Translate
CALGARY, Aug. 11 /CNW/ - Compton Petroleum Corporation ("Compton" or the "Company") is pleased to announce its financial and operating results for the quarter ended June 30, 2008 and provide an update on its strategic review process.
STRATEGIC REVIEW PROCESS
On February 28, 2008, the Board of Directors of Compton announced that it was conducting a formal review of the Company's business plans and strategic alternatives for enhancing shareholder value. The Board appointed a Special Committee comprised of independent directors to conduct the review and retained Tristone Capital Inc. and UBS Securities Canada Inc. as independent financial advisors to assist the Company in the conduct of the review. The review included, among other considerations, the exploration of potential asset divestments, equity alternatives, strategic alliances, joint venture opportunities, mergers or a corporate transaction.
On June 11, 2008, the Special Committee received independent reports and recommendations from its financial advisors and after due deliberation and on the recommendation of the Special Committee, the Board of Directors determined to commence a process to seek a buyer for all the outstanding shares of the Company.
Currently, the Company together with the advisors, are in the process of preparing a Data Room that will be accessible to interested purchasers in early September. The sale process is expected to conclude this autumn.
The Company is pursuing an active third quarter drilling program, however, in view of the sales process, will not be providing updated guidance nor hosting a conference call in relation to this news release.
SECOND QUARTER 2008 HIGHLIGHTS
- Second quarter 2008 natural gas production of 150 mmcf/d, a 15% year
over year increase.
- Total second quarter production averaged 30,557 boe/d, a 6% year over
year increase.
- Funds flow from operations of $77 million for the quarter ended
June 30, 2008, a 58% increase over last year.
- Second quarter 2008 adjusted net earnings from operations of
$22 million, a 144% year over year increase.
FINANCIAL SUMMARY
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
($000s, except June 30 June 30
per share
amounts) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Gross revenue $186,797 $126,171 48% $349,230 $267,048 31%
Funds flow from
operations(1)(2) $ 76,651 $ 48,582 58% $145,973 $117,365 24%
Per share
- basic(1) $ 0.59 $ 0.38 55% $ 1.13 $ 0.91 24%
- diluted(1) $ 0.58 $ 0.36 61% $ 1.10 $ 0.88 25%
Adjusted net
earnings from
operations(1) $ 22,319 $ 9,137 144% $ 41,336 $ 31,471 31%
Per share
- basic(1) $ 0.17 $ 0.07 143% $ 0.32 $ 0.24 33%
- diluted(1) $ 0.17 $ 0.07 143% $ 0.31 $ 0.24 29%
Net earnings $ (8,561) $ 45,307 -119% $ (6,942) $ 59,026 -112%
Per share
- basic $ (0.07) $ 0.35 -120% $ (0.05) $ 0.46 -111%
- diluted $ (0.07) $ 0.34 -121% $ (0.05) $ 0.44 -111%
Capital
expenditures $ 64,138 $ 51,133 25% $175,665 $112,500 56%
-------------------------------------------------------------------------
(1) See advisory statements at the beginning of Management's Discussion
and Analysis.
(2) Funds flow from operations was referred to as adjusted cash flow from
operations in prior filings.
OPERATING SUMMARY
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Average daily
production
Natural gas
(mmcf/d) 150 130 15% 160 139 15%
Liquids (bbls/d) 5,643 7,199 -22% 5,326 7,959 -33%
-------------------------------------------------------------------------
Total (boe/d) 30,557 28,918 6% 31,916 31,105 3%
Realized prices
Natural gas
($/mcf) $ 9.42 $ 6.92 36% $ 8.39 $ 7.09 18%
Liquids ($/bbl) $ 110.37 $ 60.49 82% $ 103.13 $ 57.74 79%
-------------------------------------------------------------------------
Total ($/boe) $ 67.18 $ 47.94 40% $ 60.12 $ 47.43 27%
Field netback
($/boe) $ 37.60 $ 28.55 32% $ 34.97 $ 28.22 24%
-------------------------------------------------------------------------
OPERATIONS REVIEW
Consistent with the industry in general, our field activities during the second quarter of 2008 were restricted by spring break-up and extended wet field conditions that reduced drilling, well completions, and tie-ins. As a result we drilled a total of 34 wells during the quarter as compared to the 99 wells drilled in Q1 2008. The 34 wells drilled during the quarter included six horizontal wells: three at Niton, one at Caroline, and two at Hooker.
With improved field conditions, activity has increased markedly with a primary focus of applying horizontal wells combined with multi-stage frac completions to our deeper resource plays. As of August 1, 2008, we have 11 operated and two non-operated drilling rigs working. Two drilling rigs are drilling horizontal wells at Hooker, and four rigs are operating at Niton, with three drilling horizontals targeting the Rock Creek and one drilling a vertical Rock Creek test. At Caroline, we have two drilling rigs operating, one drilling a Lower Mannville horizontal test and one drilling a vertical well. In the Plains Belly River play, we have three drilling rigs operating in southern Alberta and finally at Callum, we have just rig released our first horizontal well located using 3D seismic and targeting the Thrusted Belly River. Multi stage fracs are planned for all of the horizontal wells.
Drilling Summary
Of the total 133 (106 net) wells drilled during the first half of this year, 130 wells were classified as development and three as exploratory wells. The following table summarizes our drilling results in the first half of the year.
------------------------------------------------------------------------- First Half 2008 Drill Summary Gas Oil D&A Total Net Success ------------------------------------------------------------------------- Southern Alberta 80 - 2 82 79 92% Central Alberta 38 5 3 46 22 97% ------------------------------------------------------------------------- Standing, cased wells 5 5 ------------------------------------------------------------------------- Total 118 5 5 133 106 96% -------------------------------------------------------------------------
SOUTHERN ALBERTA: FOOTHILLS
During the second quarter at our thrusted foothills Belly River gas play at Callum/Cowley, we spudded our first horizontal well using proprietary 3D seismic. The well is located at 14-5-7-1W5M, and was successfully completed using multi stage frac technology. The 14-5 horizontal leg is oriented to maximize the number of natural fractures encountered across this over-pressured natural gas play, and is projected to be on-stream during the third week of August. There are four immediate offset wells located using 3D seismic that Compton is in the process of licensing.
DEEP BASIN GAS
Compton has three Deep Basin natural gas resource plays: the Basal Quartz sands at Hooker in southern Alberta, the Gething/Rock Creek sands at Niton and in central Alberta, and the shallow Plains Belly River play in southern Alberta.
Southern Alberta: Hooker
In the second quarter of 2008, the Hooker pool reached a 100 bcf cumulative production milestone since its discovery by Compton in 1999. During the quarter, we placed our second horizontal Basal Quartz well on production at 15-30-16-29W4M, with an initial production rate of 2.2 mmcfe/d, whereas offsetting vertical wells also on the edge of the play produce, on average, 40 to 100 mcfe/d. The first two horizontal wells successfully targeted the tight margins on the western edge of the Hooker channel. Compton currently has two horizontal wells drilling at Hooker. The third horizontal well at 13-34-18-29W4M will target the middle of the channel, with the fourth well at 1-18-17-29W4M continuing to target the tighter formations on the western edge of the play.
Hooker is a deep basin channel sand deposit covering over five townships. Compton is the major landholder and operator in the area, with over 120 net development sections. Horizontal wells together with multi stage frac technology increase the probability of accessing reservoir quality rock with increased gas production rates. Compton is planning to drill up to six additional Hooker horizontal wells in the second half of 2008.
Central Alberta: Niton and Caroline
In the Niton area, Compton controls over 270 gross sections of land in this Deep Basin multi-zone area, mainly targeting tight Rock Creek and Ellerslie (Hooker BQ equivalent) sands.
During the first half of 2008, Compton drilled 10 Rock Creek horizontals as compared to a total of eight horizontal Rock Creek wells drilled in all of 2007.
Multiple horizontal locations have been identified on this Rock Creek trend. Compton currently has three rigs in the area drilling high impact Rock Creek horizontal wells. We plan to drill eight Rock Creek horizontal wells and two Ellerslie horizontal wells in the second half of 2008.
During the second quarter of 2008, we also completed compressor and pipeline installations at Edson 5-26-53-17W5M on May 30, 2008. The system is 100% Compton owned. The most recent horizontal well at 4-28-52-17W5 tested at rates of 8.1 mmscf/d on post frac cleanup with the well being tested in line.
Also at Niton, Compton has earned 11 sections of land on farm-ins. Compton has drilled three Rock Creek vertical oil wells and three Rock Creek horizontal gas wells on these lands.
At Caroline, where we have 100 gross sections of land, we are currently drilling the area's first horizontal well targeting a sand similar to our Hooker Basal Quartz pool. With success, a number of follow-ups have been identified.
