CALGARY, Aug. 5 /CNW/ -- CALGARY, Aug. 5 /CNW/ - Compton Petroleum
Corporation (TSX - CMT) reports its financial and operating results
for the second quarter ended June 30, 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 www.comptonpetroleum.com, at
www.sedar.com and at www.sec.gov. Q2 2010 in Review Summary of
Results: - Cash flow was $11.2 million or $0.04 per diluted share -
Operating loss was $21.5 million or $0.08 per diluted share - Net
loss was $52.3 million or $0.20 per diluted share - Capital
expenditures were $8.6 million, before acquisitions and
divestitures Achievements: The upper end of Management's budget
expectations was reached during the second quarter as a result of
Compton's focus on improving operational results and reducing
costs. Results for the quarter included: - Maintained average
production of 19,481 boe/d, which was slightly above the 19,411
boe/d in the first quarter of 2010 and approximately 1,200 boe/d
ahead of plan - Operating costs were up slightly to $10.46 per boe
versus $10.01 per boe in the second quarter of 2009, but were
reduced from the $11.29 per boe for 2009 (full year average)
despite lower production - Decreased operating and administrative
expenditures by $2.4 million from the second quarter of 2009 -
Improved drilling processes at Niton resulted in higher average
initial production rates and lower drilling costs - The continued
focus on optimization and reliability enhanced base production
performance - Completed the sale of $115.0 million in assets at
Niton effective June 30, 2010, and announced an agreement to sell
$35.2 million in assets at Gilby, which closed in July - Closed the
final 0.75% of the overriding royalty transaction for proceeds of
$14.3 million, bringing the total overriding royalty obligation to
5.0% and total proceeds of $95.0 million - Strengthened the
Corporation's capital structure by further reducing debt from
year-end 2009 levels: - Total bank debt and senior notes decreased
by 17% to $469.1 million - The Senior Credit Facility's balance was
eliminated, and the Facility was renegotiated and renewed effective
July 1, 2010 - A Recapitalization Plan for the Corporation's Senior
Term Notes was initiated subsequent to the second quarter (see
'Outlook' section) - The banking syndicate has agreed to increase
the borrowing limit, extend the term of the Facility and reduce the
interest margin by 0.5% from previous levels upon completion of the
Recapitalization Plan North American natural gas prices continued
to trade near the low point of the price cycle during the second
quarter, and expectations are that they will continue to remain
depressed over the near term due to excess supplies of natural gas.
In this environment, Compton continued its prudent approach to
capital investment commitments and focused its development strategy
on optimizing asset value, reducing costs, and carefully managing
its capital structure throughout the second quarter of 2010. As a
result, Compton improved its operating efficiencies and partially
offset the impact of lower natural gas prices on cash flows
generated by operations, which remain below normalized levels. "We
continue to deliver strong results from our asset base," said Tim
Granger, President and Chief Executive Officer. "Improved capital
efficiencies have enabled us to stabilize production rates with a
constrained capital investment program. The efficiency of our asset
base will be increasingly evident as we move forward and complete
our 2010 development program. In addition, we are continuing to
reduce our cost structures and improve our capital structure, which
is further strengthening the Corporation." Financial Review Three
Months Ended June 30 Six Months Ended June 30 (000s, except
----------------------------- ----------------------------- per
share % % amounts) 2010 2009 Change 2010 2009 Change
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Total revenue $ 57,790 $ 54,124 7% $129,058 $123,023 5% Cash
flow(1)(2) $ 11,162 $ 9,572 17% $ 32,683 $ 31,613 4% Per share -
basic (1)(2) $ 0.04 $ 0.08 (50%) $ 0.12 $ 0.25 (52%) - diluted
(1)(2) $ 0.04 $ 0.08 (50%) $ 0.12 $ 0.25 (52%) Operating
loss(1)(2)(3)$(21,511) $(14,782) (146%) $(26,283) $(19,149) (138%)
Net earnings (loss)(3) $(52,254) $ 19,848 (364%) $(35,297) $ 2,480
(1,524%) Per share - basic $ (0.20) $ 0.16 (225%) $ (0.13) $ 0.02
(750%) - diluted $ (0.20) $ 0.16 (225%) $ (0.13) $ 0.02 (750%)
Capital expenditures before acquisitions and divestments $ 8,631 $
16,245 (46%) $ 19,374 $ 32,131 (39%) June 30, Dec. 31, % As at 2010
2009 Change Total bank debt & senior notes $ 469,061 $ 568,924
(17%) Shareholders equity $ 958,170 $ 992,237 (3%) Shares
outstanding 263,579 263,573 - (1) Prior periods have been revised
to conform to current period presentation (2) Cash flow and
operating loss are non-GAAP measures and are addressed in detail in
the 'Advisories' section (3) Three and six months ended June 30,
2010 includes non-recurring costs of $13.3 million related to
surplus office lease costs Revenue increased by 7% in the second
quarter of 2010 compared to 2009 due to higher realized commodity
prices, particularly liquids prices, despite lower production
volumes. The higher average realized prices also impacted cash
flow, which was 17% higher in the second quarter of 2010 compared
to the same period in 2009. Compton reported a net loss for the
second quarter of 2010 of $52.3 million versus earnings of $19.8
million in the second quarter of 2009 due to non-cash unrealized
foreign exchange and risk management losses during the second
quarter of 2010. In addition, contributing to the loss in 2010 was
a non-recurring expense of $13.3 million related to the termination
of the Corporation's obligation for unused office space. The office
lease surrender payment reduces rent obligations in future periods.
