CALGARY, May 10 /CNW/ - Compton Petroleum Corporation ("Compton" or the
"Company") is pleased to announce its financial and operating results for the
quarter ended March 31, 2006.
HIGHLIGHTS
- Production of 34,029 boe/d, 19% increase from first quarter 2005.
- Largest first quarter drilling program to date - drilled 121 wells
with a 92% success rate.
- Revenue of $148 million, 39% increase from first quarter 2005.
- Cash flow of $74 million, 41% increase from first quarter 2005.
- U.S.$150 million add-on Senior Note offering completed.
- Acquired partner's interest in Callum
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FINANCIAL SUMMARY
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Three Months Ended March 31
($000s, except per share amounts) 2006 2005 Change
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Gross revenue $ 147,644 $ 106,589 39%
Cash flow from operations(1) $ 73,596 $ 52,277 41%
Per share - basic(1) $ 0.58 $ 0.43 35%
- diluted(1) $ 0.55 $ 0.41 34%
Operating earnings(1) $ 22,403 $ 15,354 46%
Net earnings $ 38,002 $ 10,059 278%
Per share - basic $ 0.30 $ 0.08 275%
- diluted $ 0.28 $ 0.08 250%
Capital expenditures $ 193,429 $ 96,379 101%
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(1) See cautionary statements following Management's Discussion and
Analysis.
OPERATING SUMMARY
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Three Months Ended March 31 2006 2005 Change
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Average production
Natural gas (mmcf/d) 142 130 9%
Liquids (bbls/d) 10,418 7,090 47%
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Total (boe/d) 34,029 28,714 19%
Realized prices
Natural gas ($/mcf) $ 7.64 $ 6.60 16%
Liquids ($/bbl) 53.62 46.23 16%
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Total ($/boe) $ 48.21 $ 41.25 17%
Field netback ($/boe) $ 29.15 $ 24.31 20%
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OPERATIONS REVIEW
Our first quarter 2006 drilling program was the most active first quarter
in our history. We drilled 121 wells with a 92% success rate during the three
months ended March 31, 2006, more than double the number of wells drilled in
the first quarter of 2005. We are on schedule to complete our planned 2006
capital program of 480 wells. Except as noted, well numbers refer to gross
wells.
Drilling Summary
Of the 121 wells drilled during the quarter, 95 were classified as
development wells and 26 as exploratory wells. The following table summarizes
drilling results to March 31, 2006.
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Gas Oil D&A Total Net Success
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Southern Alberta 52 1 1 54 50 98%
Central Alberta 28 2 4 34 23 88%
Peace River Arch 7 18 4 29 22 86%
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87 21 9 117 95 92%
Standing, cased wells 4 4
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Total 121 99
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Southern Alberta
Southern Alberta remains the primary focus of our activities. The Company
holds 804,007 (699,751 net) acres of land in the South, which are prospective
for multiple zones including Basal Quartz at Hooker, thrusted Belly River at
Callum, Wabamun/Crossfield, the Plains Belly River, and Edmonton/CBM.
During the first quarter of 2006, we drilled 56 (52 net) wells with a 98%
success rate in Southern Alberta. We plan to drill 277 wells in the area in
2006.
Plains Belly River and Edmonton Horseshoe Canyon Coalbed Methane
We drilled 44 Belly River wells in the Centron, Gladys, and Brant areas
during the first quarter, with all wells encountering multiple pay sections
and uphole Edmonton Horseshoe Canyon Coals. Locations were selected using the
Company's seismic and geological models, which have been critical to
identifying the best producible zones.
By the third quarter of 2006, we anticipate completing three 3D seismic
programs to assist in the identification of over 300 downspace locations in
the Belly River play. Compton currently has approval to drill two wells per
section on seven townships of land. The Alberta Energy and Utilities Board
announced a phased modification to spacing for the Belly River in Southern
Alberta that is intended to see the standard spacing increase from one well
per section to four wells per section. This initiative will allow us to ramp
up our Belly River/Edmonton drilling program in 2007 and accelerate production
growth from the Belly River/Edmonton zones.
Three Edmonton Horseshoe Canyon CBM wells were on production at Ghost
Pine throughout the first quarter of 2006, with each well producing an average
of 120 mcf/d. Three additional Edmonton Horseshoe Canyon CBM wells were
drilled at Ghost Pine during the quarter and 30 locations have been surveyed.
These wells are scheduled to be on stream early in the fourth quarter of 2006
with the completion of the necessary facilities, including compression and a
metering station.
During the second quarter of 2006, we began re-completing a number of
previously drilled Belly River wells in the Edmonton Horseshoe Canyon
formation. Of the more than 450 Belly River wells drilled to date by the
Company, we expect to re-complete at least 70 wells in the Edmonton formation
during the year.
Callum Thrusted Belly River
During the first quarter of 2006, operations continued on several fronts
on our thrusted Belly River Play at Callum.
Completion and testing operations are ongoing on the 6-7 well drilled in
the fourth quarter of 2005. Several sands remain to be tested, however, it is
evident that the sands sequence and natural fracturing encountered in the 8-13
well are not present at 6-7. The 8-13 well which came on production in late
December of 2005 at 8 mmcf/d from one sand continues to exceed our
expectations and has stabilized above 1.1 mmcf/d.
In March of 2006, an exploration well was drilled three miles north of
all previous drill wells and completion and testing operations are currently
ongoing.
During the quarter, two existing wells were recompleted in the Edmonton
sands which is present throughout the Company's acreage at Callum. At 8-26,
production increased fivefold to 1.6 mmcf/d. Production from the second well
increased only marginally. Recompletions are planned for two additional wells
during the second quarter.
We have been granted approval to license a well at 9-31, two miles south
of existing production. Drilling of the well cannot commence until July due to
environmental restrictions. We have also successfully negotiated surface
access for five additional pads on our Callum acreage to the south.
Environmental assessments for the pads are currently being completed and well
license applications will be requested during the second and third quarters.
As previously announced, we acquired our partner's working interest in
the Callum play during the quarter and now have 100% ownership of the play
including the lands, wells, the gas plant and related infrastructure.
We have planned to drill a total of ten wells at Callum during 2006.
Although results to date have varied significantly and been mixed, as typical
with an exploratory play, we remain very confident in pursuing this
challenging and technically complex play based upon the knowledge gained from
our activities.
Hooker Basal Quartz
In the first three months of 2006, seven wells were drilled targeting the
lower Cretaceous Basal Quartz resource play at Hooker. As a result of our 2005
drilling program, it is evident that the edges of the Hooker pool have yet to
be defined. Currently, we have identified 24 further locations to continue our
successful drilling program at Hooker.