At Gilby, immediately north of Caroline, on a play similar to our Niton Rock Creek area, we drilled a successful Rock Creek vertical well. We hold five offset sections to this well and multiple Rock Creek horizontal locations have been identified as follow-ups to our vertical discovery.
SHALLOW GAS - Plains Belly River and Edmonton Group
The Plains Belly River and overlying Edmonton shallow gas zones are comprised of multiple sands, silts, shales, and coals, with an average of 900 vertical metres being gas charged. Our land covers more than 1,200 sections in southern Alberta. We are continuing to focus on downspacing, development drilling, and recompletions in order to establish a resource manufacturing and processing model designed to maximize production and capital efficiency.
In the second quarter of 2008, we drilled 24 Belly River wells. We currently have three rigs working on our Plains Belly River gas play. The wells typically take two to three days to drill, and are attractive at current AECO gas prices. We now have over 500 drilling locations identified and in various stages of acquisition.
At Centron, adjacent to the city of Calgary, Compton acquired and licensed a pipeline system that is currently under construction and will tie in eight standing gas wells. The standing wells are analogues to the well at 02/06-22-22-28W4M, which had an initial production rate of 740 mcf/d.
Southern Alberta: Vulcan
Compton placed on production a horizontal Vulcan Lower Mannville I oil well in June 2008. The well is currently producing 225 bbls/d. This pool received Good Production Practice (GPP) on July 19, 2008, which has removed certain production restrictions. We are currently upgrading our Vulcan 9-29-15-25W4M oil battery to accommodate the increased oil and gas production volumes. We anticipate these expansion requirements will benefit future water flood plans for the area. One additional well is planned for the second half of 2008.
MANAGEMENT'S DISCUSSION AND ANALYSIS
-------------------------------------------------------------------------
ADVISORIES
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 August 8, 2008 and should be read in conjunction with the interim unaudited consolidated financial statements for the six months ended June 30, 2008 and the audited consolidated financial statements for the year ended December 31, 2007, available in printed form on request and posted on Compton's website.
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 MD&A solely for the purpose of generally disclosing Compton's views of its 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 MD&A and elsewhere in this report are references to terms used in the oil and gas industry such as funds flow from operations, cash flow per share, adjusted net earnings from operations, adjusted EBITDA, and enterprise value. 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 net earnings from operations 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 net earnings from operations 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.
EXECUTIVE SUMMARY
- Second quarter 2008 natural gas production of 150 mmcf/d, a 15% year
over year increase.
- Total second quarter production averaged 30,557 boe/d, a 6% year over
year increase.
- Funds flow from operations of $77 million for the quarter ended
June 30, 2008, a 58% increase over last year.
- Second quarter 2008 adjusted net earnings from operations of
$22 million, a 144% year over year increase.
RESULTS OF OPERATIONS
FUNDS FLOW FROM OPERATIONS
Funds flow from operations is a non-GAAP measure that represents net
earnings adjusted for non-cash items. We consider funds flow from operations
to be a key financial measure as it demonstrates our ability to generate funds
necessary to finance future growth through capital investment. Funds flow from
operations may not be comparable to similar measures presented by other
companies.
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
($000s, except June 30 June 30
per share
amounts) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Funds flow from
operations $ 76,651 $ 48,582 58% $145,973 $117,365 24%
Per share
- basic $ 0.59 $ 0.38 55% $ 1.13 $ 0.91 24%
- diluted $ 0.58 $ 0.36 61% $ 1.10 $ 0.88 25%
Net earnings $ (8,561) $ 45,307 -119% $ (6,942) $ 59,026 -112%
Per share
- basic $ (0.07) $ 0.35 -120% $ (0.05) $ 0.46 -111%
- diluted $ (0.07) $ 0.34 -121% $ (0.05) $ 0.44 -111%
-------------------------------------------------------------------------
The following schedule sets out the determination of funds flow from
operations and reconciles funds flow from operations to cash flow from
operating activities:
-------------------------------------------------------------------------
Three months ended June 30, 2008 2007
-------------------------------------------------------------------------
Operating activities
Net earnings $ (8,561) $ 45,307
Amortization and other 939 1,415
Depletion and depreciation 39,541 35,070
Accretion of asset retirement obligations 825 612
Unrealized foreign exchange (gain) loss (4,185) (40,275)
Future income taxes (1,564) 2,619
Unrealized risk management (gain) loss 46,987 87
Stock-based compensation 1,878 2,362
Asset retirement expenditures (590) (516)
Non-controlling interest 1,381 1,901
-------------------------------------------------------------------------
Funds flow from operations $ 76,651 $ 48,582
Change in non-cash working capital (9,934) (5,908)
-------------------------------------------------------------------------
Cash flow from operating activities $ 66,717 $ 42,674
-------------------------------------------------------------------------
NET EARNINGS AND ADJUSTED NET EARNINGS FROM OPERATIONS
Risk management losses significantly affected net earnings for the second quarter and for the six months ended June 30, 2008 and largely resulted in the Company reporting a loss for the quarter and the six month period. During the six month period we recognized a $60.6 million net risk management loss of which $60.4 million was recognized in the second quarter. The six month loss included unrealized losses of $63 million associated with outstanding commodity hedge contracts. Of the total risk management loss reported for the six months, $47.8 million was unrealized. Risk management activities are discussed in greater detail in the Risk Management section of the MD&A and also in Note 13 to the financial statements.
Adjusted net earnings from operations is a non-GAAP measure that adjusts net earnings by non-operating items, net of tax, that we believe reduce the comparability of our underlying financial performance between periods. The following reconciliation of adjusted net earnings from operations has been prepared to provide investors with information that is more comparable between periods. Adjusted net earnings from operations should not be considered an alternative or meaningful than net earnings detailed in accordance with GAAP.
Summary of adjusted net earnings from operations(1)
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
($000s, except per share June 30 June 30
amounts) 2008 2007(3) 2008 2007(3)
-------------------------------------------------------------------------
Net earnings, as
reported $ (8,561) $ 45,307 $ (6,942) $ 59,026
Non-operational items, after
tax
Unrealized foreign exchange
loss (gain) (3,568) (33,807) 11,701 (38,491)
Unrealized risk management
loss (gain) 33,125 59 33,668 11,819
Stock-based compensation(2) 1,323 1,603 2,909 3,142
Effect of statutory tax rate
changes - (4,025) - (4,025)
-------------------------------------------------------------------------
Adjusted net earnings from
operations $ 22,319 $ 9,137 $ 41,336 $ 31,471
Per share
- basic $ 0.17 $ 0.07 $ 0.32 $ 0.24
- diluted $ 0.17 $ 0.07 $ 0.31 $ 0.24
-------------------------------------------------------------------------
(1) Adjusted net earnings from operations was referred to as Operating
Earnings in prior filings.
(2) Excludes compensation costs related to the Restricted Share Unit
Plan.
(3) Prior periods have been revised to conform with current period
presentation.
REVENUE
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Average production
Natural gas
(mmcf/d) 150 130 15% 160 139 15%
Liquids (light
oil & ngls)
(bbls/d) 5,643 7,199 -22% 5,326 7,959 -33%
-------------------------------------------------------------------------
Total (boe/d) 30,557 28,918 6% 31,916 31,105 3%
Benchmark prices
AECO ($/GJ)
Monthly index $ 8.68 $ 7.07 23% $ 7.81 $ 7.03 11%
Daily index $ 9.68 $ 7.00 38% $ 8.59 $ 6.85 25%
WTI (U.S.$/bbl) $ 123.98 $ 58.16 113% $ 110.92 $ 61.60 80%
Edmonton Par
($/bbl) $ 126.02 $ 67.12 88% $ 111.74 $ 69.51 61%
Realized prices
Natural gas
($/mcf) $ 9.42 $ 6.92 36% $ 8.39 $ 7.09 18%
Liquids ($/bbl) 110.37 60.49 82% 103.13 57.74 79%
-------------------------------------------------------------------------
Total ($/boe) $ 67.18 $ 47.94 40% $ 60.12 $ 47.43 27%
Revenue ($000s)
Natural gas $126,780 $ 82,112 54% $242,160 $178,191 36%
Crude oil and
ngls 60,017 44,059 36% 107,070 88,857 20%
-------------------------------------------------------------------------
Total $186,797 $126,171 48% $349,230 $267,048 31%
-------------------------------------------------------------------------
Natural gas production increased 15% during the second quarter and first half of 2008 as compared to 2007. Year over year liquids production decreased primarily as a result of the sale of the Company's oil property at Worsley that closed at the end of the third quarter of 2007. Overall second quarter production increased by 6% when compared to the second quarter of 2007.
