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CALGARY, Nov. 10 /CNW/ - Compton Petroleum Corporation ("Compton" or the "Company") announces its financial and operating results for the quarter ended September 30, 2008.
CONTINUING OPERATIONS
On October 30, 2008 Compton announced the corporate sales process had been terminated. Prevailing public market conditions and the ongoing liquidity and credit crisis resulted in offers that were neither acceptable nor reflective of the true value of Compton or its asset base. On October 30, the Company also announced its intent to continue operating as an independent exploration and production entity.
Compton is well positioned to continue and succeed even during difficult times.
- With the sale of non-core properties during the third quarter, we are now essentially a pure natural gas story focused entirely on three concentrated low risk natural gas resource plays. - 85% of our production is natural gas and, although continued commodity price volatility is expected, we believe North American demand for natural gas will result in gas prices not being subject to the same downward pressure as crude oil prices, during a recessionary period. - Our core properties have all progressed through to a development stage and the associated, large, secure land position provides a very significant inventory of low risk development drilling opportunities. - Our high working interests and operatorship of virtually all our properties permit us to manage the pace of their exploitation and development consistent with our capital expenditure priorities. - We have a solid reserve and production base to build upon. Proved plus probable reserves at August 1, 2008 were approximately 1.6 Tcfe and current production is approximately 164 MMcfe per day (27,300 boe per day). - Our capital structure is secure. Our debt is term structured with 66% not due until December 2013. Our extendible, revolving bank credit facility was renewed on July 2, 2008 with an authorized loan amount of $500 million. At September 30, we had $260 million available under the facility to assist in managing our operations and capital programs. We are fully compliant with all our debt covenants.
Recently, in light of the current market turmoil, credit restrictions, and termination of the sale process, Compton has been the subject of speculation from various sources as to its ongoing viability. The opposite of this speculation is in fact the case. Liquidity is not an issue at Compton. Although our overall debt level may differ from others, it has been structured consistent with our long-life asset base. Our current corporate position, as outlined above, is such that the Compton is well able to manage its financial affairs through these turbulent times to the benefit of all shareholders.
Operationally, our drilling results have been excellent and have further verified the applicability of horizontal drilling and multi-stage fracture completions to our Deep Basin plays. All our plays are economically sound at current commodity prices and we will build on our recent successes in planning for the future.
We are currently developing and expect to finalize our plans for 2009 by mid-December at which time we will provide guidance for 2009. An extensive inventory of lower risk drill locations has been identified targeting both the Ellerslie and Rock Creek formations at Niton and the Basal Quartz and Belly River zones in southern Alberta. We expect our 2009 operational activities will focus on identified low risk, higher impact liquids rich natural gas opportunities. In the interim, our fourth quarter activities are focused on completion and tie-in activities to bring reserves on production. We expect our 2009 plans will be financed by available funds provided by operations. The major variable to determining such funds will be natural gas prices which are approximately 12% higher than at this time last year. We have hedged 25% of our gas production through to March 31, 2009 and expect to expand upon these positions to provide greater certainty to our capital expenditure programs.
Compton has a Normal Course Issuer Bid in place that permits the Company to repurchase its issued and outstanding shares; 5.6 million shares currently remain authorized for such repurchases. In view of our current share price versus our underlying asset value and funds flow multiple, we are considering re-directing a portion of our capital expenditure budget to additional share repurchases, thus improving per share net asset value and funds flow.
With the termination of the sales process, Compton and its staff are looking forward to focusing their full efforts to ongoing operations and value creation for all shareholders.
THIRD QUARTER HIGHLIGHTS
- Four 5 MMcf/d plus wells at Niton, drilling success in all areas -
100% success rate.
- Average production of 26,006 boe/d.
- Divestment of non-core assets for net proceeds of $204 million.
- Debt reduction of $212 million from June 30, 2008.
- Q3 funds flow from operations of $87 million, $233 million for the
nine months.
- Net earnings of $60 million.
FINANCIAL SUMMARY
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Three Months Ended Nine Months Ended
($000s, except per Sept. 30 Sept. 30
share amounts) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Gross revenue $ 153,322 $ 107,980 42% $ 502,551 $ 375,028 34%
Funds flow from
operations(1) $ 86,675 $ 33,133 162% $ 232,648 $ 150,498 55%
Per share
- basic(1) $ 0.67 $ 0.26 158% $ 1.79 $ 1.17 53%
- diluted(1) $ 0.66 $ 0.25 164% $ 1.75 $ 1.13 55%
Adjusted
operational
earnings(1) $ 40,019 $ (813) $ 81,354 $ 30,658
Net earnings $ 59,882 $ 19,782 203% $ 52,940 $ 78,808 -33%
Per share
- basic $ 0.46 $ 0.15 207% $ 0.41 $ 0.61 -33%
- diluted $ 0.46 $ 0.15 207% $ 0.40 $ 0.59 -32%
Capital
expenditures
before
acquisitions
and divestments $ 105,985 $ 115,635 -8% $ 270,330 $ 269,441 0%
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OPERATING SUMMARY
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Three Months Ended Nine Months Ended
Sept. 30 Sept. 30
2008 2007 Change 2008 2007 Change
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Average daily
production
Natural gas
(mmcf/d) 130 135 -4% 150 138 9%
Liquids (bbls/d) 4,323 7,954 -46% 4,989 7,958 -37%
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Total (boe/d) 26,006 30,440 -15% 29,931 30,881 -3%
Realized prices
Natural gas
($/mcf) $ 8.75 $ 5.23 67% $ 8.50 $ 6.47 31%
Liquids
($/bbl)(2) $ 124.05 $ 61.91 100% $ 109.22 $ 59.15 85%
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Total ($/boe) $ 64.08 $ 38.56 66% $ 61.28 $ 44.48 38%
Field netback(1)
($/boe) $ 34.32 $ 20.51 67% $ 35.24 $ 25.38 39%
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(1) See advisory statements relating to non-GAAP measures included with
Management's Discussion and Analysis.
(2) Includes sulphur.
OPERATIONS REVIEW
With much improved field conditions, Compton drilled a total of 101 gross wells (79 net) during the third quarter as compared to the 34 gross wells (33 net) drilled during all of the second quarter of 2008. We have continued the focus of applying horizontal drilling combined with multi-stage frac completions to our Deep Basin and Foothills natural gas plays with good success.
Compton currently has 31 horizontal gas wells that have been multi-staged fractured: 24 at Niton, five at Hooker, and one each at Cowley and Caroline. The majority of these wells were drilled and placed on production in 2008. The horizontal multi-stage fracture technology has proven applicable to the development of Compton's extensive land base in the Deep Basin of Alberta.
DRILLING SUMMARY
Of the 101 (79 net) wells drilled during the third quarter of 2008, 100 or 99% were classified as development wells. The following table summarizes our drilling results in the first nine months of the year.
------------------------------------------------------------------------- Nine Months Ended September 30 Gas Oil D&A Total Net Success ------------------------------------------------------------------------- Southern Alberta 151 0 2 153 144 99% Central Alberta 61 5 3 69 30 96% ------------------------------------------------------------------------- Standing, cased wells 12 7 ------------------------------------------------------------------------- Total 212 5 5 234 181 93% -------------------------------------------------------------------------
EXPLOITATION AND DEVELOPMENT
Compton has four 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, the shallow Plains Belly River play in southern Alberta, plus an emerging over pressured foothills gas play in southern Alberta. Three of these plays are now relatively proven low risk development plays.