Central Alberta
Central Alberta provides Compton with excellent exploration and
development drilling opportunities using analogous techniques gained through
our experience with unconventional gas development in Southern Alberta.
Compton has an average 55% working interest in 541,643 (297,475 net) acres of
land. In the first quarter of 2006, we drilled 35 (24 net) wells with an 88%
success rate, and we plan to drill a total of 90 wells in the area in 2006.
We drilled 12 wells at Niton during the first three months of 2006. All
wells encountered multiple sands and results met or exceeded our expectations.
We also completed a successful 13 well shallow gas winter drilling program at
Thornbury.
Peace River Arch
The Peace River Arch area, located north of Grande Prairie, contains
multi-zone exploration and development opportunities. This area includes both
light oil production at Cecil/Worsley and natural gas exploration at Howard
and Pouce Coupe. The Company averages a 61% working interest in 199,040
(121,634 net) acres of land in the area. We drilled 30 (22 net) wells in the
Arch with an 86% success rate during the first quarter of 2006 and plan to
drill a total of 106 wells in the area during the year.
Worsley
19 Charlie Lake oil wells were drilled at Worsley during the quarter. Two
of the wells were drilled on lands two miles north of the main Worsley pool
and encountered a separate Charlie Lake gas pool.
Building on the knowledge gained from our successful 2005 Charlie Lake
horizontal drilling program at Cecil, we drilled a horizontal well at the
south end of the Worsley pool in the first quarter 2006. The well is currently
producing 150-180 bbls/d and we now plan to drill up to 27 horizontal oil
wells in the Worsley area during 2006.
We also acquired an additional eight sections of land at Worsley, and
recent drilling activity has proved up multiple drilling locations on the
newly acquired acreage.
The Worsley gas plant has been successfully expanded with the
installation of a 15 mmcf/d amine unit, which became operational on March 24,
2006. The plant is now capable of processing 12 mmcf/d, with current
throughput estimated at 10 mmcf/d.
MANAGEMENT'S DISCUSSION AND ANALYSIS
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Management's Discussion and Analysis ("MD&A") is intended to provide both
an historical and prospective view of our activities. The MD&A was prepared as
at May 9, 2006 and should be read in conjunction with the interim unaudited
consolidated financial statements for the three months ended March 31, 2006
and the audited consolidated financial statements for the year ended
December 31, 2005, available in printed form on request and posted on the
Company's website.
Additional advisories with respect to forward looking statements, the use
of non-GAAP Financial Measures, and the use of BOE volumetric measures are set
out at the end of this MD&A.
EXECUTIVE SUMMARY
- Quarterly production averaged 34,029 boe/d, a 19% increase from
Q1 - 2005.
- Cash flow from operations was $74 million a 41% increase over
Q1 - 2005.
- Operating earnings rose 46% from the first quarter of 2005 to
$22 million.
- Net earnings were $38 million, an increase of 278% from the first
quarter of 2005.
- U.S.$150 million add-on Senior Note offering completed.
RESULTS OF OPERATIONS
Cash Flow from Operations and Net Earnings
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Three Months Ended March 31
($000s, except per share amounts) 2006 2005 Change
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Cash flow from operations(1) $ 73,596 $ 52,277 41%
Per share - basic $ 0.58 $ 0.43 35%
- diluted $ 0.55 $ 0.41 34%
Net earnings $ 38,002 $ 10,059 278%
Per share - basic $ 0.30 $ 0.08 275%
- diluted $ 0.28 $ 0.08 250%
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(1) Cash flow from operations represents net income before depletion and
depreciation, future income taxes, and other non-cash expenses.
Cash flow from operations for the first quarter of 2006 increased from
the comparative period in 2005 due to a combination of increased production
volumes and stronger realized commodity prices. Cash flow decreased 18% from
the fourth quarter of 2005 primarily as a result of significantly lower
realized prices which more than offset quarter over quarter production gains.
Net earnings for the first quarter increased 278% over the first quarter
of 2005 primarily as a result of increased production volumes and higher
realized commodity prices. Additionally, risk management activities during the
first quarter of 2006 resulted in an after tax gain of $10.8 million as
compared to an after tax loss of $5.6 million in 2005.
OPERATING EARNINGS
Operating earnings is a non-GAAP measure that adjusts net earnings by
non-operating items that we believe reduces the comparability of our
underlying financial performance between periods. The following reconciliation
of operating earnings has been prepared to provide investors with information
that is more comparable between periods.
Summary of Operating Earnings
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Three Months Ended March 31
($000s, except per share amounts) 2006 2005
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Net earnings, as reported $ 38,002 $ 10,059
Non-operational items, after tax
Unrealized foreign exchange loss 296 804
Unrealized risk management (gain) loss (10,854) 5,645
Stock-based compensation 1,532 754
Effect of tax rate changes on future income
tax liabilities (6,573) (1,908)
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Operating earnings $ 22,403 $ 15,354
Per share - basic $ 0.18 $ 0.13
- diluted $ 0.17 $ 0.12
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REVENUE
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Three Months Ended March 31 2006 2005 Change
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Average production
Natural gas (mmcf/d) 142 130 9%
Liquids (light oil & ngls) (bbls/d) 10,418 7,090 47%
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Total (boe/d) 34,029 28,714 19%
Benchmark prices
NYMEX (U.S.$/mmbtu) $ 9.08 $ 6.32 44%
AECO ($/GJ)
Monthly index $ 8.79 $ 6.34 39%
Daily index $ 7.16 $ 6.51 10%
WTI (U.S.$/bbl) $ 63.48 $ 50.03 27%
Edmonton Par ($/bbl) $ 68.96 $ 61.45 12%
Realized prices
Natural gas ($/mcf) $ 7.64 $ 6.60 16%
Liquids ($/bbl) 53.62 46.23 16%
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Total ($/boe) $ 48.21 $ 41.25 17%
Revenue ($000s)
Natural gas $ 97,364 $ 77,091 26%
Crude oil and ngls 50,280 29,498 70%
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Total $ 147,644 $ 106,589 39%
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Production for the three months ended March 31, 2006 increased 19% from
the first quarter of 2005 due to Compton's ongoing exploration and development
program. Production rose by 10% compared to the fourth quarter of 2005 as the
current period received the full benefit from a number of new wells placed on
stream late in the prior quarter.
