributable to two horizontal wells. A
total of 189 wells are on production at Niton including 26
horizontal wells. The Hooker area contributed 25% of proved and 21%
of proved and probable negative revisions. Approximately 60% of the
proved revisions relate to 14 Basal Quartz wells, including three
undeveloped locations; in total, 102 Basal Quartz wells are on
production in the area. The Plains Belly River accounted for
approximately one-half of the negative well performance related
revisions. The technical revisions result from a general reduction
in the ultimate recovery from 63% of producing well locations. This
reduction was also applied to the proved undeveloped and probable
locations. Approximately 15% of proved plus probable revisions
relate to operational factors and land expiries. Finding and
Development Costs ----------------------------- Finding and
Development (F&D) and Finding, Development and Acquisition
(FD&A) costs are used as a measure of capital efficiency and
are determined by dividing the capital costs for the period,
including the change in estimated future development capital, by
associated reserve additions. During 2008, we incurred total
capital expenditures of $324 million, excluding acquisitions and
proceeds from dispositions. These expenditures added 14,649 MBoe to
proved reserves and 13,719 MBoe to proved plus probable reserves,
which resulted from discoveries, extensions, and improved
recoveries. Future capital associated with placing proved reserves
on production is estimated to be $289 million and future capital
associated with placing proved and probable reserves on production
is $1,045 million. This reflects a reduction from 2007 of future
capital associated with proven and proven plus probable reserves of
$30 million and $120 million respectively. Reductions of future
capital reflect, in part, our 2008 focus on the promotion of
reserves to the producing category. F&D costs for 2008 do not
reflect technical revisions as these revisions relate to preceding
years. Three year average F&D costs include technical
revisions. FD&A costs, which include reserves and capital
associated with acquisitions, is also presented. During 2008,
Compton acquired 473 MBoe of proven plus probable reserves at a
total cost of $11 million and disposed of 11,325 MBoe of proven
plus probable reserves for proceeds of $203 million. In all cases,
capital expenditures are before proceeds on the disposition of
reserves during the period.
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2008 3-Year Average
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Excluding Including Excluding Including (Including change Technical
Technical Technical Technical in future capital) Revisions
Revisions Revisions Revisions
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F&D Costs ($/boe)
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Total Proved $ 20.14 n.a $ 28.58 $ 28.07 Total Proved + Probable $
14.91 n.a $ 14.67 $ 28.85
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FD&A Costs ($/boe)
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Proved $ 20.29 n.a $ 26.70 $ 26.33 Proved + Probable $ 17.27 n.a $
12.86 $ 21.04
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Year-end financial reports are in the process of being completed.
The capital expenditure figures are preliminary and may be subject
to adjustment; any such adjustment is not expected to be material.
The aggregate of exploration and development costs incurred in the
most recent financial year and the change during that year in
estimated future development costs generally will not reflect total
finding and development costs related to reserve additions for that
year. Undeveloped Land ---------------- We had a total of 858,788
net acres of undeveloped land at December 31, 2008. Based on an
independent land evaluation, this acreage is valued at $118 million
for the Company. 2008 Year-End Financial Results and Conference
Call Compton plans to release its year-end results on March 23,
2009. Additional reserve disclosures will be provided together with
audited year-end financial results as at that date. Information
relating to a subsequent conference call, including dial-in
information, will be included in the year-end news release.
Advisories Use of Boe Equivalents The oil and gas industry commonly
expresses production and reserve volumes on a barrel of oil
equivalent (Boe) basis whereby natural gas volumes are converted at
the ratio of six thousand cubic feet of natural gas to one barrel
of oil. Boe's may be misleading particularly if used in isolation.
A Boe conversion ratio of 6 Mcf : 1 Bbl is based on an energy
equivalency conversion method primarily applicable at the burner
tip and does not represent a value equivalency at the wellhead.
Forward Looking Statements Certain information regarding the
Company 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
Company'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
reserves volumes, net present value of its reserves, and finding
and development costs as at December 31, 2008. 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 Company's forward-looking
statements are expressly qualified in their entirety by this
cautionary statement. About Compton Compton Petroleum Corporation
is an independent, public company actively engaged in the
exploration for and development and production of natural gas,
natural gas liquids, and crude oil in western Canada. Our
activities are focused primarily in the Deep Basin fairway in the
Western Canada Sedimentary Basin in the province of Alberta. Our
growth and reserve base results predominantly from our exploration
and development drilling programs. 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. DATASOURCE: Compton Petroleum
Corporation CONTACT: contact Tim Granger, President & CEO, or
Norm Knecht, VP Finance & CFO, Telephone: (403) 237-9400, Fax
(403) 237-9410, Website: http://www.comptonpetroleum.com/, Email:
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