Niton
In late September, we drilled a 100% owned Rock Creek horizontal well at 12-26-52-17W5 at Niton. The well flow tested, on post fracture cleanup, on October 8, 2008 at 14.9 MMcf/d at 1500 psi flowing tubing pressure. The well is currently producing 10.5 MMcf/d at rates restricted by compressor size.
In late October, we completed a second 100% Rock Creek horizontal well at 16-30-52-16W5M that also tested high initial gas rates. On October 30, 2008, the well was flowing 8.2 MMcf/d at 200 psi flowing tubing pressure on the first day of multi-stage fracture cleanup.
Two additional Rock Creek horizontal wells drilled in the Niton area during the quarter also tested in excess of 5 MMcf/d. Compton has a 50% working interest in one of these wells and a 70% working interest in the other.
In addition to the above wells, Compton has been very active elsewhere in the Niton area of central Alberta. A total of eight wells were drilled during the third quarter, six of which were horizontal wells. We also expanded our Edson 5-26-52-17W5M compressor station capacity from 10 to 20 MMcf/d to accommodate production from our expanding Rock Creek horizontal gas play. Compton currently has seven gas wells producing to this compressor station, with an additional three wells scheduled to be on production in early November. Six additional horizontal Rock Creek drill locations are currently in the licensing stage in township 52-17W5. The compressor station is designed to be quickly expanded to a capacity of 30 MMcf/d should conditions warrant.
Also at Niton, we drilled our first and second horizontal wells targeting the Ellerslie zone. These were the first horizontal wells in the area targeting the Ellerslie using multi-stage fracturing completions. The first Ellerslie well, 12-19-54-13W5M, has averaged 2.6 MMcf/d for the first two weeks of production. The second well, 1-21-53-14W5M, tested inline at 2.1 MMcf/d on cleanup of frac fluids. We have identified and are working to secure as many as 20 follow-up horizontal Ellerslie locations on our Niton acreage. The August 1, 2008 Reserve Update does not recognize any value for this exciting new, relatively shallow 2,000 metre play.
Hooker
At Hooker, we placed our third and fourth horizontal Basal Quartz wells on continuous production during the quarter. Both wells are producing between 1 to 1.5 MMcf/d in line to the Mazeppa gas plant. The rates are steadily increasing as the fracture fluids are removed from the well. The two new wells are located at High River 1-18-17-29W4M and at 12-34-18-29W4M. A fifth Hooker BQ horizontal drill well at High River 8-7-17-28W4M is waiting on completion. All the horizontal wells were drilled on the tighter periphery of the Basal Quartz channel sand system.
SHALLOW GAS - Plains Belly River and Edmonton Group
In southern Alberta, we have been actively pursuing our shallow Plains Belly River development play. In total 70 gross (65 net) Belly River wells were drilled during the third quarter of 2008 with excellent results.
In the Centron area, we began production from four new Belly River wells. In aggregate, these wells are producing approximately 1.3 MMcf/d.
In the third quarter of 2008, Compton drilled five Belly River gas wells in township 21-28W4M, an area of land that is relatively new to oil and gas development, between the Okotoks field and the Gladys field. These wells tested at average expected rates and are scheduled to be tied-in on November 15, 2008.
As at September 30, 2008, we had a total of 127 (119 net) Belly River wells scheduled to be tied-in by year end 2008.
Vulcan
At Vulcan, we continue to develop the Lower Mannville I oil pool successfully with our 50% working interest partner. Upon expansion of the solution gas handling capability, we plan to drill additional oil wells as a follow up to the recent horizontal oil well at 1-29-15-25W4M, which has been facility restricted.
Foothills
Compton's first horizontal well in the Foothills, 14-5-7-1W5 at Cowley, has averaged 2.3 MMcf/d since being placed on production in late September. The well is currently producing 1.5 MMcf/d and appears to be following the typical production profile for a thrusted Foothills Belly River well. We are very encouraged by the results of this well, and are following up with a second well at 1-19-7-1W5, which is currently drilling. Well licenses and surface leases have been obtained for an additional two Cowley locations and license applications for a further three locations will be submitted before year end.
CURRENT PRODUCTION VOLUMES
We are currently producing approximately 27,300 boe/d after sales of 4,100 boe/d during the quarter. Current production consists of 144 MMcf/d of natural gas and 3,300 bbls/d of crude oil and natural gas liquids, based on field estimates and including three of the four high rate Rock Creek wells discussed above. The Rock Creek horizontal wells are expected to follow the typical production profile of tight gas wells in the area with high decline rates during the initial year of production. We currently expect December production to average in the range of 27,000 boe/d and 28,000 boe/d and production for the fourth quarter to average in the range of 26,500 boe/d to 27,000 boe/d.
MANAGEMENT'S DISCUSSION AND ANALYSIS
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 November 7, 2008 and should be read in conjunction with the interim unaudited consolidated financial statements for the nine months ended September 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, funds flow per share, adjusted operational earnings, adjusted EBITDA, field netback, 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 operational earnings represents net earnings excluding certain items that are largely non-operational in nature and should not be considered an alternative to, or more meaningful than, net earnings as determined in accordance with Canadian GAAP. Adjusted operational earnings is used by the Company to facilitate comparability of earnings between periods.
Adjusted EBITDA is a non-GAAP measure defined as net earnings, net of interest and finance charges, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, and any foreign exchange gains or losses.
Field netback equals the total petroleum and natural gas sales, including realized gains and losses on commodity hedge contracts, less royalties and operating and transportation expenses, calculated on a $/boe basis. Field netback is a non-GAAP measure that management uses to analyze operating performance. Field netback does not have a standardized meaning as prescribed by Canadian GAAP and, therefore, it may not be directly comparable to similar measures presented by other issuers.
Enterprise value is the sum of market capitalization and total indebtedness.
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.
SUMMARY
- Four 5 mmcf/d plus wells at Niton, drilling success in all areas -
100% success rate.
- Average production of 26,006 boe/d.
- Divestment of non-core assets for net proceeds of $204 million.
- Debt reduction of $212 million from June 30, 2008.
- Funds flow from operations of $87 million, $233 million for the nine
months.
- Net earnings of $60 million.
RESULTS OF OPERATIONS
Funds flow from operations, Adjusted operational earnings, and Net
earnings
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
($000s, except per Sept. 30 Sept. 30
share amounts) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Funds flow from
operations(1) $ 86,675 $ 33,133 162% $ 232,648 $ 150,498 55%
Per share
- basic $ 0.67 $ 0.26 158% $ 1.79 $ 1.17 53%
- diluted $ 0.66 $ 0.25 164% $ 1.75 $ 1.13 55%
Adjusted
operational
earnings(2) $ 40,521 $ (813) $ 81,856 $ 30,658
Net earnings $ 59,882 $ 19,782 203% $ 52,940 $ 78,808 -33%
Per share
- basic $ 0.46 $ 0.15 207% $ 0.41 $ 0.61 -33%
- diluted $ 0.46 $ 0.15 207% $ 0.40 $ 0.59 -32%
Field netback(3) $ 34.32 $ 20.51 67% $ 35.24 $ 25.38 39%
-------------------------------------------------------------------------
(1) Funds flow from operations represents net income before depletion and
depreciation, future income taxes, and other non-cash expenses.
