CALGARY, March 24 /PRNewswire-FirstCall/ -- Compton Petroleum
Corporation (TSX - CMT, NYSE - CMZ) reports its financial and
operating results for the year and fourth quarter ended December
31, 2008. The full text of Management's Discussion and Analysis
("MD&A") and the Company's audited consolidated financial
statements can be found on the Company's website at
http://www.comptonpetroleum.com/ and at http://www.sedar.com/. 2008
In Review 2008 was a mixed year for Compton - one in which our
challenges largely overshadowed our achievements. The rapid
deterioration of capital markets, the onset of a global recession
and falling commodity prices have also had a major impact on the
Company, particularly in the fourth quarter. Summary of Results: -
Generated funds flow from operations of $255.9 million, or $1.94
per diluted share. - Adjusted operational earnings for the year
were $54.9 million. - Achieved annual average production of 28,658
boe/d. Achievements: - Realized $203 million on the sale of
non-core properties and reduced bank debt by $109 million. -
Successfully employed horizontal drilling using multi-stage
fractured completions in the Hooker and Niton core areas during the
year. - Drilled 256 wells with a 96% success rate on expenditures
of $327 million, before acquisitions and divestures. - Increased
proved developed producing reserves by approximately 6 MMBoe or
7.3% before production and property sales. - Added 14.6 MMBoe of
proved reserves, or 1.4 times 2008 production, through discoveries,
extensions and improved recoveries. Challenges: - As a result of
rapidly deteriorating market conditions in the latter part of 2008,
the corporate sale process undertaken pursuant to a review of
strategic alternatives was terminated. - A 15% negative revision to
estimated proved and probable reserves at December 31, 2007. The
majority of these revisions resulted from actual well performance,
in specific instances, being less than initially anticipated. - A
net loss for the year of $43.0 million, largely resulting from one-
time charges and an unrealized foreign exchange loss. Financial
Review
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(000s, except per share Three Months Ended Dec. 31 Year Ended Dec.
31 amounts) 2008 2007 % Change 2008 2007 % Change
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Total revenue(1) $104,769 $128,451 (18) $610,298 $506,218 21 Funds
flow from operations (2) $ 20,256 $ 48,187 (58) $255,881 $201,425
27 Per share - basic(2) $ 0.17 $ 0.37 (54) $ 1.98 $ 1.56 27 -
diluted(2) $ 0.16 $ 0.37 (57) $ 1.94 $ 1.52 28 Adjusted operational
earnings (1)(2) $ (9,216) $ 9,731 (195) $ 54,917 $ 42,689 29 Net
earnings (loss) $(95,943) $ 50,458 (290) $(43,003) $129,266 (133)
Per share - basic $ (0.74) $ 0.39 (290) $ (0.33) $ 1.00 (133) -
diluted $ (0.74) $ 0.38 (295) $ (0.33) $ 0.98 (134) Capital
expenditures before acquisitions and divestments $327,055 $385,532
(15) Total bank debt & term notes $829,321 $832,188 -
Shareholders equity $834,690 $869,956 (4) Shares outstanding
125,760 129,098 (3)
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(1) Prior periods have been revised to conform to current period
presentation (2) Funds flow from operations and adjusted
operational earnings are non- GAAP measures and are addressed in
detail in the MD&A Revenue, funds flow from operations and
operational earnings all benefited from higher commodity prices
realized in 2008 as compared to 2007. Despite improved revenue from
stronger commodity prices, we recognized a net loss of $43.0
million for the year ended December 31, 2008 as compared to net
earnings of $129.3 million in 2007. The 2008 loss is largely
attributable to an unrealized foreign exchange loss of $90.7
million, net of income taxes, on translation of the Company's
US-dollar denominated senior notes. In 2007, we recognized an
unrealized foreign exchange gain of $66.9 million, net of income
taxes, relating to the notes. Additionally, one-time costs of $23.0
million, net of income taxes, associated with the strategic review
process and subsequent corporate restructuring impacted 2008
earnings. Adjusted operational earnings increased 29% from $42.7
million in 2007 to $54.9 million in 2008. Adjusted operational
earnings is a non-GAAP measure that adjusts net earnings by
non-operating items that, in management's opinion, reduce the
comparability of our underlying financial performance between
periods. These non-operating items are largely non-cash in nature
or one-time non-recurring items, including those referred to above.
Capital spending in 2008 was directed towards the continued
development of our core natural gas resource plays in southern and
central Alberta. The Company drilled 20% fewer wells in 2008 when
compared with 2007. However, capital spending, before acquisitions
and divestitures, decreased by only 15% year over year and drilling
and completion costs decreased by just 1% as a result of the
increased number of higher cost horizontal wells drilled during
2008. During 2008, we continued to pursue our strategy of focusing
on our core natural gas assets in central and southern Alberta, and
divested of a number of non-core assets at Cecil, Zama, Thornbury,
and the Peace River Arch for net proceeds of $203 million. Fourth
Quarter During the fourth quarter of 2008 revenue decreased 34%
quarter over quarter due to declining commodity prices and a 4%
decrease in production, which reflects the sale of non-core assets
that closed at various times throughout the third quarter of 2008.