Total revenue for the first quarter of 2006 increased from the
comparative period in 2005 due to a combination of additional production
volumes and higher realized prices. Revenue decreased 20% from the fourth
quarter of 2005 despite a 10% increase in production, as our average realized
commodity prices declined by 25% from the prior quarter.
Approximately 10% of Compton's natural gas production remains committed
to aggregator contracts, which received a price during the current quarter
that was, on average, $1.13/mcf less than prices received on non-aggregator
volumes.
ROYALTIES
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Three Months Ended March 31 2006 2005
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Royalties ($000s) $ 34,566 $ 25,804
Percentage of revenues 23.4% 24.2%
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The Alberta royalty structure is based upon commodity prices and well
productivity, with higher prices and well productivity attracting higher
royalty rates. The increased royalty rate associated with higher prices
experienced in the current quarter was offset by additional oil production and
a rise in the number of lower productivity gas wells, both of which attracted
lower royalty rates.
The average royalty rate in the first quarter of 2006 was consistent with
the rate incurred in the preceding quarter.
OPERATING EXPENSES
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Three Months Ended March 31 2006 2005
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Operating expenses ($000s) $ 20,749 $ 15,898
Operating expenses per boe ($/boe) $ 6.77 $ 6.15
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Operating costs per boe increased from the comparative period due to
additional lifting costs associated with a 68% increase in crude oil
production in the first quarter of 2006 compared to the first quarter of 2005.
Additionally, there has been an overall rise in costs as a result of
accelerated activity throughout the oil and gas industry increasing the demand
for and cost of goods and services. Particular increases of note include
salaries for additional field staff and contract operators, rising electricity
prices, salt water disposal, and emulsion processing.
Operating costs in the current quarter are consistent with those incurred
during the fourth quarter of 2005.
TRANSPORTATION
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Three Months Ended March 31 2006 2005
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Transportation costs ($000s) $ 3,072 $ 2,069
Transportation costs per boe ($/boe) $ 1.00 $ 0.80
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Higher transportation costs in first three months of 2006 resulted from a
combination of trucking costs associated with increased crude oil production
and surcharges associated with rising fuel costs. Transportation costs during
the current quarter are marginally lower than those realized during the
preceding quarter.
GENERAL AND ADMINISTRATIVE EXPENSES
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Three Months Ended March 31
($000s, except where noted) 2006 2005
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General and administrative expenses $ 9,797 $ 7,331
Capitalized general and administrative expenses (961) (1,582)
Operator recoveries (2,448) (1,523)
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Total general and administrative expenses $ 6,388 $ 4,226
General and administrative per boe ($/boe) $ 2.09 $ 1.64
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As budgeted, general and administrative costs were higher in the first
quarter of 2006 than in the comparative period in 2005 and fourth quarter of
2005. Employee costs associated with higher personnel levels was a major
contributor to the increase, as well as a general increase in salaries
necessary to attract and retain qualified personnel in a very competitive
industry. Other increases include insurance costs and costs associated with
the current regulatory environment.
INTEREST EXPENSE
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Three Months Ended March 31
($000s, except where noted) 2006 2005
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Interest on bank debt, net $ 3,136 $ 2,245
Interest on Senior Notes 6,796 4,893
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Interest charges 9,932 7,138
Finance charges 427 540
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Total interest and finance charges $ 10,359 $ 7,678
Total interest and finance charges per boe ($/boe) $ 3.38 $ 2.97
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Interest costs in the first quarter of 2006 increased from the prior
period and the fourth quarter of 2005 due to higher debt levels, precipitated
by capital expenditures exceeding cash flow throughout 2005. Interest costs
have also been affected by rising interest rates.
DEPLETION AND DEPRECIATION
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Three Months Ended March 31 2006 2005
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Depletion and depreciation ($000s) $ 34,410 $ 23,359
Depletion and depreciation per boe ($/boe) $ 11.24 $ 9.04
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Strong commodity prices have accelerated capital programs and competition
throughout the oil and gas industry raising the demand and costs for goods and
services. This increase in costs is reflected in increased finding,
development, and on-stream costs which in turn has resulted in an increase in
depletion and depreciation rates on a boe basis in the current quarter in
comparison to the prior period and fourth quarter of 2005.
FUTURE INCOME TAXES
Income taxes are recorded using the liability method of accounting.
Future income taxes are calculated based on the difference between the
accounting and income tax basis of an asset or liability. The classification
of future income taxes between current and non-current is based upon the
classification of the liabilities and assets to which the future income tax
amounts relate. The classification of a future income tax amount as current
does not imply a cash settlement of the amount within the following twelve
month period.
CAPITAL EXPENDITURES
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Three Months Ended March 31 ($000s) 2006 % 2005 %
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Land and seismic $ 24,959 13% $ 10,449 11%
Drilling and completions 101,494 52% 60,177 62%
Production facilities 39,898 21% 20,450 21%
Property acquisitions 27,431 14% 5,253 6%
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Sub-total 193,782 100% $ 96,329 100%
MPP (353) 50
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Total capital expenditures $ 193,429 $ 96,379
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Capital expenditures in 2006 have increased significantly over the
comparable period in 2005, reflecting our accelerated 2006 drilling program.
We drilled a total of 121 wells during the three month period ended March 31,
2006, as compared to 60 wells drilled during the first quarter of 2005. Lower
drilling and completion costs on a per well basis in the first quarter of 2006
reflect a higher percentage of shallow wells, as compared to the first quarter
of 2005.
RISK MANAGEMENT
Our financial results are impacted by external market risks associated
with fluctuations in commodity prices, interest rates, and the Canadian/U.S.
currency exchange rate. We use various financial instruments for non-trading
purposes to manage and partially mitigate our exposure to these risks.
Financial instruments used to manage risk are subject to periodic
settlements throughout the term of the instruments. Such settlements may
result in a gain or loss which is recognized as a risk management gain or loss
at the time of settlement. The mark-to-market value of an instrument
outstanding at the end of a reporting period reflects the value of the
instrument based upon market conditions existing as of that date. Any change
in value from that determined at the end of the prior period is recognized as
an unrealized Risk Management gain or loss.
Risk management gains and losses recognized in the quarter are summarized
in the following table.