(2) Adjusted operational earnings is a non-GAAP measure that adjusts net
earnings by non-operating items that reduce the comparability of our
underlying financial performance between periods. These non-operating
items, that are primarily of a non-cash nature, have been excluded in
determining adjusted operational earnings. The reconciliation given
in this MD&A has been prepared to provide investors with information
that is more comparable between periods.
(3) Field netback equals the total petroleum and natural gas sales,
including realized gains and losses on commodity hedge contracts,
less royalties and operating and transportation expenses, calculated
on a $/boe basis. Field netback is a non-GAAP measure that management
uses to analyze operating performance. Field netback does not have a
standardized meaning as prescribed by Canadian GAAP and, therefore,
it may not be directly comparable to similar measures presented by
other issuers.
The following schedule sets out the determination of funds flow from
operations and reconciles funds flow from operations to cash flow from
operating activities:
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Three Months Ended Nine Months Ended
Sept. 30 Sept. 30
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Operating activities
Net earnings $ 59,882 $ 19,782 $ 52,940 $ 78,808
Amortization and other (1,616) 1,098 (779) 3,024
Depletion and depreciation 34,006 33,168 115,354 107,032
Accretion of asset
retirement obligations 748 686 2,385 1,949
Unrealized foreign exchange
(gain) loss 19,173 (30,195) 32,899 (76,050)
Future income taxes 24,489 2,608 26,211 5,837
Unrealized risk management
(gain) loss (52,422) 4,846 (4,667) 22,257
Stock-based compensation 1,775 2,151 5,901 6,780
Asset retirement
expenditures (439) (2,146) (1,969) (3,863)
Non-controlling interest 1,079 1,135 4,373 4,724
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Funds flow from operations $ 86,675 $ 33,133 $ 232,648 $ 150,498
Change in non-cash working
capital 33,828 (12,510) 24,220 (14,165)
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Cash flow from operating
activities $ 120,503 $ 20,623 $ 256,868 $ 136,333
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Funds flow from operations for the third quarter of 2008 grew by 162% year over year to approximately $87 million. This growth is attributable to higher commodity prices combined with a $21 million realized risk management gain. For the nine months ended 2008, funds flow from operations increased by 55% year over year to approximately $233 million primarily as a result of higher commodity prices.
NET EARNINGS
Net earnings for the three months ended September 30, 2008 was approximately $60 million, an increase of 203% over the comparable period in 2007. In addition to higher commodity prices, net earnings for the quarter benefited from a risk management gain of $73.6 million ($48.6 million after taxes), of which $21.1 million was realized. The gain recognized in the third quarter more than offsets the risk management loss of $60.4 million recognized in the second quarter of 2008. For the nine months ended September 30, 2008, earnings fell by 33% when compared to the first nine months of 2007 primarily a result of fluctuations in the Canadian/US exchange rate. We recorded an exchange gain of $75.3 million for the nine months ended September 30, 2007 as compared to an exchange loss of $31 million for the same period in 2008.
Period over period net earnings continue to fluctuate significantly reflecting the volatility in exchange rates, commodity prices, and changes in income tax rates that effect future income taxes. The impact of this volatility is summarized in the determination of Adjusted Operational Earnings below.
Adjusted Operational earnings
Adjusted operational earnings is a non-GAAP measure that adjusts net earnings by non-operating items that reduce the comparability of our underlying financial performance between periods. These non-operating items, that are primarily of a non-cash nature, have been excluded in determining adjusted operational earnings. The following reconciliation has been prepared to provide investors with information that is more comparable between periods.
Summary of adjusted operational earnings(1)(3)
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Three Months Nine Months
($000s, except per Ended Sept. 30 Ended Sept. 30
share amounts) 2008 2007 2008 2007
-------------------------------------------------------------------------
Net earnings, as reported $ 59,882 $ 19,782 $ 52,940 $ 78,808
Non-operational items,
after tax
Unrealized foreign exchange
(gain) loss 16,346 (25,346) 28,046 (63,836)
Unrealized risk management
loss (gain) (36,958) 3,291 (3,290) 15,109
Stock-based compensation(2) 1,251 1,460 4,160 4,602
Effect of tax rate changes
on future income tax
liabilities - - - (4,025)
-------------------------------------------------------------------------
Adjusted operational earnings $ 40,521 $ (813) $ 81,856 $ 30,658
Per share
- basic $ 0.31 $ (0.01) $ 0.63 $ 0.24
- diluted $ 0.31 $ (0.01) $ 0.62 $ 0.23
-------------------------------------------------------------------------
(1) Adjusted operational earnings was referred to as adjusted net
earnings from operations or 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.
The non-GAAP measure adjusted operational earnings should not be
considered an alternative to or more meaningful than net earnings determined
in accordance with GAAP.
Revenue
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
Sept. 30 Sept. 30
2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Average production
Natural gas
(mmcf/d) 130 135 -4% 150 138 9%
Liquids (light
oil & ngls)
(bbls/d) 4,323 7,954 -46% 4,989 7,958 -37%
Total (boe/d) 26,006 30,440 -15% 29,931 30,881 -3%
Benchmark prices
AECO ($/GJ)
Monthly index $ 9.22 $ 5.32 73% $ 8.54 $ 6.43 33%
Daily index $ 7.73 $ 5.16 50% $ 8.59 $ 6.52 32%
WTI (U.S.$/bbl) $ 117.98 $ 75.38 57% $ 113.27 $ 66.18 71%
Edmonton Par
($/bbl) $ 121.79 $ 79.59 53% $ 115.09 $ 72.87 58%
Realized prices
Natural gas
($/mcf) $ 8.75 $ 5.23 67% $ 8.50 $ 6.47 31%
Liquids
($/bbl)(1) $ 124.05 $ 61.91 100% $ 109.22 $ 59.15 85%
Total ($/boe) $ 64.08 $ 38.56 66% $ 61.28 $ 44.48 38%
Revenue ($000s)
Natural gas $ 104,730 $ 64,891 61% $ 348,542 $ 243,082 43%
Crude oil
and ngls 48,592 43,089 13% 154,009 131,946 17%
-------------------------------------------------------------------------
Total $ 153,322 $ 107,980 42% $ 502,551 $ 375,028 34%
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(1) Includes sulphur.
During the third quarter of 2008, we sold four non-core assets. Production associated with these assets was approximately 4,100 boe/d comprised of 15 MMcf/d of natural gas and 1,600 bbls/d of crude oil and liquids. This, combined with high initial production decline rates typical of tight gas wells, resulted in production for the three and nine months ended September 30, 2008 to fall by 15% and 3% respectively. During the past 12 months, we have sold the majority of our predominantly oil weighted, non-core properties. These sales represented approximately 8,100 boe/d of production, and gross proceeds received were approximately $488 million. As a result of these sales, Compton's activities are now focused entirely in central Alberta and the Rock Creek/Ellerslie play at Niton/Caroline and in southern Alberta, including the Basal Quartz play at Hooker, the Plains Belly River play, and the thrusted Belly River play in the Foothills.