In addition to lower commodity prices and production volumes,
fourth quarter earnings and funds flow were impacted by unrealized
currency exchange losses and one-time non-recurring strategic
review and corporate restructuring costs previously discussed, the
majority of which were recognized in the fourth quarter. Operations
Review
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Three Months Ended Dec. 31 Year Ended Dec. 31 2008 2007 % Change
2008 2007 % Change
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Average daily production Natural gas (mmcf/d) 125 167 (25) 143 145
(1) Liquids (bbls/d) 4,113 4,818 (15) 4,769 7,166 (33) Total
(boe/d) 24,868 32,646 (24) 28,658 31,326 (9) Realized prices
Natural gas ($/mcf) $ 6.99 $ 6.00 17 $ 8.17 $ 6.33 29 Liquids
($/bbl) $ 60.60 $ 77.60 (22) $ 98.68 $ 62.28 58 Total ($/boe) $
45.79 $ 42.77 7 $ 58.18 $ 44.27 31 Field netback(1) ($/boe) $ 29.67
$ 24.68 20 $ 34.30 $ 26.99 27 Reserves Proved plus probable Natural
gas (Bcf) 1,119 1,369 (18) Crude oil, NGLs & Sulphur (MBbl)
28,920 42,631 (32) Total (MBoe) 215,488 270,819 (20)
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(1) Field netback is a non-GAAP measures and is addressed elsewhere
in detail in the MD&A Overall production in 2008 fell 9% from
the year prior. Natural gas volumes decreased 1%, while liquids
production decreased 33% from 2007. The year over year decrease in
our natural gas and liquids volumes is attributable to natural
declines and the sale of our Cecil, Zama, Thornbury, and Peace
River Arch assets. Drilling Summary The following table summarizes
our drilling results.
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Natural Crude Year Ended Dec 31, Gas Oil D&A Total Net Success
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Southern Alberta 160 3 3 166 152 98% Central Alberta 72 6 7 85 35
92% Standing, cased wells 5 5
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2008 Total 232 9 10 256 192 96%
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2007 Total 276 25 10 322 266 97%
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Of the 192 net wells drilled during 2008, only 2% were classified
as exploratory wells. This compares to 266 net wells and 273 net
wells drilled in 2007 and 2006, of which 9% and 17% were
exploratory, respectively. Development Properties In 2008, Compton
applied horizontal well and multiple stage fracture stimulation
technology at several of its key properties. Management believes
that this technology is particularly applicable to its deep basin
assets and has the potential to increase ultimate recovery and
improve development economics. The Company successfully employed
horizontal drilling using multi-stage fractured completions in the
Hooker and Niton core areas during the year. Hooker (Southern
Alberta) ------------------------- The Hooker pool reached a
cumulative production milestone of 100 BCF in early 2008. Through
selective drilling and pool wide optimization, Hooker's depletion
strategy can be optimized to enhance capital efficiency. Compton
initiated horizontal drilling with multi-stage fracture
stimulations to the pool with the drilling of one well in late 2007
and an additional four wells in 2008. The successful application of
this technology could allow Compton to improve depletion economics,
particularly in the tight early stage parts of the reservoir. Also
in 2008, Compton successfully negotiated with the sole remaining
partner in the pool to down-space 45 of 57 developed sections to
three wells per section. This will provide us with more latitude
when establishing optimal well density in order to maximize the
value of our depletion strategy. The 12 remaining sections have
sufficient drainage with current well densities to adequately
access the reservoir. In 2009, the Company plans to optimize its
existing gas producers and with more favourable commodity prices,
continue building on our success in 2008 by drilling one to three
horizontals in addition to select vertical locations. A key
component of success in this area will be to minimize drilling and
completion costs. In addition, existing field compression and
subsequent pool performance will be optimized by reducing the field
pressures. Niton & Caroline (Central Alberta)
---------------------------------- Compton has continued to be a
very active driller at Niton. During 2008, 25 wells were drilled,
including 12 horizontal wells in the Rock Creek formation and two
horizontal wells targeting the Ellerslie formation. The Rock Creek
play at Niton is being aggressively developed by a number of
Western Canadian operators. Compton is the leading Niton operator
developing this play with 23 successful horizontal wells producing
from this zone at year-end. In 2008, the Company also completed a
joint venture farm-in to earn a further nine sections of land on
this Rock Creek play and drilled three vertical and two horizontal
Rock Creek wells on this land. The Ellerslie formation has
historically only been developed through vertical drilling. Compton
evaluated the application of new technology in 2008, drilling two
horizontal wells targeting lower permeability sands in this zone.