Capital spending, before acquisitions and divestitures, decreased
by 46% in the second quarter of 2010 compared with the second
quarter of 2009. Capital spending was lower than anticipated for
the quarter due to the reduced cost of drilling and delays caused
by weather. The majority of the drilling capital was focused on
wells targeting the Belly River formation in Southern Plains, as
well as the drilling of one Glauconite well. The Corporation
drilled or participated in seven wells during the quarter as
compared to nine wells in 2009. Operations Review Three Months
Ended June 30 Six Months Ended June 30
----------------------------- ----------------------------- % %
2010 2009 Change 2010 2009 Change
-------------------------------------------------------------------------
Average daily production Natural gas (MMcf/d) 98 108 (9%) 98 113
(13%) Liquids (bbls/d) 3,076 3,428 (10%) 3,156 3,540 (10%)
-------------------------------------------------------------------------
Total (boe/d) 19,481 21,440 (9%) 19,446 22,312 (12%)
-------------------------------------------------------------------------
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Realized prices Natural gas ($/mcf) $ 4.15 $ 3.80 10% $ 4.90 $ 4.51
9% Liquids ($/bbl) $ 66.00 $ 49.93 33% $ 66.81 $ 43.99 52%
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Total ($/boe) $ 31.41 $ 27.74 14% $ 35.48 $ 30.46 17%
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Field netback(1) ($/boe) $ 17.73 $ 17.97 (1%) $ 20.07 $ 19.40 4%
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(1) Field netback is a non-GAAP measures and is addressed in detail
in the MD&A The excellent drilling results achieved at Niton in
the first quarter of 2010 were the major contributor to the
Corporation's continued strong performance. In addition, Compton's
focus on optimization and reliability enhanced base production
performance. These better than predicted sustained production rates
resulted in the quarter's volumes exceeding budget by more than
1,200 boe/d, and maintained production volumes at 19,481 boe/d
compared to 19,411 boe/d in the first quarter of 2010. Also, a 40%
non-operated Rock Creek well was brought on production during the
second quarter, adding approximately 800 boe/d to the quarter's
volumes. In the Southern Plains area, four of the six Belly River
wells drilled in the first half of the year were brought on
production. Better than anticipated results with these wells
reflect the success of Compton's ongoing emphasis on indentifying
optimal Belly River targets. The completion of the remaining two
wells was delayed due to lease conditions, but are expected to be
completed and brought on production in the third quarter of 2010.
In June, Compton announced the sale a portion of its natural gas
assets located in the Niton and Gilby areas in Central Alberta for
gross proceeds of $150.2 million. The sales closed at the end of
June and on July 15, 2010. A portion of the proceeds will be used
to provide additional capital for Compton's 2010 development
program. Drilling activity for the remainder of the year is on
plan. Management anticipates that the development portion of its
2010 capital expenditure program will range between $60.0 and $70.0
million (before acquisitions and dispositions). The asset sales
announced in the second quarter resulted in some reallocation of
capital between areas to maximize potential return on investment.