Risk Management Gains and Losses
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Three Months Ended March 31 ($000s) 2006 2005
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Commodity contracts
Realized (gain) $ (1,986) $ (1,446)
Unrealized (gain) loss (18,902) 7,996
Cross currency interest rate swap
Unrealized loss 1,747 1,051
Foreign currency contracts
Realized (gain) (23) -
Unrealized loss 301 -
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Total risk management loss $ (18,863) $ 7,601
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Realized (gain) $ (2,009) $ (1,446)
Unrealized (gain) loss (16,854) 9,047
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Total risk management (gain) loss $ (18,863) $ 7,601
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Outstanding Commodity Contracts
The following table outlines commodity hedge transactions which were in
place during the first quarter of 2006 and/or are currently in place.
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Commodity Term Amount Average Price Index
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Natural gas
Collar Nov. 2005 - Mar. 2006 40,000 GJ/d Cdn$8.56 - $12.79 AECO
Fixed Nov. 2005 - Mar. 2006 10,000 GJ/d Cdn$8.60 AECO
Collar Apr. 2006 - Oct. 2006 45,000 GJ/d Cdn$8.33 - $12.23 AECO
Crude oil
Collar Jan. 2006 - Dec. 2006 3,000 bbls/d U.S.$55.00 - $75.17 WTI
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LIQUIDITY AND CAPITAL RESOURCES
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As at As at
March 31, Dec. 31,
($000s, except where noted) 2006 2005
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Working capital deficiency(1) $ 93,314 $ 62,431
Senior secured credit facilities 269,000 177,900
Senior term notes 358,008 357,640
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Total indebtedness $ 720,322 $ 597,971
Shareholders' equity
Capital stock $ 227,490 $ 226,444
Contributed surplus 11,213 9,173
Retained earnings 397,500 360,719
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Total equity $ 636,203 $ 596,336
Debt to cash flow from operations(1)(2) 2.09 1.93
Debt to book capitalization(1) 50% 47%
Debt to market capitalization(1) 25% 20%
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(1) Excludes unrealized risk management items net of related future
income taxes.
(2) Based on trailing 12 month cash flow from operations.
In March 2006, we issued U.S. $150 million of 7 5/8% Senior Notes due
2013. This issue was an add-on to the U.S. $300 million issue completed in
November 2005. Proceeds from the issue, which closed in early April, were used
to repay a portion of our outstanding debt under Compton's existing senior
secured credit facilities. The issue gives us the ability to draw on the
senior secured credit facilities to assist in funding our planned 2006 capital
program.
Our pro-forma long-term debt as at March 31, 2006, giving effect to the
add-on U.S. $150 million note issue, was:
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As at March 31 (Cdn $000s)
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Senior secured credit facilities $ 98,000
Senior term notes 529,008
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Total long term debt $ 627,008
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We expect internally generated cash flow from operations together with
the $191 million currently available through our existing credit facilities
and other available financing options, including readily accessible equity
markets and potential minor non-core property dispositions, will be sufficient
to fund our planned 2006 capital program, while still maintaining fiscal
responsibility.
OUTLOOK
In 2006, we will continue to focus on the development of our five natural
gas resource plays and conventional crude oil properties to maximize reserve
recognition and production growth. We drilled 121 (99 net) wells with a 92%
success rate in the three months ended March 31, 2006, more than double the
number of wells drilled in the first quarter of 2005, and we are currently on
track to complete our planned 480 well drilling program. Our efforts are
focused on infill drilling locations with close proximity to existing
pipelines to ensure quick tie-ins and production gains.
We anticipate 2006 cash flow of approximately $375 million to
$400 million based on budgeted realized prices of $65.00/bbl for crude oil and
$8.15/mcf for natural gas and average annual production in the range of 37,000
to 38,000 boe/d. Although commodity prices have declined in the first months
of 2006, our existing credit facilities together with cash flow are sufficient
to fund our planned $575 million capital program.
We have not modified our capital program or guidance at this time. As we
have previously stated and in keeping with our standard practice, we will
conduct a detailed review of our capital program and budget during the month
of June giving consideration to first half results, commodity prices, costs,
and general industry conditions. Should this review result in any amendment to
our outlook and plans for the second half of 2006, we will provide updated
guidance at that time.
QUARTERLY INFORMATION
The following table sets forth certain quarterly financial information of
the Company for the eight most recent quarters.
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2006 2005 2004
Q1 Q4 Q3 Q2 Q1 Q4 Q3 Q2
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Total revenue
(millions) $ 148 $ 184 $ 145 $ 122 $ 107 $ 101 $ 102 $ 99
Cash flow from
operations
(millions) $ 74 $ 90 $ 74 $ 62 $ 52 $ 42 $ 47 $ 48
Per share
- basic $ 0.58 $ 0.71 $ 0.58 $ 0.49 $ 0.43 $ 0.35 $ 0.40 $ 0.41
- diluted $ 0.55 $ 0.67 $ 0.56 $ 0.47 $ 0.41 $ 0.33 $ 0.38 $ 0.39
Net earnings
(millions) $ 38 $ 38 $ 11 $ 22 $ 10 $ 16 $ 22 $ 3
Per share
- basic $ 0.30 $ 0.30 $ 0.09 $ 0.17 $ 0.08 $ 0.14 $ 0.19 $ 0.03
- diluted $ 0.28 $ 0.28 $ 0.08 $ 0.17 $ 0.08 $ 0.13 $ 0.18 $ 0.02
Operating
earnings
(millions) $ 22 $ 33 $ 26 $ 19 $ 15 $ 6 $ 11 $ 15
Production
Natural gas
(mmcf/d) 142 133 130 130 130 128 123 122
Liquids
(bbls/d) 10,418 8,879 7,351 7,249 7,090 6,963 6,712 5,977
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Total (boe/d) 34,029 31,042 29,041 28,877 28,714 28,204 27,268 26,295
Average price
Natural gas
(mmcf/d) $ 7.64 $11.20 $ 8.46 $ 7.28 $ 6.60 $ 6.29 $ 6.48 $ 6.84
Liquids
(bbls/d) 53.62 57.99 64.75 54.20 46.23 42.88 46.60 42.75
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Total ($/boe) $48.21 $64.58 $54.31 $46.33 $41.25 $39.00 $40.78 $41.43
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In the first quarter of 2006, revenue and cash flow from operations
decreased from the fourth quarter of 2005 due to lower realized commodity
prices despite increased production volumes. Net earnings for the first
quarter of 2006 were also impacted by increased volumes and lower realized
prices. However in the first quarter of 2006, an after tax gain of
$10.8 million from risk management activities was recognized as compared to an
after tax loss of $5.6 million in the first quarter of 2005.
During 2005, revenue and cash flow from operations benefited from
increased production volumes and higher realized prices throughout the year.