Total revenue for the third quarter of 2008 of $153 million was approximately 42% higher than in the third quarter of 2007 as a result of higher commodity prices that more than offset lower production volumes.
We market our natural gas through a combination of daily and monthly indexed contracts and aggregator contracts. Approximately 9.5% of our natural sales volumes remain committed to aggregator contracts, which realized a price during the current quarter that was, on average, $1.17/mcf less than prices received on non-aggregator volumes.
Royalties
-------------------------------------------------------------------------
Three Months Nine Months
Ended Sept. 30 Ended Sept. 30
2008 2007 2008 2007
-------------------------------------------------------------------------
Royalties ($000s) $ 31,694 $ 24,108 $ 102,868 $ 76,061
Percentage of revenues 20.7% 22.3% 20.5% 20.3%
-------------------------------------------------------------------------
The Alberta royalty structure is based upon commodity prices and well
productivity, with higher prices and well productivity attracting higher
royalty rates. Overall royalty rates, as a percentage of revenues, have
remained relatively consistent between the comparable periods.
Operating Expenses
-------------------------------------------------------------------------
Three Months Nine Months
Ended Sept. 30 Ended Sept. 30
2008 2007 2008 2007
-------------------------------------------------------------------------
Operating expenses ($000s) $ 27,447 $ 24,425 $ 84,735 $ 73,929
Operating expenses per boe
($/boe) $ 11.47 $ 8.72 $ 10.33 $ 8.77
-------------------------------------------------------------------------
Operating expenses for the three and nine months ended September 30, 2008
were higher than the comparable 2007 figures due to higher costs associated
with accelerated activity throughout the oil and gas industry. Additional
costs associated with our recent property dispositions and increased property
taxes that came due during the quarter also impacted third quarter operating
costs.
Transportation Expenses
-------------------------------------------------------------------------
Three Months Nine Months
Ended Sept. 30 Ended Sept. 30
2008 2007 2008 2007
-------------------------------------------------------------------------
Transportation expenses
($000s) $ 2,133 $ 4,227 $ 6,960 $ 10,961
Transportation expenses per
boe ($/boe) $ 0.89 $ 1.51 $ 0.85 $ 1.30
-------------------------------------------------------------------------
Transportation expenses for the three and nine months ended September 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 Nine Months
Ended Sept. 30 Ended Sept. 30
($000s, except where noted) 2008 2007 2008 2007
-------------------------------------------------------------------------
General and administrative
expenses $ 10,875 $ 11,298 $ 32,967 $ 32,104
Capitalized general and
administrative expenses (1,949) (1,520) (6,519) (5,126)
Operator recoveries (665) (676) (1,949) (2,244)
-------------------------------------------------------------------------
Total general and
administrative expenses $ 8,261 $ 9,102 $ 24,499 $ 24,734
General and administrative
expenses per boe ($/boe) $ 3.45 $ 3.25 $ 2.99 $ 2.93
-------------------------------------------------------------------------
Total general and administrative costs have remained relatively consistent
over the reporting periods although, on a boe basis, third quarter 2008 costs
increased as a result of lower production.
Strategic Review Expenses
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
Sept. 30, 2008 Sept. 30, 2008
-------------------------------------------------------------------------
Strategic review costs ($000s) $ 2,669 $ 8,903
Strategic review costs per boe ($/boe) $ 1.12 $ 1.09
-------------------------------------------------------------------------
In the third quarter of 2008, we incurred approximately $2.7 million in expenses associated with the strategic review and corporate sale process. Costs to date have totaled $8.9 million. We estimate direct costs associated with and resulting from the review and sale process could total approximately $25 million and include, among others, consulting and advisory fees, legal fees, and costs relating to employee retention. Costs are recognized when incurred. The balance of the costs are expected to be recognized during the fourth quarter of 2008.
Interest and Finance Charges
-------------------------------------------------------------------------
Three Months Nine Months
Ended Sept. 30 Ended Sept. 30
($000s, except where noted) 2008 2007 2008 2007
-------------------------------------------------------------------------
Interest on bank debt, net $ 4,992 $ 6,891 $ 17,415 $ 17,643
Interest on senior notes 9,334 9,328 27,355 29,571
-------------------------------------------------------------------------
Interest charges $ 14,326 $ 16,219 $ 44,770 $ 47,214
Finance charges 676 1,258 1,679 1,785
-------------------------------------------------------------------------
Total interest and finance
charges $ 15,002 $ 17,477 $ 46,449 $ 48,999
Total interest and finance
charges per boe ($/boe) $ 6.27 $ 6.24 $ 5.66 $ 5.81
-------------------------------------------------------------------------
Total interest and finance charges were lower during the third quarter of
2008 and for the nine months ended September 30, 2008 due to reduced
borrowings and lower interest rates on our revolving credit facility.
Weighted Average Debt
-------------------------------------------------------------------------
Three Months Nine Months
Ended Sept. 30 Ended Sept. 30
($000s, except where noted) 2008 2007 2008 2007
-------------------------------------------------------------------------
Bank debt $ 388,874 $ 412,174 $ 427,231 $ 460,070
Effective interest rate 5.14% 6.60% 5.43% 6.57%
Senior unsecured notes
(US$450,000) $ 460,474 $ 454,280 $ 446,822 $ 479,139
Effective interest rate 8.11% 8.21% 8.16% 8.23%
-------------------------------------------------------------------------
Depletion and Depreciation
-------------------------------------------------------------------------
Three Months Nine Months
Ended Sept. 30 Ended Sept. 30
2008 2007 2008 2007
-------------------------------------------------------------------------
Depletion and depreciation
($000s) $ 34,006 $ 33,168 $ 115,354 $ 107,032
Depletion and depreciation
per boe ($/boe) $ 14.21 $ 11.84 $ 14.07 $ 12.70
-------------------------------------------------------------------------
Stronger 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 is reflected in increased finding, development and on-stream costs which in turn have resulted in an increase in depletion and depreciation rates in comparison to prior comparative periods.
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 ------------------------------------------------------------------------- Nine Months Ended Sept. 30 ($000s) 2008 % 2007 % ------------------------------------------------------------------------- Land and seismic $ 16,089 6 $ 37,133 14 Drilling and completions 186,007 69 155,482 58 Production facilities 68,234 25 76,826 28 ------------------------------------------------------------------------- Sub-total, before under noted $ 270,330 100 $ 269,441 100 Net property acquisitions (dispositions) (192,671) (205,610) ------------------------------------------------------------------------- Sub-total $ 77,659 $ 63,831 MPP 156 4,271 ------------------------------------------------------------------------- Total capital expenditures $ 77,815 $ 68,102 -------------------------------------------------------------------------
In the first nine months of 2008 and prior to any acquisition and divestiture activity, capital expenditures totalled approximately $270 million, virtually the same as the $269 million of capital expenditure incurred in 2007. We drilled 234 (181 net) wells during the first nine months of 2008 as compared to 214 (177.7 net) wells in the same period of 2007. Drilling and completion costs during 2008 increased $30.5 million as compared to 2007. On a per well basis, drilling and completion costs in 2008 were $1,028,000 per well as compared to $875,000 per well in 2007, reflecting the proportionate increase in higher cost horizontal wells drilled in 2008 as compared to 2007. Land, seismic, and facility expenditures were approximately $29.6 million less in the first nine months of 2008 as compared to 2007. The decrease reflects our previous investments in these areas to the benefit of the current year.