Second quarter production was impacted by high initial decline rates, typical of tight gas production, associated with new wells placed on-stream during the previous two quarters. Additionally, field activities decreased from the first quarter as a result of spring break-up and extended wet field conditions that delayed well completions and tie-ins. Finally, second quarter production realized the full impact of the previously reported high rate gas zone in a well at Bigoray that watered out during the first quarter. As a result and similar to prior years, second quarter production decreased 8% from that of the first quarter of 2008.
Approximately 9% of Compton's natural gas production is marketed through aggregator contracts during the quarter, which received a price that was, on average, $1.25/mcf less than prices received on non-aggregator volumes.
ROYALTIES
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
2008 2007 2008 2007
-------------------------------------------------------------------------
Royalties ($000s) $ 37,686 $ 23,307 $ 71,173 $ 51,953
Percentage of revenues 20.2% 18.5% 20.4% 19.5%
-------------------------------------------------------------------------
The Alberta royalty structure is based upon commodity prices and well
productivity, with higher prices and well productivity attracting higher
royalty rates. Year over year royalties paid by Compton are slightly higher on
a percentage of revenues basis due to the proportionate increase in natural
gas production which generally attracts a higher royalty rate.
OPERATING EXPENSES
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
2008 2007 2008 2007
-------------------------------------------------------------------------
Operating expenses ($000s) $ 28,448 $ 23,472 $ 57,290 $ 49,504
Operating expenses per boe
($/boe) $ 10.23 $ 8.92 $ 9.86 $ 8.79
-------------------------------------------------------------------------
Operating expenses for the second quarter and for the six months ended
June 30, 2008 were higher due to higher costs associated with accelerated
activity throughout the oil and gas industry. Second quarter costs are
relatively consistent with the first quarter of 2008, although 7% higher on a
boe basis due to lower production volumes.
TRANSPORTATION EXPENSES
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
2008 2007 2008 2007
-------------------------------------------------------------------------
Transportation expenses
($000s) $ 2,573 $ 4,252 $ 4,827 $ 6,734
Transportation expenses per
boe ($/boe) $ 0.93 $ 1.62 $ 0.83 $ 1.20
-------------------------------------------------------------------------
Transportation expenses for the three and six months ended June 30, 2008
were significantly lower than for the comparable periods in 2007 due to
reduced trucking charges associated with lower oil production.
GENERAL AND ADMINISTRATIVE EXPENSES
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
($000s, except where noted) 2008 2007 2008 2007
-------------------------------------------------------------------------
General and administrative
expenses $ 10,038 $ 11,431 $ 22,092 $ 20,806
Capitalized general and
administrative expenses (2,112) (1,404) (4,570) (3,606)
Operator recoveries (610) (804) (1,284) (1,568)
-------------------------------------------------------------------------
Total general and
administrative expenses $ 7,316 $ 9,223 $ 16,238 $ 15,632
General and administrative
expenses per boe ($/boe) $ 2.63 $ 3.50 $ 2.80 $ 2.78
-------------------------------------------------------------------------
General and administrative costs for the second quarter of 2008 decreased $1.9 million from the second quarter of 2007 and $1.6 million from the first quarter of 2008. With the decision, announced June 11, 2008, to seek a buyer for all the capital stock of the Company, we have discontinued accruing for certain year end expenses, including 2008 employee bonuses and also reversed those provided for in the first quarter. This has more than offset an overall increase in general and administrative expense resulting from higher personnel costs, higher rent associated with additional office space and insurance costs. Our annual employee bonus program is largely offset by an employee retention program that is accounted for in strategic review expenses.
STRATEGIC REVIEW EXPENSES
-------------------------------------------------------------------------
Three Months Six Months
Ended Ended
June 30 June 30
-------------------------------------------------------------------------
Strategic review costs ($000s) $ 3,666 $ 6,234
Strategic review costs per boe ($/boe) $ 1.32 $ 1.07
-------------------------------------------------------------------------
In the second quarter of 2008, we incurred approximately $3.7 million in expenses associated with the strategic review process. Compton has estimated direct costs associated with and resulting from the review process could total approximately $10.8 million, excluding any fees associated with the sale of the Company. Strategic review expenses include, among others, consulting and advisory fees, legal fees, and costs relating to employee retention.
INTEREST AND FINANCE CHARGES
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
2008 2007 2008 2007
-------------------------------------------------------------------------
Interest on bank debt, net $ 5,965 $ 6,039 $ 12,423 $ 11,248
Interest on senior notes 9,041 9,798 18,022 20,243
-------------------------------------------------------------------------
Interest charges $ 15,006 $ 15,837 $ 30,445 $ 31,491
Finance charges 590 141 1,002 31
-------------------------------------------------------------------------
Total interest and finance
charges $ 15,596 $ 15,978 $ 31,447 $ 31,522
Total interest and finance
charges per boe ($/boe) $ 5.61 $ 6.07 $ 5.41 $ 5.60
-------------------------------------------------------------------------
Interest costs in the three and six months ended June 30, 2008 were
consistent with comparative periods in 2007. When measured on a $/boe basis,
our interest and finance charges were 8% and 3% lower for the first quarter
and the first half of 2008 respectively due to increased year over year
production.
WEIGHTED AVERAGE DEBT
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
($000s, except where noted) 2008 2007 2008 2007
-------------------------------------------------------------------------
Bank Debt $447,747 $347,846 $433,159 $335,064
Effective Interest Rate 5.33% 6.38% 5.68% 6.41%
Senior unsecured notes
(US$450,000) $443,182 $473,212 $442,035 $492,153
Effective interest rate 8.16% 8.28% 8.15% 8.23%
-------------------------------------------------------------------------
DEPLETION AND DEPRECIATION
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
2008 2007 2008 2007
-------------------------------------------------------------------------
Depletion and depreciation
($000s) $ 39,541 $ 35,070 $ 81,348 $ 73,864
Depletion and depreciation per
boe ($/boe) $ 14.22 $ 13.33 $ 14.00 $ 13.12
-------------------------------------------------------------------------
Strong commodity prices have accelerated capital programs and competition throughout the oil and gas industry, raising the demand for and costs of goods and services. This increase in costs is reflected in increased finding, development, and on-stream costs which in turn have resulted in an increase in depletion and depreciation rates in the current quarter in comparison to the prior comparative period.
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. Note 12 in the financial statements details the calculation of the provision and the effective tax rate for the period. 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 ------------------------------------------------------------------------- Six Months Ended June 30 ($000s) 2008 % 2007 % ------------------------------------------------------------------------- Land and seismic $ 12,497 8 $ 20,750 13 Drilling and completions 103,089 63 88,989 58 Production facilities and equipment 48,759 29 44,067 29 ------------------------------------------------------------------------- Sub-total $164,345 100 $153,806 100 Property acquisitions (divestitures) net 11,192 (45,241) ------------------------------------------------------------------------- Sub-total $175,537 $108,565 MPP 128 3,935 ------------------------------------------------------------------------- Total capital expenditures $175,665 $112,500 -------------------------------------------------------------------------
Capital expenditures, before acquisitions and divestitures for the first half of 2008 increased $10.5 million as compared to the same time period in 2007 primarily due to an increase of $14.1 million in drilling and completion expenditures. During the first half of 2008, we drilled 106 net wells, whereas during the same period in 2007 we drilled 75.5 net wells. Land and seismic expenditures decreased in real dollars and also as a percentage of expenditures primarily as a result of reduced seismic programs.
RISK MANAGEMENT
Our financial results are impacted by external market risks associated with fluctuations in commodity prices, interest rates, and the Canadian/US 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 indicates 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) Losses
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
($000s) 2008 2007 2008 2007
-------------------------------------------------------------------------
Commodity contracts
Realized $ 9,704 $ (3,030) $ 9,093 $(11,783)
Unrealized 35,908 (3,033) 63,005 13,453
Foreign currency contracts
Realized 3,720 3,072 3,720 3,072
Unrealized 11,075 3,120 (15,249) 3,958
-------------------------------------------------------------------------
Total risk management $ 60,407 $ 129 $ 60,569 $ 8,700
-------------------------------------------------------------------------
Realized $ 13,424 $ 42 $ 12,813 $ (8,711)
Unrealized 46,983 87 47,756 17,411
-------------------------------------------------------------------------
Total risk management $ 60,407 $ 129 $ 60,569 $ 8,700
-------------------------------------------------------------------------
Outstanding Commodity Contracts
The following table outlines commodity hedge contracts which were in place
during the second quarter of 2008 and/or are currently in place.