Net income in the second quarter of 2005 rose due to a $6 million unrealized
after tax risk management gain. Higher realized commodity prices in the third
quarter of 2005 were offset by an unrealized after tax risk management loss of
$22 million, reducing net income from the prior quarter.
ADVISORIES
Management's Discussion and Analysis ("MD&A") is intended to provide both
an historical and prospective view of the Company's activities. The MD&A was
prepared as at May 10, 2006 and should be read in conjunction with the interim
unaudited consolidated financial statements for the three months ended
March 31, 2006 and the audited consolidated financial statements and MD&A for
the year ended December 31, 2005, available in printed form on request and
posted on the Company's website.
Forward Looking Statements
Certain information regarding the Company contained herein constitutes
forward looking statements under the meaning of applicable securities laws,
including 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, production, capital
expenditures, and planned wells in 2006, and (ii) 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 expectations reflected in such forward looking statements are reasonable,
it can give no assurance that such 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
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 and mechanical failures, uncertainties in the
estimates of reserves and in projections of future rates of production and
timing of development expenditures, general economic conditions, the actions
or inactions of third party operators and regulatory pronouncements. Compton
may, as considered necessary in the circumstances, update or revise forward
looking information, whether as a result of new information, future events, or
otherwise. The Company's forward looking statements are expressly qualified in
their entirety by this cautionary statement.
Non-GAAP Financial Measures
Included in the MD&A and elsewhere in this report are references to terms
used in the oil and gas industry such as cash flow from operations, cash flow
per share and operating earnings. 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.
Cash 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. Cash 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.
Operating 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. Operating earnings is used by the Company to
facilitate comparability of earnings between periods.
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. Compton has used the 6:1 boe measure which is the approximate
energy equivalency of the two commodities at the burner tip. However, boe does
not represent a value equivalency at the plant gate where Compton sells its
production volumes and therefore may be a misleading measure if used in
isolation.
Compton is an independent, public company actively engaged in the
exploration, development, and production of natural gas, natural gas liquids,
and crude oil in Western Canada. Compton also controls and manages the
operations of the Mazeppa Processing Partnership ("MPP"), which owns
significant midstream assets critical to the Company's activities in Southern
Alberta. The accounts of MPP are consolidated in the Company's financial
statements.
-------------------------------------------------------------------------
Compton Petroleum Corporation
Consolidated Balance Sheets
(thousands of dollars)
-------------------------------------------------------------------------
March 31, December 31,
2006 2005
------------ ------------
(unaudited)
Assets
Current
Cash $ 4,768 $ 8,954
Accounts receivable and other 112,005 132,484
Unrealized risk management gain
(Note 11a and b) 15,450 -
------------ ------------
132,223 141,438
Property and equipment 1,748,471 1,587,371
Goodwill 7,914 7,914
Deferred financing charges and other 13,011 13,156
Deferred risk management loss (Note 11c) 5,200 5,610
------------ ------------
$ 1,906,819 $ 1,755,489
------------ ------------
------------ ------------
Liabilities
Current
Accounts payable $ 210,087 $ 203,869
Unrealized risk management loss (Note 11a) - 3,150
Future income taxes 5,045 -
------------ ------------
215,132 207,019
Bank debt (Note 2) 269,000 177,900
Senior term notes (Note 3) 358,008 357,640
Asset retirement obligations (Note 5) 23,418 20,770
Unrealized risk management loss (Note 11d) 16,145 14,809
Future income taxes 320,792 312,117
Non-controlling interest (Note 6) 68,121 68,898
------------ ------------
1,270,616 1,159,153
------------ ------------
Shareholders' equity
Capital stock (Note 7) 227,490 226,444
Contributed surplus (Note 8a) 11,213 9,173
Retained earnings 397,500 360,719
------------ ------------
636,203 596,336
------------ ------------
$ 1,906,819 $ 1,755,489
------------ ------------
------------ ------------
See accompanying notes to the consolidated financial statements.
-------------------------------------------------------------------------
Compton Petroleum Corporation
Consolidated Statements of Earnings
(unaudited) (thousands of dollars, except per share amounts)
-------------------------------------------------------------------------
Three months ended March 31, 2006 2005
----------------------------------------------------------- ------------
Revenue
Oil and natural gas revenues $ 147,644 $ 106,589
Royalties (34,566) (25,804)
------------ ------------
113,078 80,785
------------ ------------
Expenses
Operating 20,749 15,898
Transportation 3,072 2,069
General and administrative 6,388 4,226
Interest and finance charges (Note 4) 10,359 7,678
Depletion and depreciation 34,410 23,359
Foreign exchange loss (Note 12) 365 986
Accretion of asset retirement obligations 568 422
Stock-based compensation 2,379 1,208
Risk management loss (gain) (Note 11e) (18,863) 7,601
------------ ------------
59,427 63,447
------------ ------------
Earnings before taxes and non-controlling
interest 53,651 17,338
------------ ------------
Income taxes (Note 10)
Current 414 430
Future 13,720 5,514
------------ ------------
14,134 5,944
------------ ------------
Earnings before non-controlling interest 39,517 11,394
Non-controlling interest 1,515 1,335
------------ ------------
Net earnings $ 38,002 $ 10,059
------------ ------------
------------ ------------
Net earnings per share (Note 9)
Basic $ 0.30 $ 0.08
------------ ------------
------------ ------------
Diluted $ 0.28 $ 0.08
------------ ------------
------------ ------------
-------------------------------------------------------------------------
Compton Petroleum Corporation
Consolidated Statements of Retained Earnings
(unaudited) (thousands of dollars)
-------------------------------------------------------------------------
Three months ended March 31, 2006 2005
----------------------------------------------------------- ------------
Retained earnings, beginning of year $ 360,719 $ 284,712
Net earnings 38,002 10,059
Premium on redemption of shares (Note 7) (1,221) (1,951)
------------ ------------
Retained earnings, end of period $ 397,500 $ 292,820
------------ ------------
------------ ------------
See accompanying notes to the consolidated financial statements.