During the third quarter of 2008, we closed the sale of four non-core asset divestitures for total net proceeds of approximately $204 million. Proceeds from the sale of these properties were used to reduce funds drawn on the bank credit facility and as at September 30, 2008, $260 million remains undrawn and available to the Company.
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) Losses
-------------------------------------------------------------------------
Three Months Nine Months
Ended Sept. 30 Ended Sept. 30
($000s) 2008 2007 2008 2007
-------------------------------------------------------------------------
Commodity contracts
Realized $ 9,939 $ (5,701) $ 19,032 $ (17,484)
Unrealized (71,619) 4,296 (8,614) 17,749
Cross currency interest
rate swap
Realized - - - 2,899
Unrealized - 436 - 4,394
Foreign currency contracts
Realized (31,080) - (27,360) 173
Unrealized 19,197 114 3,947 114
-------------------------------------------------------------------------
Total risk management $ (73,563) $ (855) $ (12,995) $ 7,845
-------------------------------------------------------------------------
Realized $ (21,141) $ (5,701) $ (8,328) $ (14,412)
Unrealized (52,422) 4,846 (4,667) 22,257
-------------------------------------------------------------------------
Total risk management $ (73,563) $ (855) $ (12,995) $ 7,845
-------------------------------------------------------------------------
Outstanding Commodity Contracts
Approximately 28% of current production is hedged for the balance of 2008.
The following table outlines commodity hedge contracts that were in place
during the third quarter of 2008 and/or are currently in place.
-------------------------------------------------------------------------
Commodity Term Amount Average Price Index
-------------------------------------------------------------------------
Natural gas
Collars April 2008 - Oct. 2008 70,000 GJ/d $7.14 - $8.51/GJ AECO
Fixed April 2008 - Oct. 2008 20,000 GJ/d $7.48/GJ AECO
Collars Nov. 2008 - March 2009 30,000 GJ/d $8.00 - $9.53/GJ AECO
Fixed Nov. 2008 - March 2009 10,000 GJ/d $8.10/GJ AECO
Crude oil
Fixed March 2008 - Dec. 2008 1,000 bbls/d U.S.$93.00/bbl WTI
-------------------------------------------------------------------------
Foreign Exchange Contracts
In late 2007, we entered into a number of forward foreign exchange
contracts relating to our US dollar denominated senior notes. During the
quarter, and in contemplation of a corporate transaction, we sold these
contracts, realizing a gain of $31.1 million included in risk management gains
and losses.
LIQUIDITY AND CAPITAL RESOURCES
-------------------------------------------------------------------------
As at As at
Sept 30, Dec. 31,
($000s, except where noted) 2008 2007
-------------------------------------------------------------------------
Senior term notes $ 476,955 $ 444,645
Associated unrealized risk management (gain) - (14,146)
-------------------------------------------------------------------------
$ 476,955 $ 430,499
Bank debt 240,000 400,000
-------------------------------------------------------------------------
Long term debt $ 716,955 $ 830,499
Adjusted working capital deficiency(1) 45,300 39,215
-------------------------------------------------------------------------
Total debt $ 762,255 $ 869,714
Shareholders' equity $ 933,448 $ 869,956
Total debt to adjusted EBITDA(2) 2.2x 3.6x
Total debt to total capitalization 45% 50%
Total debt to enterprise value(3) 50% 41%
-------------------------------------------------------------------------
(1) Adjusted working capital deficiency excludes risk management items
and related future income taxes, that are subject to market
volatility and may or may not be realized within a year.
(2) Adjusted EBITDA is a non-GAAP measure determined as outlined below.
---------------------------------------------------------------------
12 months ended September 30, 2008 December 31, 2007
---------------------------------------------------------------------
Net earnings $ 103,398 $ 129,266
Add (deduct)
Interest and finance charges 60,943 63,493
Income taxes (6,038) (26,435)
Depletion, depreciation and
amortization 159,733 151,411
Accretion of asset retirement
obligations 3,154 2,718
Foreign exchange (gain) loss 27,206 (78,717)
---------------------------------------------------------------------
Adjusted EBITDA $ 348,396 $ 241,736
---------------------------------------------------------------------
(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 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. The carrying value of the notes increased $32.3 million from December 31, 2007 as a result of the unrealized loss on translation at September 30, 2008. The senior notes are due on December 1, 2013.
Our bank debt is an extendable, revolving, syndicated credit facility in the authorized amount of $500 million. The facility was renewed on July 2, 2008 under substantially identical terms and conditions except that certain syndicate members, representing $90 million of the authorized amount of $500 million, elected not to extend their participation beyond July 2, 2009. The borrowing base upon which the facility was renewed gave full recognition to the recent property sales that closed during the third quarter of 2008. The next scheduled annual review of the facility is due mid-2009; if not extended at that time, amounts then outstanding are due July 2, 2010. During the third quarter of 2008, we reduced the amount drawn on the facility from $470 million at June 30, 2008 to $240 million.
At September 30, 2008, we are in full compliance with all covenants relating to our the senior notes and our syndicated credit facility. We foresee no difficulty in continuing to comply with these covenants.
Note 5 to the financial statements discusses our capital structure and certain non-GAAP measures utilized in managing our capital structure. We target a total debt to capitalization ratio of between 40% and 50%, and a total debt to adjusted EBITDA ratio between 2.5 to 1 and 3.0 to 1. At September 30, 2008 we had met or exceeded these targets.
We market our sales volumes to a number of substantial petroleum purchasers. We regularly monitor their credit worthiness and also limit the amount of exposure to any one purchaser. As a result of our procedures and policies we have not experienced any delays or losses on the sale of production.
We have entered into a number of commodity hedge contracts as outlined in the risk management section of this MD&A. The counterparties to these contracts are all members of our banking syndicate and any third party risk in relation to these contracts is minimal.
Our corporate debt is structured to provide us with financial flexibility and coincide with the long-life nature of our asset base. As at September 30, 2008, we have $260 million unused on our line of credit. Procedures and policies are in place that significantly reduce third party and counter party credit risk.
We believe internally generated funds from operations will be sufficient to fund our planned capital programs and we have the ability to modify these programs as circumstances warrant.
OUTLOOK
On October 30, 2008, Compton advised that the previously announced corporate sale process had been terminated and that Compton will continue to focus on operating as an independent exploration and production company.
The immediate focus of the Company's capital expenditure program will be on completion and tie-in activities to bring reserves on production. The drilling program will continue to concentrate on higher impact opportunities and capital expenditures will be consistent with available funds flow from operations. The major variable in determining such available funds will be natural gas prices. Given the enormous upheaval in financial and commodity markets since mid-September combined with the unpredictability of winter weather, forecasting such prices is very challenging. Compton's Board of Directors and Management will remain vigilant in the coming months in monitoring natural gas prices and adjusting capital expenditure programs to remain within available funds flow from operations. We are currently developing and expect to finalize our 2009 capital expenditures and operating plans by mid-December, at which time we will provide more detailed guidance for 2009.