Both wells are on production with a combined first month initial
production rate of 1,340 Mcf/d. Adjacent to our two horizontals,
older, offset vertical wells had limited productive capability. In
the second half of 2009, Compton may continue with development
operations at Niton targeting more permeable sands in the Rock
Creek and Ellerslie formations, should commodity prices and
drilling costs support acceptable investment returns. Plains Belly
River & Edmonton Group (Southern Alberta)
------------------------------------------------------ In 2008,
Compton drilled 160 gross Belly River development wells. At
year-end, the Company was producing 45 MMcf/d from 750 wells. There
is ample infrastructure in the area for future production increases
with 32,500 horsepower of compression and approximately 1,300
kilometres of pipeline. On a go forward basis, Compton anticipates
that the majority of its Plains Belly River lands will be developed
at the government approved spacing of four wells per section on
this shallow low risk gas play. Exploratory Properties
Callum-Cowley & Todd Creek (Southern Alberta)
--------------------------------------------- The Callum-Cowley
area is a largely exploratory property at this time. In 2008,
Compton drilled and fracture stimulated two horizontal wells,
targeting select thrusted Belly River sands. The use of 3-D seismic
was essential to effectively target these structurally complex
fractured sands. The wells are following the typical production
profile for tight horizontal gas sands. Well licenses, surface
leases and pipelines have been obtained for an additional three
Callum-Cowley locations for 2009, which may be drilled depending
upon economics. At Todd Creek, Compton is pursuing an exciting new
exploratory play. In 2008, the Company successfully completed a new
zone in an older existing well bore. A pipeline was installed late
in December 2008 to tie-in the well. Initial production was 4
MMcf/d, but is currently being restricted to 2.5 MMcf/d in order to
provide sufficient test data on this new exploratory concept.
Reserves Reserve Summary Company Working Interest before Royalties
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2008 2007 Crude Natural % % As at Oil Gas NGLs Sulphur Total Proved
Total Proved December 31, MBbl MMcf MBbl MLt MBoe MBoe
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Proved Produc- ing 4,433 440,375 8,087 1,928 87,844 71% 103,884 69%
Non- produc- ing 37 44,076 613 66 8,062 6% 10,464 7% Undevel- oped
317 155,946 1,960 151 28,418 23% 35,216 24%
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Total Proved 4,786 640,396 10,660 2,145 124,324 100% 149,564 100%
Probable 3,156 479,013 7,230 944 91,164 121,255
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Total Proved + Probable 7,942 1,119,409 17,889 3,089 215,488
270,819
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Boe per share 1.71 2.10
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* Numbers may not add due to rounding After giving effect to
property sales, production, extensions, improved recovery, and
revisions, 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, Compton produced 10.5 MMBoe and
sold approximately 11.6 MMBoe of proved reserves. Reserves
decreased by 5 MMBoe or 3% on a proved basis and 29 MMBoe or 11% on
a proved plus probable basis, net of production and property sales.
Technical revisions reflect adjustments to reserve estimates made
in previous years and relate to expected 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 plus
probable basis. The Plains Belly River accounted for approximately
one-half of well performance revisions and a small number of wells
in the Niton and Hooker areas accounted for the majority of
performance related revisions in these areas. The 2008 drilling
program focused primarily on development activities and the
advancement of reserves from the proved undeveloped and probable
classifications to the proved producing classification. In
contrast, a greater emphasis was placed on discoveries and
extensions in prior years As a result, proved developed producing
reserves increased approximately 6 MMBoe or 7.3% before production
and property sales. Net Present Value of Reserves
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Future net revenue before income taxes discounted at a rate of As
at December 31, ($000) 0% 10% 15%
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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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2008 Total proved plus probable $ 7,355,017 $ 2,568,777 $ 1,828,152
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2007 Total proved plus probable $ 8,074,691 $ 2,918,833 $ 2,106,520
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* 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 our
reserves or the costs that would be incurred to obtain equivalent
resources. At December 31, 2008, future net revenue from reserves
decreased 9.7% from 2007 on a total proved basis and 12% on a total
proved plus probable basis, discounted at 10%. The decrease
reflects the reduced volumes and changes in forecasted prices
between the two years. 2009 Outlook The current economic
environment is challenging and uncertain amidst a global recession,
reduced demand for crude oil and natural gas, low commodity prices,
volatile financial markets, and limited access to capital markets.
Natural gas prices have historically been volatile. During 2008
AECO daily index natural gas prices fluctuated from an average
monthly high of $10.62/GJ in June to a low of $6.21/GJ in December.