-------------------------------------------------------------------------
Compton Petroleum Corporation
Consolidated Statements of Cash Flow
(unaudited) (thousands of dollars)
-------------------------------------------------------------------------
Three months ended March 31, 2006 2005
----------------------------------------------------------- ------------
Operating activities
Net earnings $ 38,002 $ 10,059
Amortization of deferred charges and other 424 469
Depletion and depreciation 34,410 23,359
Accretion of asset retirement obligations 568 422
Unrealized foreign exchange loss 368 990
Future income taxes 13,720 5,514
Unrealized risk management loss (gain) (16,854) 9,047
Stock-based compensation 2,379 1,208
Asset retirement expenditures (936) (126)
Non-controlling interest 1,515 1,335
------------ ------------
73,596 52,277
Change in non-cash working capital 23,391 (6,909)
------------ ------------
96,987 45,368
------------ ------------
Financing activities
Issuance (repayment) of bank debt 91,100 (43,000)
Proceeds from share issuances (net) 860 88,191
Distributions to partner (2,292) (2,293)
Redemption of common shares (1,374) (2,168)
Issue costs on senior notes (281) -
Change in non-cash working capital (1,449) 5,437
------------ ------------
86,564 46,167
------------ ------------
Investing activities
Property and equipment additions (165,662) (91,000)
Property acquisitions (27,531) (5,253)
Property dispositions 700 -
Change in non-cash working capital 4,756 14,416
------------ ------------
(187,737) (81,837)
------------ ------------
Change in cash (4,186) 9,698
Cash, beginning of year 8,954 10,068
------------ ------------
Cash, end of period $ 4,768 $ 19,766
------------ ------------
------------ ------------
See accompanying notes to the consolidated financial statements.
-------------------------------------------------------------------------
Compton Petroleum Corporation
Notes to the Consolidated Financial Statements
(unaudited) (Tabular amounts in thousands of dollars, unless otherwise
stated)
March 31, 2006
-------------------------------------------------------------------------
1. Basis of presentation
Compton Petroleum Corporation (the "Company") is in the business of
exploration for and production of petroleum and natural gas reserves
in the Western Canadian Sedimentary Basin.
The consolidated financial statements include the accounts of the
Company and its wholly owned subsidiaries. The consolidated financial
statements also include the accounts of Mazeppa Processing
Partnership in accordance with Accounting Guideline 15 ("AcG-15"),
Consolidation of Variable Interest Entities, as outlined in Note 6.
The consolidated interim financial statements of the Company have
been prepared by Management in accordance with accounting principles
generally accepted in Canada. Certain information and disclosure
normally required to be included in notes to annual consolidated
financial statements have been condensed or omitted. The consolidated
interim financial statements should be read in conjunction with the
audited consolidated financial statements and the notes thereto in
the Company's annual report for the year ended December 31, 2005. The
consolidated interim financial statements have been prepared
following the same accounting policies and methods of computation as
the audited consolidated financial statements for the year ended
December 31, 2005.
All amounts are presented in Canadian dollars unless otherwise
stated.
2. Credit facilities
March 31, December 31,
2006 2005
------------ ------------
Authorized $ 289,000 $ 289,000
------------ ------------
------------ ------------
Prime rate $ 114,000 $ 22,900
Bankers' acceptance 155,000 155,000
------------ ------------
Utilized $ 269,000 $ 177,900
------------ ------------
------------ ------------
As at March 31, 2006, the Company had arranged authorized senior
credit facilities with a syndicate of Canadian banks in the amount of
$289 million. Advances under the facilities can be drawn and
currently bear interest as follows:
Prime rate plus 0.15%
Bankers' Acceptance rate plus 1.15%
LIBOR rate plus 1.15%
Margins are determined based on the ratio of total consolidated debt
to consolidated cash flow. These facilities reach term on July 5,
2006, and will mature 366 days later on July 6, 2007. These
facilities are currently under review by the Company's banking
syndicate and are expected to be renewed under similar terms and
conditions.
The senior credit facilities are secured by a first fixed and
floating charge debenture in the amount of $600 million covering all
the Company's assets and undertakings.
3. Senior term notes
March 31, December 31,
2006 2005
------------ ------------
Senior term notes
U.S.$300 million, 7.625% due
December 1, 2013 $ 350,130 $ 349,770
U.S.$6.75 million, 9.90% due
May 15, 2009 7,878 7,870
------------ ------------
$ 358,008 $ 357,640
------------ ------------
------------ ------------
On April 4, 2006, the Company issued an additional U.S.$150 million
7.625% senior term notes due 2013 under the same terms and conditions
as the 7.625% notes outstanding at March 31, 2006. The proceeds from
the issue of the notes was used to repay a portion of the debt
outstanding under the Company's senior credit facilities. The Company
also intends to use a portion of the proceeds to redeem the balance
of the U.S.$6.75 million 9.90% senior notes on May 16, 2006, being
the first call date, at 104.95%.
The 7.625% notes are not redeemable prior to December 1, 2009, except
in limited circumstances. After that time, they can be redeemed in
whole or part, at the rates indicated below:
December 1, 2009 103.813%
December 1, 2010 101.906%
December 1, 2011 and thereafter 100.000%
The senior notes are subordinate to the Company's senior credit
facilities.
4. Interest and finance charges
Amounts charged to expense during the period ended are as follows:
Three months ended March 31, 2006 2005
------------------------------------------------------- ------------
Interest on bank debt, net $ 3,136 $ 2,245
Interest on senior term notes 6,796 4,893
Finance charges 427 540
------------ ------------
$ 10,359 $ 7,678
------------ ------------
------------ ------------
Finance charges include the amortization of deferred charges and
current year expenses.
5. Asset retirement obligations
The following table presents a reconciliation of the beginning and
ending aggregate carrying amount of the obligations associated with
the retirement of oil and gas assets:
March 31, December 31,
2006 2005
------------ ------------
Asset retirement obligations, beginning
of year $ 20,770 $ 18,006
Liabilities incurred 2,145 5,218
Liabilities settled and disposed (65) (1,275)
Accretion expense 568 1,975
Revision of estimates - (3,154)
------------ ------------
Asset retirement obligations, end of
period $ 23,418 $ 20,770
------------ ------------
------------ ------------
6. Non-controlling interest
Mazeppa Processing Partnership ("MPP" or "the Partnership") is a
limited partnership organized under the laws of the province of
Alberta and owns certain midstream facilities, including gas plants
and pipelines in Southern Alberta. The Company processes a
significant portion of its production from the area through these
facilities pursuant to a processing agreement with MPP. The Company
does not have an ownership position in MPP, however, the Company,
through a management agreement, manages the activities of MPP and is
considered to be the primary beneficiary of MPP's operations.