Changes in Internal Control over Financial Reporting
There were no changes during the quarter ended September 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
-------------------------------------------------------------------------
Q3 Q2 Q1 Q4
-------------------------------------------------------------------------
Total revenue (millions) $ 153 $ 187 $ 162 $ 126
Funds flow from operations
(millions) $ 87 $ 77 $ 69 $ 46
Per share - basic $ 0.67 $ 0.59 $ 0.54 $ 0.35
- diluted $ 0.66 $ 0.58 $ 0.52 $ 0.35
Net earnings (millions) $ 60 $ (9) $ 2 $ 50
Per share - basic $ 0.46 $ (0.07) $ 0.01 $ 0.39
- diluted $ 0.46 $ (0.07) $ 0.01 $ 0.38
Adjusted net earnings from
operations (millions)(1) $ 40 $ 22 $ 19 $ 8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2007 2006
-------------------------------------------------------------------------
Q3 Q2 Q1 Q4
-------------------------------------------------------------------------
Total revenue (millions) $ 108 $ 126 $ 141 $ 130
Funds flow from operations
(millions) $ 33 $ 49 $ 69 $ 55
Per share - basic $ 0.26 $ 0.38 $ 0.53 $ 0.43
- diluted $ 0.25 $ 0.36 $ 0.52 $ 0.42
Net earnings (millions) $ 20 $ 45 $ 14 $ (10)
Per share - basic $ 0.15 $ 0.35 $ 0.11 $ (0.08)
- diluted $ 0.15 $ 0.34 $ 0.10 $ (0.08)
Adjusted net earnings from
operations (millions)(1) $ (1) $ 9 $ 22 $ 19
-------------------------------------------------------------------------
(1) Prior periods have been revised to conform with current period
presentation.
Third quarter 2008 revenue fell by 18% when compared to the second quarter of 2008 due to reduced production resulting from minor, non-core asset sales that closed in August 2008. Third quarter 2008 funds flow from operations grew by 13% when compared to the second quarter of 2008 as a result of a $21 million realized risk management gain. Net earnings for the third quarter of 2008 grew significantly year over year and when compared to the second quarter of 2008 due to realized risk management gains. In the second quarter of 2008, revenue and funds flow from operations increased by 15% and 12%, respectively, due to increased quarter over quarter natural gas production and strengthening commodity prices. 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. In the first quarter of 2008, revenue and funds flow from operations increased from the fourth quarter of 2007 due to increased production and higher commodity prices.
Revenue and funds flow from operations for the third quarter of 2007 decreased relative to the second quarter of 2007 due to lower natural gas prices. Production grew by five percent on a quarter over quarter basis. In the second quarter of 2007, revenue declined slightly due to reduced production. Net earnings, however, increased compared to the first quarter of 2007, largely due to an unrealized foreign exchange gain. In the first quarter of 2007, revenue and funds flow from operations increased from the fourth quarter of 2006 due primarily to higher commodity prices. On a quarter over quarter basis, net earnings increased significantly as fourth quarter of 2006 net earnings were negatively impacted by the reversal of unrealized foreign exchange gains recorded in prior quarters as a result of the weakening Canadian dollar relative to the U.S. dollar.
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)
-------------------------------------------------------------------------
September 30, December 31,
2008 2007
------------- -------------
(unaudited)
Assets
Current
Cash $ 5,901 $ 8,665
Accounts receivable 77,538 83,144
Risk management gain (Note 13b) 10,405 1,835
Other current assets 19,092 19,772
Future income taxes - 2,606
------------- -------------
112,936 116,022
Property and equipment 2,075,206 2,116,834
Goodwill 9,933 9,933
Other assets 346 291
Risk management gain (Note 13b) - 14,320
------------- -------------
$ 2,198,421 $ 2,257,400
------------- -------------
------------- -------------
Liabilities
Current
Accounts payable $ 147,831 $ 150,796
Risk management loss (Note 13b) - 8,832
Future income taxes 2,967 542
------------- -------------
150,798 160,170
Long term debt (Note 3) 704,685 832,188
Asset retirement obligations (Note 7) 34,994 36,696
Risk management loss (Note 13b) - 1,585
Future income taxes 313,691 293,494
Non-controlling interest (Note 8) 60,805 63,311
------------- -------------
1,264,973 1,387,444
------------- -------------
Shareholders' equity
Capital stock (Note 4) 245,974 235,871
Contributed surplus (Note 9a) 27,038 24,233
Retained earnings 660,436 609,852
------------- -------------
933,448 869,956
------------- -------------
$ 2,198,421 $ 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 Nine months ended
September 30, September 30,
----------------------- -----------------------
2008 2007 2008 2007
----------- ----------- ----------- -----------
Revenue
Oil and natural gas
revenues $ 153,322 $ 107,980 $ 502,551 $ 375,028
Royalties (31,694) (24,108) (102,868) (76,061)
----------- ----------- ----------- -----------
121,628 83,872 399,683 298,967
----------- ----------- ----------- -----------
Expenses
Operating 27,447 24,425 84,735 73,929
Transportation 2,133 4,227 6,960 10,961
General and
administrative 8,261 9,102 24,499 24,734
Stock-based compensation 2,555 2,150 9,172 9,398
Strategic review
(Note 16) 2,669 - 8,903 -
Interest and finance
charges (Note 10) 15,002 17,477 46,449 48,999
Foreign exchange (gain)
loss (Note 14) 16,907 (30,044) 30,666 (75,257)
Risk management (gain)
loss (Note 13c) (73,563) (855) (12,995) 7,845
Depletion and
depreciation 34,006 33,168 115,354 107,032
Accretion of asset
retirement obligations 748 686 2,385 1,949
----------- ----------- ----------- -----------
36,165 60,336 316,128 209,590
----------- ----------- ----------- -----------
Earnings before taxes and
non-controlling interest 85,463 23,536 83,555 89,377
----------- ----------- ----------- -----------
Income taxes (Note 12)
Current 13 11 31 8
Future 24,489 2,608 26,211 5,837
----------- ----------- ----------- -----------
24,502 2,619 26,242 5,845
----------- ----------- ----------- -----------
Earnings before
non-controlling interest 60,961 20,917 57,313 83,532
Non-controlling interest 1,079 1,135 4,373 4,724
----------- ----------- ----------- -----------
Net earnings 59,882 19,782 52,940 78,808
Other comprehensive income - - - -
----------- ----------- ----------- -----------
Comprehensive income $ 59,882 $ 19,782 $ 52,940 $ 78,808
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
Net earnings per share
(Note 11)
Basic $ 0.46 $ 0.15 $ 0.41 $ 0.61
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
Diluted $ 0.46 $ 0.15 $ 0.40 $ 0.59
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
-------------------------------------------------------------------------
Compton Petroleum Corporation
Consolidated Statements of Retained Earnings
(unaudited) (thousands of dollars)
-------------------------------------------------------------------------
Three months ended Nine months ended
September 30, September 30,
----------------------- -----------------------
2008 2007 2008 2007
----------- ----------- ----------- -----------
Retained earnings,
beginning of period $ 602,217 $ 541,082 $ 609,852 $ 483,838
Net earnings 59,882 19,782 52,940 78,808
Premium on redemption of
shares (Note 4) (1,663) (400) (2,356) (2,182)
----------- ----------- ----------- -----------
Retained earnings,
end of period $ 660,436 $ 560,464 $ 660,436 $ 560,464
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
See accompanying notes to the consolidated financial statements.