-------------------------------------------------------------------------
Commodity Term Amount Average Price Index
-------------------------------------------------------------------------
Natural gas
Collars April 2008 - Oct. 2008 66,667 mcf/d $7.50 - $ 8.93/mcf AECO
Fixed April 2008 - Oct. 2008 19,048 mcf/d $ 7.86/mcf AECO
Collars Nov. 2008 - March 2009 28,571 mcf/d $8.40 - $10.00/mcf AECO
Fixed Nov. 2008 - March 2009 9,524 mcf/d $ 8.51/mcf AECO
Crude oil
Fixed March 2008 - Dec. 2008 1,000 bbls/d U.S.$93.00/bbl WTI
-------------------------------------------------------------------------
Outstanding Foreign Exchange Contracts
On June 30, 2008, the Company had the following foreign exchange contracts
in place:
-------------------------------------------------------------------------
Mark-
to-
Market
Contract Amount Rate Amount Term gain
USD CDN (loss)
-------------------------------------------------------------------------
Currency
Swap $450,000,000 96.9750 $436,387,500 Matures on
December 1, 2010 $21,915
Currency Equal payments on
Swap $ 78,435,000 99.5500 $ 78,082,043 May 30 and Nov. 30
until 2010 1,753
Cross
Currency BA
Interest
Rate plus Equal payments on
May 15
Swap $ 16,335,000 4.845% $21,002,412 and Nov. 15 until
2009 (4,471)
-------------------------------------------------------------------------
Total unrealized foreign exchange gain $19,197
-------------------------------------------------------------------------
LIQUIDITY AND CAPITAL RESOURCES
-------------------------------------------------------------------------
As at As at
June 30, Dec. 31,
($000s, except where noted) 2008 2007
-------------------------------------------------------------------------
Senior term notes $458,370 $444,645
Associated unrealized risk management (gain) (21,915) (14,146)
-------------------------------------------------------------------------
$436,455 $430,499
Bank debt 470,000 400,000
-------------------------------------------------------------------------
Long term debt $906,455 $830,499
Working capital deficiency (surplus) (3,376) 39,215
-------------------------------------------------------------------------
Total indebtedness $903,079 $869,714
Shareholders' equity $873,293 $869,956
Debt to adjusted EBITDA(1)(2) 3.8x 3.6x
Debt to total capitalization(1) 51% 50%
Debt to enterprise value(1)(3) 35% 41%
-------------------------------------------------------------------------
(1) Excludes risk management items net of related future income taxes.
(2) Based on trailing 12 month adjusted EBITDA as presented in Note 5 to
the financial statements.
(3) Enterprise value is the sum of market capitalization and total
indebtedness.
Our senior term notes are payable in US dollars and are translated into Canadian dollars at the period end at the then prevailing exchange rate. Any change from the prior period is recognized as an unrealized exchange gain or loss and decreases or increases the carrying value of the notes. At June 30, 2008 the carrying value of the notes increased $13.7 million from December 31, 2007 as a result of the unrealized loss on translation at June 30, 2008. In 2007, we entered into foreign exchange contracts relating to the senior notes that effectively fixes their liability in Canadian dollars through to December 1, 2010. The unrealized mark-to-market gain on these contracts is recognized as a reduction to the notes in determining total debt and capitalization as determined above.
Note 5 to the financial statements discusses our capital structure and certain non-GAAP measures utilized in managing our capital structure. We have targeted a total debt to capitalization ratio of between 40% and 50% and a total debt to adjusted EBITDA ratio of between 2.5 to 1 and 3.0 to 1. As at June 30, 2008 our debt to capitalization ratio of 51% and our debt to adjusted EBITDA of 3.8 to 1 exceed our targeted ranges. The proceeds from asset dispositions outlined below will assist us in achieving our stated targets.
Subsequent to June 30, 2008, the Company closed the transaction for the sale of certain assets in the Peace River Arch area. Gross proceeds of $38.5 million, before adjustments, were received from the disposition. Additionally, Purchase and Sale Agreements have been executed relating to the sale of assets at Zama, Thornbury, and Cecil. The Company anticipates that these sales will close in August, with expected gross proceeds before adjustments of $179.6 million.
Our corporate debt is structured to provide us with financial flexibility and coincide with the nature of our asset base. As of December 31, 2007 the reserve life index of our proved reserves was approximately 12 years. Of our existing debt, 49% consists of long term senior notes that are not due until 2013. This structure provides the ability to draw on our senior secured credit facilities to assist in funding our planned capital programs.
The borrowing base on which our syndicated credit facility is based is determined in relation to our year end reserves. The annual review of the facility has recently been completed, giving effect to the asset sales outlined above, resulting in no adjustment to the authorized amount of $500 million of which $470 million was drawn as of June 30, 2008. Proceeds from the asset sales will initially be used to reduce the amount outstanding subsequent to which approximately $230 million will remain available under the facilities.
We believe internally generated funds from operations and the proceeds from the asset dispositions will be more than sufficient to fund our planned capital program.
OUTLOOK AND GUIDANCE
As announced on June 11, 2008, the Company's Board of Directors has determined to seek a buyer for all of the capital stock of the Company. The Company, together with its advisors, Tristone Capital Inc. and UBS Securities Canada Inc., are currently in the process of preparing a Data Room that will be accessible to interested parties in early September.
The Company is pursuing an active third quarter drilling program, however in view of the sale process, updated guidance is not being provided.
Changes in Internal Control over Financial Reporting
There were no changes during the quarter ended June 30, 2008 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
QUARTERLY INFORMATION
The following table sets forth certain quarterly financial information of
the Company for the eight most recent quarters.
-------------------------------------------------------------------------
2008 2007
Q2 Q1 Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Total revenue
(millions) $ 187 $ 162 $ 126 $ 108 $ 126 $ 141
Funds flow
from
operations
(millions) $ 77 $ 69 $ 46 $ 33 $ 49 $ 69
Per share
- basic $ 0.59 $ 0.54 $ 0.35 $ 0.26 $ 0.38 $ 0.53
- diluted $ 0.58 $ 0.52 $ 0.35 $ 0.25 $ 0.36 $ 0.52
Net earnings
(millions) $ (9) $ 2 $ 50 $ 20 $ 45 $ 14
Per share
- basic $ (0.07) $ 0.01 $ 0.39 $ 0.15 $ 0.35 $ 0.11
- diluted $ (0.07) $ 0.01 $ 0.38 $ 0.15 $ 0.34 $ 0.10
Adjusted net
earnings from
operations
(millions)(1) $ 26 $ 19 $ 8 $ (1) $ 9 $ 22
Production
Natural gas
(mmcf/d) 150 170 167 135 130 148
Liquids
(bbls/d) 5,643 5,009 4,818 7,954 7,199 8,729
-------------------------------------------------------------------------
Total (boe/d) 30,557 33,274 32,646 30,440 28,918 33,316
Average price
Natural gas
(mmcf/d) $ 9.42 $ 7.48 $ 6.00 $ 5.23 $ 6.92 $ 7.24
Liquids
(bbls/d) 110.37 94.97 77.60 61.91 60.49 54.20
-------------------------------------------------------------------------
Total
($/boe) $ 67.18 $ 53.64 $ 41.94 $ 38.56 $ 47.94 $ 46.98
-------------------------------------------------------------------------
---------------------------------
2006
Q4 Q3
---------------------------------
Total revenue
(millions) $ 130 $ 127
Funds flow
from
operations
(millions) $ 55 $ 60
Per share
- basic $ 0.43 $ 0.47
- diluted $ 0.42 $ 0.45
Net earnings
(millions) $ (10) $ 31
Per share
- basic $ (0.08) $ 0.24
- diluted $ (0.08) $ 0.23
Adjusted net
earnings from
operations
(millions)(1) $ 19 $ 14
Production
Natural gas
(mmcf/d) 148 142
Liquids
(bbls/d) 8,600 9,249
---------------------------------
Total (boe/d) 33,245 32,843
Average price
Natural gas
(mmcf/d) $ 6.48 $ 5.38
Liquids
(bbls/d) 48.44 57.53
---------------------------------
Total
($/boe) $ 42.60 $ 42.03
---------------------------------
(1) Prior periods have been revised to conform with current period
presentation.
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.