Pursuant to AcG-15, these consolidated financial statements include
the assets, liabilities and operations of the Partnership. Equity in
the Partnership, attributable to the partners of MPP, is recorded on
consolidation as a non-controlling interest and is comprised of the
following:
March 31, December 31,
2006 2005
------------ ------------
Non-controlling interest,
beginning of year $ 68,898 $ 71,537
Earnings attributable to
non-controlling interest 1,515 6,533
Distributions to limited partner (2,292) (9,172)
------------ ------------
Non-controlling interest, end of period $ 68,121 $ 68,898
------------ ------------
------------ ------------
MPP has guaranteed payment of certain obligations of its limited
partner under a credit agreement between the limited partner and a
syndicate of lenders. The maximum liability of the Partnership under
the guarantee is limited to amounts due and payable to MPP by the
Company pursuant to the processing agreement. The processing
agreement has a five year term ending April 1, 2009, at which time
Compton may renew the agreement, purchase the Partnership units or
allow the sale of the Partnership units to a third party. The maximum
liability at March 31, 2006 is $28.3 million. The Company has
determined that its exposure to loss under these arrangements is
minimal, if any.
7. Capital stock
Issued and outstanding
March 31, 2006 December 31, 2005
---------------------- ----------------------
Number Number
of shares Amount of shares Amount
---------- ---------- ---------- ----------
(000s) (000s)
Common shares
outstanding,
beginning of year 127,263 $ 226,444 117,354 $ 135,526
Shares issued for
cash, net - - 7,500 87,294
Shares issued under
stock option plan 137 1,199 2,926 4,424
Shares repurchased (86) (153) (517) (800)
---------- ---------- ---------- ----------
Common shares
outstanding, end
of period 127,314 $ 227,490 127,263 $ 226,444
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
The Company maintains a Normal Course Issuer Bid program on an annual
basis. Under the current bid, the Company may purchase for
cancellation up to 6,000,000 of its common shares, representing
approximately 5.0% of the issued and outstanding common shares at the
time the bid received regulatory approval.
During the three months ended March 31, 2006, the Company purchased
for cancellation 86,000 common shares at an average price of $15.97
per share (December 31, 2005 - 516,600 shares at an average price of
$11.84 per share) pursuant to the normal course issuer bid. The
excess of the purchase price over book value has been charged to
retained earnings.
8. Stock-based compensation plans
a) Stock option plan
The Company has implemented a stock option plan for Directors,
Officers and employees. The exercise price of each option
approximates the market price for the common shares on the date the
option was granted. Options granted under the plan before June 1,
2003 are generally fully exercisable after four years and expire ten
years after the grant date. Options granted under the plan after
June 1, 2003 are generally fully exercisable after four years and
expire five years after the grant date.
The following tables summarize the information relating to stock
options:
March 31, 2006 December 31, 2005
---------------------- ----------------------
Weighted Weighted
average average
Stock exercise Stock exercise
Options price options price
---------- ---------- ---------- ----------
(000s) (000s)
Outstanding, beginning
of year 11,446 $ 6.13 11,655 $ 3.51
Granted 1,589 $ 14.61 2,930 $ 11.89
Exercised (137) $ 6.27 (2,926) $ 1.32
Cancelled (141) $ 10.24 (213) $ 8.30
---------- ---------- ---------- ----------
Outstanding, end of
period 12,757 $ 7.14 11,446 $ 6.13
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
Exercisable, end of
period 6,780 $ 3.90 6,219 $ 3.38
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
The range of exercise prices of stock options outstanding and
exercisable at March 31, 2006 is as follows:
Outstanding Options Exercisable Options
----------------------------- --------------------
Weighted
average
remaining
contrac- Weighted Weighted
Range of Number of tual average Number of average
exercise options life exercise options exercise
prices outstanding (years) price outstanding price
----------------------------- ------ --------- ----------- -------
(000s) (000s)
$0.80 - $2.99 2,644 2.5 $1.55 2,644 $1.55
$3.00 - $3.99 1,482 5.1 $3.47 1,330 $3.43
$4.00 - $4.99 1,571 5.9 $4.30 1,287 $4.26
$5.00 - $6.99 1,155 2.7 $5.87 590 $5.88
$7.00 - $9.99 1,405 3.1 $7.59 525 $7.55
$10.00 - $12.99 2,585 4.0 $11.60 387 $11.90
$13.00 - $18.39 1,915 4.8 $14.45 17 $13.42
-------- ------- --------- --------- ---------
12,757 4.0 $7.14 6,780 $3.90
-------- ------- --------- --------- ---------
-------- ------- --------- --------- ---------
The Company has recorded stock-based compensation expense in the
consolidated statement of earnings for stock options granted to
Directors, Officers and employees after January 1, 2003 using the
fair value method.
The fair value of each option granted is estimated on the date of
grant using the Black-Scholes option pricing model with weighted
average assumptions for grants as follows:
Three months ended March 31, 2006 2005
------------------------------------------------------- ------------
Weighted average fair value of options
granted $7.55 $5.53
Risk-free interest rate 4.0% 3.7%
Expected life (years) 5.0 5.0
Expected volatility 44.0% 44.5%
The following table presents the reconciliation of contributed
surplus with respect to stock-based compensation:
March 31, December 31,
2006 2005
------------ ------------
Contributed surplus, beginning of year $ 9,173 $ 3,840
Stock-based compensation expense 2,379 5,903
Stock options exercised (339) (570)
------------ ------------
Contributed surplus, end of period $ 11,213 $ 9,173
------------ ------------
------------ ------------
b) Share appreciation rights plan
CICA Handbook section 3870 requires recognition of compensation costs
with respect to changes in the intrinsic value for the variable
component of fixed share appreciation rights ("SARs"). During the
periods ended March 31, 2006 and 2005, there were no significant
compensation costs related to the outstanding variable component of
these SARs. The liability related to the variable component of these
SARs amounts to $1.4 million, which is included in accounts payable
as at March 31, 2006 (December 31, 2005 - $1.4 million). All
outstanding options having a variable component expire at various
times through 2011.