-------------------------------------------------------------------------
Compton Petroleum Corporation
Consolidated Statements of Cash Flow
(unaudited) (thousands of dollars)
-------------------------------------------------------------------------
Three months ended Nine months ended
September 30, September 30,
----------------------- -----------------------
2008 2007 2008 2007
----------- ----------- ----------- -----------
Operating activities
Net earnings $ 59,882 $ 19,782 $ 52,940 $ 78,808
Amortization and other (1,616) 1,098 (779) 3,024
Depletion and
depreciation 34,006 33,168 115,354 107,032
Accretion of asset
retirement obligations 748 686 2,385 1,949
Unrealized foreign
exchange (gain) loss 19,173 (30,195) 32,899 (76,050)
Future income taxes 24,489 2,608 26,211 5,837
Unrealized risk
management (gain) loss (52,422) 4,846 (4,667) 22,257
Stock-based compensation 1,775 2,151 5,901 6,780
Asset retirement
expenditures (439) (2,146) (1,969) (3,863)
Non-controlling interest 1,079 1,135 4,373 4,724
----------- ----------- ----------- -----------
86,675 33,133 232,648 150,498
Change in non-cash
working capital 33,828 (12,510) 24,220 (14,165)
----------- ----------- ----------- -----------
120,503 20,623 256,868 136,333
----------- ----------- ----------- -----------
Financing activities
Repayment of bank debt (229,260) (144,509) (159,089) (103,894)
Proceeds from share
issuances 768 195 7,757 2,797
Distributions to
limited partner (2,293) (2,307) (6,879) (6,893)
Redemption of common
shares (2,268) (484) (3,105) (2,603)
----------- ----------- ----------- -----------
(233,053) (147,105) (161,316) (110,593)
----------- ----------- ----------- -----------
Investing activities
Property and equipment
additions (105,573) (113,824) (269,498) (269,849)
Corporate acquisitions - (74,965) - (74,965)
Property acquisitions - (7,450) (11,673) (8,042)
Property dispositions 203,864 259,763 204,344 305,596
Change in non-cash
working capital 7,000 58,683 (21,489) 19,648
----------- ----------- ----------- -----------
105,291 122,207 (98,316) (27,612)
----------- ----------- ----------- -----------
Change in cash (7,259) (4,275) (2,764) (1,872)
Cash, beginning of
period 13,160 14,279 8,665 11,876
----------- ----------- ----------- -----------
Cash, end of period $ 5,901 $ 10,004 $ 5,901 $ 10,004
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
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)
September 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 Canada
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, how those risks
are managed by the Company and are 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
September 30, December 31,
2008 2007
------------- -------------
Syndicated bank debt
Prime rate $ 50,000 $ 50,000
Bankers' acceptance 190,000 350,000
Discount to maturity (663) (1,574)
------------- -------------
239,337 398,426
------------- -------------
Senior term notes
US $450 million senior term notes 476,955 444,645
Unamortized transaction costs (11,607) (10,883)
------------- -------------
465,348 433,762
------------- -------------
$ 704,685 $ 832,188
------------- -------------
------------- -------------
As at September 30, 2008, the Company had arranged authorized senior
credit facilities with a syndicate of banks in the amount of
$500 million. Pursuant to the annual review by the banking syndicate, the
facility was renewed under terms and conditions similar to those
disclosed in the December 31, 2007 consolidated financial statements.
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
September 30, 2008 December 31, 2007
----------------------- -----------------------
Number of Number of
shares Amount 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 1,388 10,363 993 4,603
Shares repurchased (399) (750) (398) (724)
----------- ----------- ----------- -----------
Common shares outstanding,
end of period 130,137 $ 245,974 129,098 $ 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 commons shares, representing
approximately 5.0% of the issued and outstanding common shares at the
time the bid received regulatory approval. During the nine months ended
September 30, 2008, the Company purchased for cancellation 399,700 common
shares at an average price of $7.77 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:
September 30, December 31,
2008 2007
------------- -------------
Senior term notes $ 476,955 $ 444,645
Associated unrealized risk management (gain) - (14,146)
------------- -------------
476,955 430,499
Bank debt 240,000 400,000
------------- -------------
Long-term debt 716,955 830,499
Adjusted working capital (surplus) deficiency(x) 45,300 39,215
------------- -------------
Total net debt 762,255 869,714
Total shareholder's equity 933,448 869,956
------------- -------------
Total capitalization $ 1,695,703 $ 1,739,670
------------- -------------
------------- -------------
Total net debt to capitalization ratio 45% 50%
------------- -------------
------------- -------------
(x) Adjusted working capital excludes risk management items and 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 September 30, 2008 the carrying value increased by
$32.3 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 fixed the
liability in Canadian dollars through to December 1, 2010. The unrealized
risk management gain on these contracts was previously recognized as a
reduction to the notes in determining total net debt and capitalization
as calculated above. During the third quarter of 2008, the Company sold
all of these contracts realizing a net gain of $31.4 million.
The Company's total net debt to capitalization decreased to 45% at
September 30, 2008 from 50% at December 31, 2007. During the third
quarter of 2008, the Company closed several property divestments. The
disposition proceeds together with the proceeds realized on the sale of
the foreign exchange contracts were used to reduce bank debt.
Compton targets a total net debt to adjusted EBITDA of 2.5 to 3.0 times.