Compton Petroleum Corporation
Consolidated Financial Statements
June 30, 2008
(Unaudited)
-------------------------------------------------------------------------
Compton Petroleum Corporation
Consolidated Balance Sheets
(thousands of dollars)
-------------------------------------------------------------------------
June 30, December 31,
2008 2007
------------ ------------
(unaudited)
Assets
Current
Cash $ 13,160 $ 8,665
Accounts receivable 103,027 83,144
Risk management gain (Note 13b) 531 1,835
Other current assets 24,415 19,772
Future income taxes 19,186 2,606
------------ ------------
160,319 116,022
Property and equipment 2,211,508 2,116,834
Goodwill 9,933 9,933
Other assets 325 291
Risk management gain (Note 13b) 23,137 14,320
------------ ------------
$2,405,222 $2,257,400
------------ ------------
------------ ------------
Liabilities
Current
Accounts payable $ 137,226 $ 150,796
Risk management loss (Note 13b) 65,686 8,832
Future income taxes 154 542
------------ ------------
203,066 160,170
Long term debt (Note 3) 916,951 832,188
Asset retirement obligations (Note 7) 38,692 36,696
Risk management loss (Note 13b) - 1,585
Future income taxes 311,202 293,494
Non-controlling interest (Note 8) 62,018 63,311
------------ ------------
1,531,929 1,387,444
------------ ------------
Shareholders' equity
Capital stock (Note 4) 245,577 235,871
Contributed surplus (Note 9a) 25,499 24,233
Retained earnings 602,217 609,852
------------ ------------
873,293 869,956
------------ ------------
$2,405,222 $2,257,400
------------ ------------
------------ ------------
See accompanying notes to the consolidated financial statements.
-------------------------------------------------------------------------
Compton Petroleum Corporation
Consolidated Statements of Earnings and Other Comprehensive Income
(unaudited) (thousands of dollars, except per share amounts)
-------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
------------------------- -------------------------
2008 2007 2008 2007
------------ ------------ ------------ ------------
Revenue
Oil and natural gas
revenues $ 186,797 $ 126,171 $ 349,230 $ 267,048
Royalties (37,686) (23,307) (71,173) (51,953)
------------ ------------ ------------ ------------
149,111 102,864 278,057 215,095
------------ ------------ ------------ ------------
Expenses
Operating 28,448 23,472 57,290 49,504
Transportation 2,573 4,252 4,827 6,734
General and
administrative 7,316 9,223 16,238 15,632
Stock-based
compensation 3,620 3,982 6,616 7,248
Strategic review
(Note 16) 3,666 - 6,234 -
Interest and
finance charges
(Note 10) 15,596 15,978 31,447 31,522
Foreign exchange
(gain) loss
(Note 14) (4,147) (39,691) 13,759 (45,213)
Risk management
(gain) loss
(Note 13c) 60,407 129 60,569 8,700
Depletion and
depreciation 39,541 35,070 81,348 73,864
Accretion of asset
retirement
obligations 825 612 1,637 1,263
------------ ------------ ------------ ------------
157,845 53,027 279,965 149,254
------------ ------------ ------------ ------------
Earnings (loss)
before taxes and
non-controlling
interest (8,734) 49,837 (1,908) 65,841
------------ ------------ ------------ ------------
Income taxes (Note 12)
Current 10 10 18 (3)
Future (1,564) 2,619 1,722 3,229
------------ ------------ ------------ ------------
(1,554) 2,629 1,740 3,226
------------ ------------ ------------ ------------
Earnings (loss) before
non-controlling
interest (7,180) 47,208 (3,648) 62,615
Non-controlling
interest 1,381 1,901 3,294 3,589
------------ ------------ ------------ ------------
Net earnings (loss) (8,561) 45,307 (6,942) 59,026
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
Other comprehensive
income - - - -
------------ ------------ ------------ ------------
Comprehensive income
(loss) $ (8,561) $ 45,307 $ (6,942) $ 59,026
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
Net earnings (loss)
per share (Note 11)
Basic $ (0.07) $ 0.35 $ (0.05) $ 0.46
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
Diluted $ (0.07) $ 0.34 $ (0.05) $ 0.44
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
-------------------------------------------------------------------------
Compton Petroleum Corporation
Consolidated Statements of Retained Earnings
(unaudited) (thousands of dollars)
-------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
------------------------- -------------------------
2008 2007 2008 2007
------------ ------------ ------------ ------------
Retained earnings,
beginning of period $ 610,874 $ 496,770 $ 609,852 $ 483,838
Net earnings (loss) (8,561) 45,307 (6,942) 59,026
Premium on redemption
of shares (Note 4) (96) (995) (693) (1,782)
------------ ------------ ------------ ------------
Retained earnings,
end of period $ 602,217 $ 541,082 $ 602,217 $ 541,082
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
See accompanying notes to the consolidated financial statements.
-------------------------------------------------------------------------
Compton Petroleum Corporation
Consolidated Statements of Cash Flow
(unaudited) (thousands of dollars)
-------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
------------------------- -------------------------
2008 2007 2008 2007
------------ ------------ ------------ ------------
Operating activities
Net earnings (loss) $ (8,561) $ 45,307 $ (6,942) $ 59,026
Amortization and
other 939 1,415 837 1,926
Depletion and
depreciation 39,541 35,070 81,348 73,864
Accretion of asset
retirement
obligations 825 612 1,637 1,263
Unrealized foreign
exchange (gain)
loss (4,185) (40,275) 13,725 (45,855)
Future income taxes (1,564) 2,619 1,722 3,229
Unrealized risk
management (gain)
loss 46,987 87 47,756 17,411
Stock-based
compensation 1,878 2,362 4,126 4,629
Asset retirement
expenditures (590) (516) (1,530) (1,717)
Non-controlling
interest 1,381 1,901 3,294 3,589
------------ ------------ ------------ ------------
76,651 48,582 145,973 117,365
Change in non-cash
working capital (9,934) (5,908) (9,608) (1,655)
------------ ------------ ------------ ------------
66,717 42,674 136,365 115,710
------------ ------------ ------------ ------------
Financing activities
Issuance of bank debt 34,933 55,615 70,171 40,615
Proceeds from share
issuances (net) 5,071 725 6,989 2,602
Distributions to
limited partner (2,294) (2,293) (4,586) (4,586)
Redemption of common
shares (113) (1,173) (837) (2,119)
------------ ------------ ------------ ------------
37,597 52,874 71,737 36,512
------------ ------------ ------------ ------------
Investing activities
Property and equipment
additions (62,875) (50,597) (163,925) (156,025)
Property acquisitions (675) (592) (11,673) (592)
Property dispositions - 572 480 45,833
Change in non-cash
working capital (44,218) (41,626) (28,489) (39,035)
------------ ------------ ------------ ------------
(107,768) (92,243) (203,607) (149,819)
------------ ------------ ------------ ------------
Change in cash (3,454) 3,305 4,495 2,403
Cash, beginning of
period 16,614 10,974 8,665 11,876
------------ ------------ ------------ ------------
Cash, end of period $ 13,160 $ 14,279 $ 13,160 $ 14,279
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
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)
June 30, 2008
-------------------------------------------------------------------------
1. Basis of presentation
Compton Petroleum Corporation (the "Company" or "Compton") explores for
and produces petroleum and natural gas reserves in the Western Canadian
Sedimentary Basin.
These 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
(the "Partnership" or "MPP") in accordance with Accounting Guideline 15
("AcG-15"), Consolidation of Variable Interest Entities, as outlined in
Note 8.
These consolidated interim financial statements 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, 2007. 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, 2007 except as disclosed in Note 2 below.
All amounts are presented in Canadian dollars unless otherwise stated.
2. Changes in accounting policies and procedures
On January 1, 2008, the Company adopted the Canadian Institute of
Chartered Accountants ("CICA") Handbook Section 3031, "Inventories",
Handbook Section 1400, "General Standards of Financial Statement
Presentation", Handbook Section 3862, "Financial Instruments -
Disclosures", Handbook Section 3863, "Financial Instruments -
Presentation", and Handbook Section 1535, "Capital Disclosures".
The adoption of these standards has had no significant impact on the
Company's consolidated financial statements. The effects of the
implementation of the new standards are discussed below.
a) Inventories
The new standard replaces the previous standard and requires the
consistent grouping of like assets and the application of the first-
in-first-out or weighted average cost formula methodology. Spare
parts inventory are tangible assets with a useful life that extends
beyond one year and are held for re-deployment rather than re-sale.
As such, they have been included in property and equipment and are
depreciated on a per unit of production basis.
b) General standards of financial statement presentation
The new standard requires assessing an entity's ability to continue
as a going concern and disclosing such if any uncertainty exists.
c) Financial instruments disclosure and presentation
The new standards require increased disclosure of financial
instruments with particular emphasis on the risks associated with
recognized and unrecognized financial instruments and how those risks
are managed by the Company as disclosed in Note 13.
d) Capital disclosures
The new standard requires disclosure about the Company's objectives,
policies and process for managing its capital structure as disclosed
in Note 5.
3. Long term debt
June 30, December 31,
2008 2007
------------ ------------
Syndicated bank debt
Prime rate $ 70,000 $ 50,000
Bankers' acceptance 400,000 350,000
Discount to maturity (1,403) (1,574)
------------ ------------
468,597 398,426
------------ ------------
Senior term notes
US $450 million senior term notes 458,370 444,645
Unamortized transaction costs (10,016) (10,883)
------------ ------------
448,354 433,762
------------ ------------
Total long term debt $ 916,951 $ 832,188
------------ ------------
------------ ------------
As at June 30, 2008, the Company had arranged authorized senior credit
facilities with a syndicate of banks in the amount of $500 million.