9. Per share amounts
The following table summarizes the common shares used in calculating
net earnings per common share:
Three months ended March 31, 2006 2005
------------------------------------------------------- ------------
(000s) (000s)
Weighted average common shares outstanding
- basic 127,300 121,225
Effect of stock options 7,268 6,153
------------ ------------
Weighted average common shares outstanding
- diluted 134,568 127,378
------------ ------------
------------ ------------
10. Income taxes
The following table reconciles income taxes calculated at the
Canadian statutory rates with actual income taxes:
Three months ended March 31, 2006 2005
------------------------------------------------------- ------------
Earnings before taxes and non-controlling
interest $ 53,651 $ 17,338
------------ ------------
Canadian statutory rates 35.6% 37.6%
Expected income taxes $ 19,100 $ 6,519
Effect on taxes resulting from:
Non-deductible crown charges 673 3,053
Resource allowance (289) (2,361)
Non-deductible stock-based compensation 848 454
Federal capital tax 401 430
Effect of tax rate changes (6,573) (1,908)
Non-taxable portion of foreign
exchange loss 66 186
Other (92) (429)
------------ ------------
Provision for income taxes $ 14,134 $ 5,944
------------ ------------
Current
Income taxes $ 13 $ -
Federal capital tax 401 430
Future 13,720 5,514
------------ ------------
$ 14,134 $ 5,944
------------ ------------
------------ ------------
Effective tax rate 26.3% 34.3%
------------ ------------
------------ ------------
A significant portion of the Company's taxable income is generated by
a partnership. Income taxes are incurred on the partnership's taxable
income in the year following its inclusion in the Company's
consolidated net earnings. Current income tax will vary and is
dependent upon the amount of capital expenditures incurred and the
method of deployment.
11. Financial instruments
Derivative financial instruments and risk management activities
The Company is exposed to risks from fluctuations in commodity
prices, interest rates and Canada/US currency exchange rates. The
Company utilizes various derivative financial instruments for non-
trading purposes to manage and mitigate its exposure to these risks.
Effective January 1, 2004, the Company elected to account for all
derivative financial instruments using the mark-to-market method.
Risk management activities during the period, utilizing derivative
instruments, relate to commodity price hedges, foreign currency swaps
and cross currency interest rate swap arrangements and are summarized
below:
a) Commodity price hedges
The Company enters into hedge transactions relating to crude oil and
natural gas prices to mitigate volatility in commodity prices. The
contracts entered into are forward transactions providing the Company
with a range of prices on the commodities sold. Outstanding hedge
contracts and the associated unrealized, mark-to-market, gains or
losses, at March 31, 2006 are:
Daily Mark-to-
Notional Market
Commodity Term Volume Prices Received Gain (Loss)
--------- ---- -------- --------------- -----------
Natural gas Apr. 06 - 42,857 mcf $8.73/mcf $ 17,312
Collar Oct. 06 - $12.87/mcf
Crude oil Jan. 06 - 3,000 bbls US$55.00/bbl (1,561)
Collar Dec. 06 - US$75.17/bbl
-----------
Unrealized risk management gain $ 15,751
-----------
-----------
At December 31, 2005, the unrealized hedge loss on outstanding
commodity contracts was $3.2 million.
b) Foreign currency risk management
The Company is exposed to fluctuations in the exchange rate between
the Canadian dollar and U.S. dollar and when appropriate, enters into
agreements to fix the exchange rate in order to manage the risk.
At period end the Company had the following contract in place:
Mark-to-
Average Market
Exchange Gain
Foreign Currency Term Notional Amount Rate (Loss)
---------------- ---- --------------- -------- ---------
Currency forward Jan. 06 U.S.$165,000/day 1.1570 $ (301)
- Dec. 06
-----------
Unrealized risk management loss $ (301)
-----------
-----------
c) Deferred risk management loss
As at January 1, 2004, the Company recorded a liability and a
deferred risk management loss of $10.9 million relating to then
outstanding commodity hedges and the interest rate swap. The deferred
loss is being amortized to earnings over the life of the contracts
outstanding at the time of initial measurement. The remaining balance
of $5.2 million at March 31, 2006 (December 31, 2005 - $5.6 million)
relates to the interest rate swap and will be charged to earnings in
annual amounts of $1.6 million until eliminated in 2009.
d) Cross currency interest rate swap
Concurrent with the closing of the 9.90% senior notes offering in
2002, the Company entered into interest rate swap arrangements,
expiring May 2009 that convert fixed rate U.S. dollar denominated
interest obligations into floating rate Canadian dollar denominated
interest obligations. On purchase of the majority of the 9.90% senior
notes in November 2005, the Company elected not to collapse the swap
and incur the associated costs. At March 31, 2006, the Company valued
the liability relating to future unrealized losses on the swap
arrangements to be $16.1 million (December 31, 2005 - $14.8 million)
on a mark-to-market basis.
e) Risk management (gain) loss
The following table summarizes (gains) and losses recognized during
the year relating to the foregoing:
March 31,
-----------------------------------------------------
Commodity Foreign Interest 2006 2005
Contracts Currency Rate Swap Total Total
---------- ---------- ---------- ---------- ----------
Unrealized
Amortization
of deferred
loss $ - $ - $ 411 $ 411 $ 411
Change in fair
value (18,902) 301 1,336 (17,265) 8,636
---------- ---------- ---------- ---------- ----------
(18,902) 301 1,747 (16,854) 9,047
Realized
Cash
settlements (1,986) (23) - (2,009) (1,446)
---------- ---------- ---------- ---------- ----------
Total $ (20,888) $ 278 $ 1,747 $ (18,863) $ 7,601
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
12. Foreign exchange (gain) loss
Amounts charged to foreign exchange (gain) loss during the period
ended were as follows:
Three months ended March 31, 2006 2005
------------------------------------------------------- ------------
Foreign exchange on translation of
U.S.$ debt $ 368 $ 990
Other foreign exchange (3) (4)
------------ ------------
Total loss $ 365 $ 986
------------ ------------
------------ ------------
13. Supplemental cash flow information
Amounts actually paid during the period relating to interest expense
and capital taxes are as follows:
Three months ended March 31, 2006 2005
------------------------------------------------------- ------------
Interest paid $ 1,671 $ 2,389
Capital taxes paid 180 550
------------ ------------
$ 1,851 $ 2,939
------------ ------------
------------ ------------
CONFERENCE CALL
Compton will be conducting a conference call and audio webcast May 11,
2006 at 9:30 a.m. (MST) or 11:30 a.m. (EST) to discuss the Company's 2006
first quarter financial and operating results. To participate in the
conference call, please contact the Conference Operator at 9:20 a.m. (MST),
ten minutes prior to the call.
Conference Operator Dial-in Number: Toll-Free 1-800-257-6566
Audio webcast URL:
http://www.cnxmarketlink.ca/en/webcast/viewEvent.cgi?eventID(equal
sign)1476200
The audio replay will be available two hours after the conclusion of the
conference call and will be accessible until May 18, 2006. Callers may dial
toll-free 1-877-289-8525 and enter access code 21188402 (followed by the pound
key).
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.
>>
%SEDAR: 00003803E %CIK: 0001043572