For the remainder of 2010, Compton will continue advancing emerging
formations in Niton and proving the value of the asset base in High
River, Callum/Cowley and Southern Plains. - Niton: In the second
half of the year, Compton will shift focus from the Rock Creek
formation to uphole proven zones. The current development plan is
as follows: - 4 Cardium oil wells - 1 Spirit River/Wilrich well
recompletion - 2 Second White Specks oil wells - 3 Rock Creek gas
wells - High River: Of the current 10 well refracture inventory,
three to four wells are planned for the remainder of the year. Two
to three new wells are scheduled to be drilled and are targeted for
completion by the end of 2010. Extensive technical work has been
done on these locations. Indications are that the cost to drill
these wells could be up to 20% lower than previous levels. -
Callum/Cowley/Todd Creek: Work is proceeding to obtain well
licenses for future drilling locations. Two Callum/Cowley wells in
the Belly River and one Todd Creek well in the Cadomin are expected
to be drilled prior to year-end. The Cadomin well drilled in 2009
has produced at better than expected rates, which contributed to
exceeding the second quarter's volume budget. - Southern Plains:
Results from two additional Glauconite recompletions and an
additional Glauconite drill are expected prior to year-end. The
current inventory of 50 locations is being reviewed for the 2011
program. The Belly River location optimization continues,
positioning Compton for a larger scale Belly River program if
commodity prices strengthen. Compton's operating efficiency
initiatives continued during the second quarter, targeting cost
optimization and maximizing reliability. The stretch target of
reducing operating costs by an additional $10 million per year is
65% complete. The Corporation's operational reliability has
improved, which contributed to better than anticipated base
production volumes in the second quarter. The implementation of
identified initiatives is expected to be complete by the fourth
quarter of 2010, allowing for a reduced operating expense budget to
be set for 2011. Outlook Subsequent to the quarter, the Corporation
announced a proposed Recapitalization Plan that affects its Senior
Term Notes. The Recapitalization Plan proposes to exchange all of
the existing US$450.0 million Senior Notes for a combination of: a)
US$193.5 million 10% notes due 2017 (the "New Notes"); b) US$184.5
million of cash; and c) US$45.0 million 10% notes due September
2011 (the "Mandatory Convertible Notes"). The exchange of all of
the Corporation's Notes under the Recapitalization Plan is proposed
to be completed pursuant to the Plan of Arrangement (the
"Arrangement") under the Canada Business Corporations Act which
includes the calling a meeting of noteholders. The meeting date for
noteholders to vote on the Arrangement has been set for September
14, 2010. The Arrangement will require the approval of two-thirds
of the votes cast by noteholders present in person or by proxy at
the Meeting and who are entitled to vote on the Arrangement
resolution. Subject to receiving the required approvals and to
other conditions, it is anticipated that the effective date of the
Arrangement will be on or about September 15, 2010. Management and
the Board of Directors believe that the Arrangement will provide
the following key benefits to the Corporation: - Additional
improvement in financial strength through debt reduction of
approximately $217.4 million from approximately $599.0 million to
$381.6 million, significantly reducing debt service obligations; -
Compton's banking syndicate has indicated its support for the
Recapitalization by agreeing, conditional upon the completion of
the Arrangement, to an increase in the Facility to $225.0 million
(from $150.0 million previously) and through the addition of two
new members to the syndicate; and - The Corporation will be able to
turn its full attention to its asset base, targeting production and
cash flow growth through internal development and accretive
acquisition opportunities. The Recapitalization is the final step
in the repositioning of Compton's existing capital structure,
creating a sustainable base going forward. Management will now
increase its focus on its strategic growth plan, maximizing the
value of its asset base. The current unfavourable outlook for
natural gas in North America is expected to continue to constrain
the Corporation's cash flows levels. This is expected to be
somewhat offset by better than expected volumes and reduced costs.
Compton's guidance for 2010 was revised in June due to the asset
sales as follows: Current Expectation
------------------------------------------ Average daily production
(boe/d) High end of range(1) 16,000 - 16,500 Administrative
expenses ($ millions) Low end of range(1) $25 - $27 Operating costs
($ millions) Low end of range(1) $80 - $85 Cash flow(2) ($
millions) High end of range(1) $40 - $50 Capital expenditures(3) ($
millions) $70 - $80 2010 Pricing: Natural gas - AECO (Cdn$/GJ)
$4.70 Crude oil - Edmonton Sweet (Cdn$/bbl) $78.39 Exchange rate
(US$/Cdn$) $0.99 (1) While maintaining guidance in the interim,
Management expects further improvements in increasing production
and reducing costs (2) A $0.25 change in the AECO natural gas price
is expected to result in a $7.0 million change in cash flow (3)
Includes development and corporate capital expenditures Management
remains committed to maintaining its financial prudence and
improving its capital efficiencies, focusing on proving the value
of key areas and formations in Compton's asset base. Management
will apply the knowledge gained at Niton to the drilling of
horizontal multiple-stage fracture wells at High River during the
second half of 2010, as well as to target new growth opportunities
in undeveloped formations in Niton and the Southern Plains. The
results of these activities are expected to prove the underlying
value and development potential of Compton's large asset base, and
provide solid returns to its shareholders in a conservative natural
gas price environment. Additional Information Compton has filed its
Consolidated Financial Statements for the three months ended June
30, 2010 and related Management's Discussion and Analysis with
Canadian securities regulatory authorities. Copies of these
documents may be obtained via www.sedar.com, www.sec.gov or the
Corporation's website, www.comptonpetroleum.com. To order printed
copies of the filed documents free of charge, email the Corporation
at investorinfo@comptonpetroleum.com. Advisories 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 June 30, 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 Rock
Creek sands at Niton 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. %CIK: 0001043572 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:
investorinfo@comptonpetroleum.com, Website:
www.comptonpetroleum.com
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