Subsequent to June 30, 2008, the banking syndicates annual review of the
Company's credit facilities was completed and renewed under the same
terms and conditions. Certain syndicate members representing $90 million
of the facility, have elected not to extend their participation beyond
the term date of the renewed facility, July 2, 2009.
4. Capital stock
Issued and outstanding
June 30, 2008 December 31, 2007
------------------------- -------------------------
Number Number
of shares Amount of shares Amount
------------ ------------ ------------ ------------
(000s) (000s)
Common shares
outstanding,
beginning of period 129,098 $ 235,871 128,503 $ 231,992
Shares issued for
services 50 490 - -
Shares issued under
stock option plan 1,125 9,360 993 4,603
Shares repurchased (78) (144) (398) (724)
------------ ------------ ------------ ------------
Common shares
outstanding,
end of period 130,195 $ 245,577 129,098 $ 235,871
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
The Company maintains a normal course issuer bid program on an annual
basis. Under the current program, 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 six months ended
June 30, 2008 the Company purchased for cancellation 78,300 common shares
at an average price of $10.69 per share (December 31, 2007 - 398,300
shares at an average price of $9.98 per share) pursuant to the normal
course issuer bid. The excess of the purchase price over book value has
been charged to retained earnings.
5. Capital structure
The Company's capital structure is comprised of shareholders equity plus
long-term debt. The Company's objectives when managing its capital
structure are to:
a) ensure the Company can meet its financial obligations,
b) retain an appropriate level of leverage relative to the risk of
Compton's underlying assets, and
c) finance internally generated growth and potential acquisitions.
Compton manages its capital structure based on changes in economic
conditions and the Company's planned capital requirements. Compton has
the ability to adjust its capital structure by making modifications to
its capital expenditure program, divesting of assets and by issuing new
debt or equity.
The Company monitors its capital structure and financing requirements
using non-GAAP measures consisting of total net debt to capitalization
and total net debt to adjusted Earnings Before Interest, Taxes,
Depreciation and Amortization ("adjusted EBITDA").
Compton targets a total net debt to capitalization ratio of between 40%
and 50% calculated as follows:
As at period ended June 30, December 31,
2008 2007
------------ ------------
Senior term notes $ 458,370 $ 444,645
Associated unrealized risk management (gain) (21,915) (14,146)
------------ ------------
436,455 430,499
Bank debt 470,000 400,000
------------ ------------
Long-term debt 906,455 830,499
Working capital (surplus) deficiency(x) (3,376) 39,215
------------ ------------
Total net debt 903,079 869,714
Total shareholder's equity 873,293 869,956
------------ ------------
Total capitalization $1,776,372 $1,739,670
------------ ------------
------------ ------------
Total net debt to capitalization ratio 51% 50%
------------ ------------
------------ ------------
(x) excludes risk management items, net of related future income taxes
Compton's senior term notes, denominated in US dollars, are translated
into Canadian dollars at period end at the then prevailing exchange rate.
Any change from the prior period is recognized as an unrealized foreign
exchange gain or loss and decreases or increases the carrying value of
the notes. At June 30, 2008 the carrying value increased by $13.7 million
from December 31, 2007 as a result of the unrealized loss on translation.
In 2007, the Company entered into foreign exchange contracts relating to
the senior notes that effectively fixes their liability in Canadian
dollars through to December 1, 2010. The unrealized risk management gain
on these contracts is recognized as a reduction to the notes in
determining total net debt and capitalization as calculated above.
The Company's total net debt to capitalization increased to 51% at
June 30, 2008 from 50% at December 31, 2007 as a result of increased
borrowings relating to first half activities.
Compton targets a total net debt to adjusted EBITDA of 2.5 to 3.0 times.
At June 30, 2008 total net debt to adjusted EBITDA was 3.8x (December 31,
2007 - 3.6x) calculated on a trailing 12 month basis as follows:
As at period ended June 30, December 31,
2008 2007
------------ ------------
Total net debt $ 903,079 $ 869,714
------------ ------------
------------ ------------
12 months ended June 30, December 31,
2008 2007
------------ ------------
Net earnings $ 63,298 $ 129,267
Add (deduct)
Interest and finance charges 63,418 63,493
Income taxes (27,921) (26,435)
Depletion, depreciation and amortization 158,895 151,411
Accretion of asset retirement obligations 3,092 2,718
Foreign exchange (gain) loss (19,745) (78,717)
------------ ------------
Adjusted EBITDA $ 241,037 $ 241,737
------------ ------------
------------ ------------
Net debt to adjusted EBITDA 3.8x 3.6x
------------ ------------
------------ ------------
The Company is in the process of divesting of certain non-core assets.
Proceeds from these divestments are expected to be such that, subsequent
to closing, the Company will be within the range of its stated capital
structure targets. The timing of these divestitures is discussed in
Note 17 to these consolidated financial statements.
Compton is subject to certain financial covenants relating to its credit
facility and senior notes and at June 30, 2008 is in compliance with all
such financial covenants.
6. Business combination
On December 21, 2007 the Company acquired all of the issued and
outstanding shares of WIN Energy Corporation. The transaction was
accounted for using the purchase method and during the period ended
March 31, 2008 the purchase price allocation was finalized. The result
was a decrease to petroleum and natural gas properties of $1.0 million
and an increase to the future income tax asset of $1.0 million over that
reported at December 31, 2007.
7. 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:
June 30, December 31,
2008 2007
------------ ------------
Asset retirement obligations, beginning
of period $ 36,696 $ 29,791
Liabilities incurred 2,268 8,719
Liabilities settled and disposed (210) (4,532)
Accretion expense 1,637 2,718
Revision of estimate (1,699) -
------------ ------------
Asset retirement obligations, end of period $ 38,692 $ 36,696
------------ ------------
------------ ------------
8. Non-controlling interest
Pursuant to AcG-15, these consolidated financial statements include the
assets, liabilities and operations of Mazeppa Processing Partnership
(MPP). Equity in MPP, attributable to its partners, is recorded on
consolidation as a non-controlling interest and is comprised of the
following:
June 30, December 31,
2008 2007
------------ ------------
Non-controlling interest, beginning of period $ 63,311 $ 66,350
Earnings attributable to non-controlling
interest 3,294 6,132
Distributions to limited partner (4,587) (9,171)
------------ ------------
Non-controlling interest, end of period $ 62,018 $ 63,311
------------ ------------
------------ ------------
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 pursuant to the guarantee at June 30, 2008
is $7.6 million. The Company has determined that its exposure to loss
under these arrangements is minimal, if any.
9. Stock-based compensation plans
a) Stock option plan
The following tables summarize the information relating to stock
options:
June 30, 2008 December 31, 2007
------------------------- -------------------------
Weighted Weighted
average average
Stock exercise Stock exercise
options price options price
------------ ------------ ------------ ------------
(000s) (000s)
Outstanding, beginning
of period 12,084 $ 8.49 11,611 $ 7.79
Granted 501 $ 9.75 2,074 $ 11.02
Exercised (1,125) $ 5.78 (993) $ 3.47
Forfeited (257) $ 12.70 (608) $ 11.97
------------ ------------ ------------ ------------
Outstanding, end
of period 11,203 $ 8.72 12,084 $ 8.49
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
Exercisable, end
of period 7,507 $ 7.27 7,240 $ 6.20
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
The range of exercise prices of stock options outstanding and
exercisable at June 30, 2008 was as follows:
Outstanding options Exercisable options
----------------------------------- -----------------------
Weighted
average
remaining Weighted Weighted
Range of Number of contractual average Number of average
exercise options life exercise options exercise
prices outstanding (years) price outstanding price
------------- ----------- ----------- ----------- ----------- -----------
(000s) (000s)
$1.45 - $3.99 2,448 2.0 $2.66 2,448 $2.66
$4.00 - $6.99 1,247 3.2 $4.44 1,247 $4.44
$7.00 - $9.99 1,792 2.3 $8.13 1,049 $7.62
$10.00 - $11.99 2,748 3.0 $11.20 1,107 $11.10
$12.00 - $13.99 1,619 2.2 $12.63 966 $12.56
$14.00 - $18.39 1,349 2.6 $14.69 690 $14.69
----------- ----------- ----------- ----------- -----------
11,203 2.6 $8.72 7,507 $7.27
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
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 Six months ended
June 30, June 30,
------------------------- -------------------------
2008 2007 2008 2007
------------ ------------ ------------ ------------
Weighted average fair
value of options
granted $4.56 $5.24 $3.95 $4.38
Risk-free interest rate 3.1% 4.3% 3.4% 4.0%
Expected life (years) 5.0 5.0 5.0 5.0
Expected volatility 38.5% 38.6% 38.4% 39.2%
The following table presents the reconciliation of contributed
surplus with respect to stock-based compensation:
June 30, December 31,
2008 2007
------------ ------------
Contributed surplus, beginning of period $ 24,233 $ 16,974
Stock-based compensation expense 4,126 8,416
Stock options exercised (2,860) (1,157)
------------ ------------
Contributed surplus, end of period $ 25,499 $ 24,233
------------ ------------
------------ ------------
b) Restricted share unit plan
On March 1, 2008, the Company implemented a Restricted Share Unit
Plan ("RSU" or "the plan") for employees, officers and directors. The
purpose of the Plan is to attract and retain personnel necessary to
the successful operation of the Company and promote greater alignment
of their interests to that of Compton's shareholders. Under the Plan
and at the direction of the Board of Directors, RSUs may be granted
to persons eligible under the Plan. Generally RSUs so granted vest
over three years commencing with the first anniversary date of grant
and entitle the holder to receive a cash payment equal to the fair
market value of one common share of Compton per vested RSU. On
March 10, 2008, 899,400 RSUs were granted under the Plan.