Prices have continued to decline into the first quarter of 2009 and
averaged $4.52/GJ during the month of February. In these
circumstances, we have implemented a measured and flexible
investment approach. We will adjust our 2009 capital spending up or
down, depending upon how economic circumstances unfold during the
year and intend to limit our capital expenditures to within funds
flow from operations. We are currently revisiting our initial 2009
plans in light of the continued decline in commodity prices,
particularly natural gas prices, and our commitment to limit
capital spending to funds flow from operations. In response to
current commodity prices, we have delayed certain first quarter
2009 expenditures and expect our 2009 capital program will be less
than initially planned. We will communicate our revised 2009 plans
once they have been finalized. We have initiated a corporate
restructuring process with a concentrated emphasis on continued
capital efficiencies and reducing our internal cost structures. The
overall contraction in industry activity and the expected
corresponding decline in the cost of goods and services, resulting
from current economic conditions, will benefit these initiatives.
Our overall short term strategy is to position the Company such
that, once an economic recovery occurs and commodity prices
strengthen, we will have the ability to develop and realize on our
sizable long-life asset base and create additional value for our
shareholders. To that end, management has initiated a Company-wide
restructuring and asset optimization program. Additional
Information Compton has filed its audited Consolidated Financial
Statements for the year ended December 31, 2008 and related
Management's Discussion and Analysis with Canadian securities
regulatory authorities. Copies of these documents may be obtained
via http://www.sedar.com/ or the Company's website,
http://www.comptonpetroleum.com/. To order printed copies of the
filed documents free of charge, email the Company at .
Additionally, Compton filed its Annual Information Form for the
year ended December 31, 2008, which includes the disclosure and
reports relating to reserves data and other oil and gas information
required pursuant to National Instrument 51-101 of the Canadian
Securities Administrators, on March 23, 2009. Compton will also
file its Form 40-F with the U.S. Securities and Exchange Commission
in the United States shortly thereafter. An electronic copy of
Compton's 40-F may be obtained on Compton's profile at
http://www.sec.gov/edgar.shtml. 2008 Year-End Conference Call
Compton will host a conference call and web cast on Wednesday,
March 25, 2009 at 9:30 a.m. Mountain Standard Time (11:30 a.m. EST)
to discuss the Company's 2008 fourth quarter and 2008 annual
financial and operating results. To participate in the conference
call, please contact the Conference Operator ten minutes prior to
the call at 1-800-731-5774 or 1-416-644-3419. To participate in the
web cast, please visit: http://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:
1-877-289-8525 or 1-416-640-1917 and enter access code 21301571
followed by the number sign until March 31, 2009. Annual and
Special Meeting of Shareholders Compton's Annual and Special
Meeting of Shareholders is scheduled for May 11, 2009 at 3:30 p.m.
(Calgary time) in the Historical Ballroom on the Fourth Floor of
the Calgary Chamber of Commerce, 517 Centre Street South, Calgary,
Alberta, Canada. A web cast of the Annual and Special Meeting will
be available on Compton's website at
http://www.comptonpetroleum.com/; all shareholders are encouraged
to attend either in person or electronically. Advisories 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 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
views of its financial and operational results as of December 31,
2008, reserves volumes, net present value of its reserves 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 Company's forward-looking statements are expressly
qualified in their entirety by this cautionary statement. Non-GAAP
Financial Measures Included in the news release are references to
terms used in the oil and gas industry such as funds flow from
operations, funds flow per share, adjusted operational earnings,
adjusted EBITDA, and field netback. These terms are not defined by
GAAP in Canada and consequently are referred to as non-GAAP
measures. 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. Funds flow from
operations 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 Company's performance or
liquidity. Funds flow from operations is used by Compton to
evaluate operating results and the Company's ability to generate
cash to fund capital expenditures and repay debt. Adjusted
operational earnings represents net earnings excluding certain
items that are largely non-operational in nature and should not be
considered an alternative to, or more meaningful than, net earnings
as determined in accordance with Canadian GAAP. Adjusted
operational earnings is used by the Company to facilitate
comparability of earnings between periods. Adjusted EBITDA is a
non-GAAP measure defined as net earnings, net of interest and
finance charges, income taxes, depletion, depreciation and
amortization, accretion of asset retirement obligations, and any
foreign exchange gains or 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. Field netback and funds flow netback do not
have a standardized meaning as prescribed by Canadian GAAP and,
therefore, may not be directly comparable to similar measures
presented by other issuers. About Compton Petroleum Corporation
Compton Petroleum Corporation is a Calgary-based public company
actively engaged in the exploration, development, and production of
natural gas, natural gas liquids, and crude oil in the Western
Canada Sedimentary Basin. 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: Tim Granger, President & CEO, Norm Knecht,
VP, Finance and CFO, Phone: (403) 237-9400, Fax: (403) 237-9410,
Email: , Website: http://www.comptonpetroleum.com/
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