In accordance with CICA Handbook section 3870 the Company recognizes,
as compensation costs, the change in the intrinsic value of the RSUs
over the vesting period. During the six months ending June 30, 2008
the Company recognized, within stock-based compensation, $2.5 million
(March 31, 2008 - $0.8 million) of compensation costs related to
outstanding RSUs. The corresponding liability is included in accounts
payable as at June 30, 2008. All outstanding RSUs expire in 2011.
c) 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 June 30, 2008 and 2007, 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 $1.0 million, which is included in accounts payable
as at June 30, 2008 (December 31, 2007 - $1.0 million). All
outstanding SARs having a variable component expire at various times
through 2011.
10. Interest and finance charges
Amounts charged to interest expense during the period were:
Three months ended Six months ended
June 30, June 30,
------------------------- -------------------------
2008 2007 2008 2007
------------ ------------ ------------ ------------
Interest on bank
debt, net $ 5,965 $ 6,039 $ 12,423 $ 11,248
Interest on senior
term notes 9,041 9,798 18,022 20,243
Other finance charges 590 141 1,002 31
------------ ------------ ------------ ------------
$ 15,596 $ 15,978 $ 31,447 $ 31,522
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
Other finance charges include lease financing, bank service charges and
fees as well as other miscellaneous interest revenue and expense.
11. Per share amounts
The following table summarizes the common shares used in calculating net
earnings per common share:
Three months ended Six months ended
June 30, June 30,
------------------------- -------------------------
2008 2007 2008 2007
------------ ------------ ------------ ------------
(000s) (000s) (000s) (000s)
Weighted average common
shares outstanding
- basic 129,804 129,149 129,493 128,861
Effect of stock
options 1,820 4,003 3,499 4,015
------------ ------------ ------------ ------------
Weighted average
common shares
outstanding
- diluted 131,624 133,152 132,992 132,876
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
12. Income taxes
The following table reconciles income taxes calculated at the Canadian
statutory rates with actual income taxes:
Three months ended Six months ended
June 30, June 30,
------------------------- -------------------------
2008 2007 2008 2007
------------ ------------ ------------ ------------
Earnings before taxes
and non-controlling
interest $ (8,734) $ 49,837 $ (1,908) $ 65,841
------------ ------------ ------------ ------------
Canadian statutory
rates 29.5% 32.1% 29.5% 32.1%
Expected income taxes $ (2,577) $ 15,998 $ (563) $ 21,135
Effect on taxes
resulting from:
Non-deductible
stock-based
compensation 554 759 1,218 1,487
Effect of tax rate
changes and
temporary
differences recorded
at future rates 2,353 (5,798) 741 (10,199)
Non-taxable capital
(gains) losses (1,756) (6,424) 630 (7,320)
Other (128) (1,906) (286) (1,877)
------------ ------------ ------------ ------------
Provision for income
taxes $ (1,554) $ 2,629 $ 1,740 $ 3,226
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
Current $ 10 $ 10 $ 18 $ (3)
Future (1,564) 2,619 1,722 3,229
------------ ------------ ------------ ------------
$ (1,554) $ 2,629 $ 1,740 $ 3,226
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
Effective tax rate 17.8% 5.3% (91.2%) 4.9%
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
13. Financial instruments and risk management
At June 30, 2008, the Company's financial assets and liabilities consist
of cash, accounts receivable, other current assets, accounts payable,
bank debt, senior term notes and risk management assets and liabilities
relating to the use of derivative financial instruments.
The following summarizes a) fair values of financial assets and
liabilities, b) risk management assets and liabilities, c) risk
management gains and losses and d) risks associated with financial assets
and liabilities.
a) Fair value of financial assets and liabilities
The fair value of financial assets and liabilities were as follows:
June 30, 2008 December 31, 2007
------------------------- -------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
------------ ------------ ------------ ------------
Financial assets
Held-for-trading
Cash $ 13,160 $ 13,160 $ 8,665 $ 8,665
Other current
assets 24,415 24,415 19,772 19,772
Risk management
assets(x) 23,668 23,668 16,155 16,155
Loans and receivables
Accounts receivable 103,027 103,027 83,144 83,144
Financial liabilities
Held-for-trading
Risk management
liabilities(x) $ 65,686 $ 65,686 $ 10,417 $ 10,417
Other financial
liabilities
Accounts payable 137,226 137,226 150,796 150,796
Bank debt 468,597 468,597 398,426 398,426
Senior term notes 448,354 448,057 433,762 415,743
(x) Includes current and non-current
The carrying value of cash, accounts receivable, other current
assets, accounts payable, and bank debt approximate fair value due to
the short term nature of these instruments and variable rates of
interest. The senior term notes trade in the US and the estimated
fair value was determined using quoted market prices. Risk management
assets and liabilities are recorded at their estimated fair value
based on the mark to market method of accounting, using quoted market
prices, third-party indications and forecasts.
b) Risk management assets and liabilities
i) Net risk management positions
Risk management assets and liabilities relate to unrealized gains and
losses associated with commodity price risk management and foreign
currency risk management and are classified on the balance sheet as
follows:
Total Total
Commodity Foreign June 30, December 31,
Contracts Currency 2008 2007
------------ ------------ ------------ ------------
Unrealized gain
Current asset $ - $ 531 $ 531 $ 1,835
Non-current asset - 23,137 23,137 14,320
Unrealized loss
Current liability (61,215) (4,471) (65,686) (8,832)
Non-current liability - - - (1,585)
------------ ------------ ------------ ------------
Total unrealized gain
(loss) $ (61,215) $ 19,197 $ (42,018) $ 5,738
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
ii) Net fair value of commodity positions
On June 30, 2008, the Company had the following commodity contracts
in place:
Daily
Notional Average Mark-to-
Commodity Term Volume Price Market
---------------- ----------- ------------ ------------------ ------------
gain (loss)
Natural Gas
Summer collar Apr./08 -
Oct./08 66,667 mcf $7.50 - $8.93/mcf $ (24,097)
Summer fixed Apr./08 -
Oct./08 19,048 mcf $7.86/mcf (9,296)
Winter collar Nov./08 -
Mar./09 28,571 mcf $8.40 - $10.00/mcf (13,211)
Winter fixed Nov./08 -
Mar./09 9,524 mcf $8.51/mcf (6,164)
Oil fixed price Mar./08 -
Dec./08 1,000 bbl US $93.00/bbl (8,909)
Electricity Jan./07 -
Dec./08 2.5 MW $55.00/MWh 462
------------
Total unrealized commodity loss $ (61,215)
------------
------------
iii) Net fair value of foreign currency positions
On June 30, 2008, the Company had the following foreign exchange
contracts in place:
Mark-
Contract Amount Rate Amount Term to-
USD CDN Market
-------------------------------------------------------------------------
gain
(loss)
Currency
Swap $450,000,000 96.9750 $436,387,500 Matures on
December 1, 2010 $ 21,915
Currency
Swap $ 78,435,000 99.5500 $ 78,082,043 Equal payments on
May 30 and Nov. 30
until 2010 1,753
Cross
Currency
Interest
Rate
Swap $ 16,335,000 BA plus $ 21,002,412 Equal payments on
4.845% May 15 and Nov. 15
until 2009 (4,471)
---------
Total unrealized foreign exchange gain $ 19,197
---------
---------
c) Risk management gains and losses
Risk management gains and losses recognized in the consolidated
statements of earnings and other comprehensive income during the
periods relating to commodity prices and foreign currency
transactions are summarized below:
Six months ended Commodity Foreign 2008 2007
June 30, 2008 Contracts Currency Total Total
----------------- --------- --------- --------- ---------
Unrealized change in fair
value $ 63,005 $(15,249) $ 47,756 $ 17,411
Realized cash settlements 9,093 3,720 12,813 (8,711)
--------- --------- --------- ---------
Total (gain) loss $ 72,098 $(11,529) $ 60,569 $ 8,700
--------- --------- --------- ---------
--------- --------- --------- ---------
Three months ended Commodity Foreign 2008 2007
June 30, 2008 Contracts Currency Total Total
----------------- --------- --------- --------- ---------
Unrealized change in fair
value $ 35,908 $ 11,075 $ 46,983 $ 87
Realized cash settlements 9,704 3,720 13,424 42
--------- --------- --------- ---------
Total (gain) loss $ 45,612 $ 14,795 $ 60,407 $ 129
--------- --------- --------- ---------
--------- --------- --------- ---------
The gains and losses realized during the year on the electricity
contract are included in operating expenses.
d) Risk associated with financial assets and liabilities
The Company is exposed to financial risks arising from its financial
assets and liabilities which fluctuate in value due to movements in
market prices and is comprised of the following:
i) Market risk
Market risk is the risk that the fair value or future cash flows from
financial assets or liabilities will fluctuate due to movements in
market prices and is comprised of the following:
- Commodity price risk
The Company is exposed to commodity price movements as part of its
normal oil and gas operations. Under guidelines established and
approved by the Board of Directors, Compton enters into economic
hedge transactions relating to crude oil and natural gas prices to
mitigate volatility in commodity prices and the resulting impact on
cash flow. The contracts entered into are forward transactions
providing the Company with a range of prices on the commodities sold.
Prices are marked to industry benchmarks specifically to AECO monthly
prices for gas contracts, WTI NYMEX prices for oil contracts and
power pool spot prices for electricity contracts. Prices are valued
in Canadian dollars unless otherwise disclosed. The Company does not
use derivative contracts for speculative purposes.
At June 30, 2008, with respect to commodity contracts in place on
that date, an increase of $0.25/mcf in the price of natural gas,
holding all other variables constant, would have reduced the fair
value of the derivative financial instrument and negatively impacted
before tax earnings by approximately $4.3 million. A similar decline
in commodity prices would have had the opposite impact.
- Foreign exchange rate risk
Compton is exposed to fluctuations in the exchange rate between the
Canadian dollar and the US dollar. Crude oil and to a certain extent
natural gas prices are based upon reference prices denominated in US
dollars, while the majority of the Company's expenses are denominated
in Canadian dollars. To mitigate the exposure to the fluctuating
Canada/US exchange rate the Company maintains a mix of US and
Canadian dollar denominated debt. In addition Compton enters into
agreements to fix the exchange rate of Canadian dollars to US dollars
in order to manage the risk.
With Board of Director approval, during 2007, the Company entered
into a series of foreign exchange contracts relating to the
US$450 million senior notes due December 1, 2013, effectively fixing
the liability in Canadian dollars through to December 1, 2010, being
the second call date of the senior notes. Additionally, the Company
entered into a series of foreign exchange contracts relating to the
semi-annual interest settlement obligations until November 30, 2010.
At June 30, 2008, a $0.01 increase in the value of the Canadian
dollar, when measured against the US dollar, would have reduced the
fair value of the foreign exchange contracts and negatively impacted
before tax earnings by approximately $4.8 million. A similar decrease
of $0.01 would have had the opposite impact.
- Interest rate risk
The Company is exposed to interest rate risk principally associated
with borrowings. Floating rates, associated with bank debt, expose
the Company to short-term movements in interest rates. Fixed rates,
associated with the senior term notes, introduce risk at the time of
maturity if replacement bonds are issued.
The Company partially mitigates its exposure to interest rate changes
by maintaining a mix of both fixed and floating rate debt. Entering
into interest rate swap transactions, when deemed appropriate, is
another means of managing the fixed/floating rate debt portfolio mix.
At June 30, 2008, a 100 basis point increase in floating interest
rates, would negatively impact the cross currency interest rate swap
before tax earnings by approximately 2.5 million. A similar decrease
in floating rates would have the opposite impact.
ii) Credit risk
The Company is exposed to credit risk, which is the risk that a
counterparty will fail to perform an obligation or settle a
liability, resulting in a financial loss to the Company.
A significant portion of Compton's accounts receivable and other
current asset balances are with entities in the oil and gas industry
and subject to normal industry credit risks. The allowance for
doubtful accounts is less than 1% of total balances and relates to
receivables acquired through corporate acquisitions and disputes with
partners. Substantially all of the receivable balances at June 30,
2008 were current.
In the money derivative financial instrument contracts are with
investment grade Canadian and US financial institutions that are also
members of the Company's banking syndicate. At June 30, 2008, Compton
had two financial institutions whose net settlement position
individually accounted for more than 10% of the fair value of the
outstanding in-the-money net financial instrument contracts.
The Company regularly assesses the financial strength of its
marketing customers and limits the total exposure to individual
counterparties based on management determined criteria. As well, a
number of contracts contain provisions that allow Compton to demand
the posting of collateral in the event of a downgrade to a non-
investment grade credit rating.
The maximum credit risk exposure associated with the Company's
financial assets is the carrying amount.
iii) Liquidity risk
Compton is exposed to liquidity risk which is the risk that the
Company will be unable to generate or obtain sufficient cash to meet
its commitments as they come due. Mitigation of this risk is achieved
through the active management of cash and debt. In managing liquidity
risk, in addition to cash flow generated from operating activities,
the Company has access to sources of funding at competitive rates
through public debt markets, capital markets, property dispositions
and banks as disclosed in Note 5. Compton believes it has sufficient
funding through the use of these facilities to meet any foreseeable
cash requirements.
The timing of cash outflows relating to financial liabilities are
outlined below:
1 year 2-3 years 4-5 years +5 years Total
----------- ----------- ----------- ----------- -----------
Accounts
payable $ 137,226 $ - $ - $ - $ 137,226
Risk
management
liabilities 65,686 - - - 65,686
Bank debt - 470,000 - - 470,000
Senior term
notes - - - 458,370 458,370
----------- ----------- ----------- ----------- -----------
$ 202,912 $ 470,000 $ - $ 458,370 $1,131,282
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
14. Foreign exchange (gain) loss
Amounts charged to foreign exchange (gain) loss during the period ended
are as follows:
Three months ended Six months ended
June 30, June 30,
------------------------ ------------------------
2008 2007 2008 2007
----------- ----------- ----------- -----------
Foreign exchange on
translation of US$
debt $ (4,185) $ (40,275) $ 13,725 $ (45,855)
Other foreign exchange 38 584 34 642
----------- ----------- ----------- -----------
Total (gain) loss $ (4,147) $ (39,691) $ 13,759 $ (45,213)
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
15. Supplemental cash flow information
Amounts actually paid during the period relating to interest expense and
capital taxes are as follows:
Three months ended Six months ended
June 30, June 30,
------------------------ ------------------------
2008 2007 2008 2007
----------- ----------- ----------- -----------
Interest paid $ 24,598 $ 25,336 $ 31,230 $ 29,517
Taxes paid - - - -
----------- ----------- ----------- -----------
$ 24,598 $ 25,336 $ 31,230 $ 29,517
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
16. Strategic review
In response to certain concerns raised by Centennial Energy Partners LLC,
a major shareholder of Compton, the Board of Directors of the Company
announced, in a news release dated February 28, 2008, that it would
undertake a formal review of the Company's business plans and
alternatives for enhancing shareholder value. The review was conducted
under the direction of a Special Committee of the Board comprised of
Compton's independent directors.
Subsequent to the completion of the review process, as announced on
June 11, 2008, the Company's Board of Directors has determined to seek a
buyer for all of the capital stock of the Company.
The Company has estimated direct costs associated with, and resulting
from the review process will total approximately $10.8 million. These
costs include among others, consulting and advisory fees, legal fees, and
costs relating to employee retention but do not include fees payable
associated with a sale of the Company. Costs are recognized as incurred
and, as at June 30, 2008, the Company has recorded $6.2 million of
strategic review related expenses.
17. Subsequent events
Subsequent to June 30, 2008, the Company closed the transaction for the
sale of certain assets in the Peace River Arch. Gross proceeds before
adjustments were received in the amount of $38.5 million from the
disposition. Additionally, Purchase and Sale Agreements have been
executed relating to the sale of assets at Zama, Thornbury and Cecil. The
Company anticipates that these sales will close in August, with expected
gross proceeds before adjustments of $179.6 million.
18. Reclassification
Certain amounts disclosed for prior periods have been reclassified to
conform with current period presentation.
%SEDAR: 00003803E %CIK: 0001043572