At September 30, 2008 total net debt to adjusted EBITDA was 2.2x
(December 31, 2007 - 3.6x) calculated on a trailing 12 month basis as
follows:
September 30, December 31,
2008 2007
------------- -------------
Total net debt $ 762,255 $ 869,714
------------- -------------
------------- -------------
September 30, December 31,
12 months ended 2008 2007
------------- -------------
Net earnings $ 103,398 $ 129,266
Add (deduct)
Interest and finance charges 60,943 63,493
Income taxes (6,038) (26,435)
Depletion, depreciation and amortization 159,733 151,411
Accretion of asset retirement obligations 3,154 2,718
Foreign exchange (gain) loss 27,206 (78,717)
------------- -------------
Adjusted EBITDA $ 348,396 $ 241,736
------------- -------------
------------- -------------
Total net debt to adjusted EBITDA 2.2x 3.6x
Compton is subject to certain financial covenants relating to its credit
facility and senior notes and at September 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:
September 30, December 31,
2008 2007
------------- -------------
Asset retirement obligations,
beginning of period $ 36,696 $ 29,791
Liabilities incurred 3,349 8,719
Liabilities settled and disposed (5,737) (4,532)
Accretion expense 2,385 2,718
Revision of estimate (1,699) -
------------- -------------
Asset retirement obligations, end of period $ 34,994 $ 36,696
------------- -------------
------------- -------------
8. Non-controlling interest
Pursuant to AcG-15, these consolidated financial statements include the
assets, liabilities and operations of MPP. Equity in MPP, attributable to
its partners, is recorded on consolidation as a non-controlling interest
and is comprised of the following:
September 30, December 31,
2008 2007
------------- -------------
Non-controlling interest, beginning of period $ 63,311 $ 66,350
Earnings attributable to non-controlling
interest 4,373 6,132
Distributions to limited partner (6,879) (9,171)
------------- -------------
Non-controlling interest, end of period $ 60,805 $ 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 September 30,
2008 is $5.4 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:
September 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 503 $9.76 2,074 $11.02
Exercised (1,388) $5.24 (993) $3.47
Forfeited (336) $12.75 (608) $11.97
----------- ----------- ----------- -----------
Outstanding,
end of period 10,863 $8.83 12,084 $8.49
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
Exercisable,
end of period 7,454 $7.51 7,240 $6.20
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
The range of exercise prices of stock options outstanding and
exercisable at September 30, 2008 was as follows:
Outstanding Options Exercisable Options
---------------------------------- ------------------------
Weighted
average Weighted Weighted
Range of Number of remaining average Number of average
exercise options contractual exercise options exercise
prices outstanding life (years) price outstanding price
------------ ----------- ----------- ----------- ----------- -----------
(000s) (000s)
$1.83 - $3.99 2,277 1.9 $2.75 2,277 $2.75
$4.00 - $6.99 1,161 3.2 $4.36 1,161 $4.36
$7.00 - $9.99 1,785 2.1 $8.13 1,115 $7.66
$10.00 - $11.99 2,730 2.8 $11.20 1,208 $11.09
$12.00 - $13.99 1,596 2.0 $12.63 1,027 $12.60
$14.00 - $18.39 1,314 2.4 $14.70 666 $14.70
----------- ----------- ----------- ----------- -----------
10,863 2.4 $8.83 7,454 $7.51
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
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 Nine months ended
September 30, September 30,
----------------------- -----------------------
2008 2007 2008 2007
----------- ----------- ----------- -----------
Weighted average fair
value of options
granted $4.35 $4.14 $3.95 $4.35
Risk-free interest rate 3.4% 4.4% 3.4% 4.1%
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:
September 30, December 31,
2008 2007
------------- -------------
Contributed surplus, beginning of period $ 24,233 $ 16,974
Stock-based compensation expense 5,901 8,416
Stock options exercised (3,096) (1,157)
------------- -------------
Contributed surplus, end of period $ 27,038 $ 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 the
grant and entitles the holder to receive a cash payment equal to the
fair market value of one common share of Compton per vested RSU. As
at September 30, 2008 there are 842,833 RSUs outstanding under the
Plan. During the period ended September 30, 2008, the Board of
Directors fixed a minimum cash payment amount of $12.00 per RSU,
relating to 489,500 RSU's granted to employees excluding those
granted to officers and directors of the Company.
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 nine months ending September 30,
2008 the Company recognized, within stock-based compensation,
$3.3 million (June 30, 2008 - $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
September 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 September 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 September 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 Nine months ended
September 30, September 30,
----------------------- -----------------------
2008 2007 2008 2007
----------- ----------- ----------- -----------
Interest on bank debt,
net $ 4,992 $ 6,891 $ 17,415 $ 17,643
Interest on senior term
notes 9,334 9,328 27,355 29,571
Other finance charges 676 1,258 1,679 1,785
----------- ----------- ----------- -----------
$ 15,002 $ 17,477 $ 46,449 $ 48,999
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
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 Nine months ended
September 30, September 30,
----------------------- -----------------------
2008 2007 2008 2007
----------- ----------- ----------- -----------
(000s) (000s) (000s) (000s)
Weighted average common
shares outstanding
- basic 130,219 129,131 129,737 128,952
Effect of stock options 876 3,376 3,181 3,797
----------- ----------- ----------- -----------
Weighted average common
shares outstanding
- diluted 131,095 132,507 132,918 132,749
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
12. Income taxes
The following table reconciles income taxes calculated at the Canadian
statutory rates with actual income taxes:
Three months ended Nine months ended
September 30, September 30,
----------------------- -----------------------
2008 2007 2008 2007
----------- ----------- ----------- -----------
Earnings before taxes and
non-controlling interest $ 85,463 $ 23,536 $ 83,555 $ 89,377
----------- ----------- ----------- -----------
Canadian statutory rates 29.5% 32.1% 29.5% 32.1%
Expected income taxes $ 25,212 $ 7,555 $ 24,649 $ 28,690
Effect on taxes resulting
from:
Non-deductible
stock-based compensation 523 691 1,741 2,178
Effect of tax rate
changes and temporary
differences recorded at
future rates (4,248) (1,180) (3,507) (11,379)
Non-taxable capital
(gains) losses 2,037 (4,267) 2,667 (11,587)
Other 978 (180) 692 (2,057)
----------- ----------- ----------- -----------
Provision for income
taxes $ 24,502 $ 2,619 $ 26,242 $ 5,845
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
Current $ 13 $ 11 $ 31 $ 8
Future 24,489 2,608 26,211 5,837
----------- ----------- ----------- -----------
$ 24,502 $ 2,619 $ 26,242 $ 5,845
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
Effective tax rate 28.7% 11.1% 31.4% 6.5%
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
13. Financial instruments and risk management
At September 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 value of financial assets and
liabilities, b) risk management assets and liabilities, c) risk
management gains and losses and d) risk 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:
September 30, 2008 December 31, 2007
----------------------- -----------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
----------- ----------- ----------- -----------
Financial assets
Held-for-trading
Cash $ 5,901 $ 5,901 $ 8,665 $ 8,665
Other current assets 19,092 19,092 19,772 19,772
Risk management
assets(x) 10,405 10,405 16,155 16,155
Loans and receivables
Accounts receivable 77,538 77,538 83,144 83,144
Financial liabilities
Held-for-trading
Risk management
liabilities(x) $ - $ - $ 10,417 $ 10,417
Other financial
liabilities
Accounts payable 147,831 147,831 150,796 150,796
Bank debt 239,337 239,337 398,426 398,426
Senior term notes 465,348 419,720 433,762 415,743
(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 indicators 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 September December
Contracts Currency 30, 2008 31, 2007
----------- ----------- ----------- -----------
Unrealized gain
Current asset $ 10,405 $ - $ 10,405 $ 1,835
Non-current asset - - - 14,320
Unrealized loss
Current liability - - - (8,832)
Non-current
liability - - - (1,585)
----------- ----------- ----------- -----------
Total unrealized
gain (loss) $ 10,405 $ - $ 10,405 $ 5,738
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
ii) Net fair value of commodity positions
On September 30, 2008, the Company had the following commodity
contracts in place:
Daily
Notional Mark-to-
Commodity Term Volume Average Price Market
--------- ---- -------- ------------- -----------
gain (loss)
Natural Gas
Apr./08 -
Summer collar Oct./08 70,000 GJ $7.14 - $8.51/GJ $ 2,760
Apr./08 -
Summer fixed Oct./08 20,000 GJ $7.48/GJ 967
Nov./08 -
Winter collar Mar./09 30,000 GJ $8.00 - $9.53/GJ 5,580
Nov./08 -
Winter fixed Mar./09 10,000 GJ $8.10/GJ 1,646
Mar./08 -
Oil fixed price Dec./08 1,000 bbl US $93.00 /bbl (721)
Jan./07 -
Electricity Dec./08 2.5 MW $55.00/MWh 173
-----------
Total unrealized
commodity gain $ 10,405
-----------
-----------
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:
Nine months ended Commodity Foreign 2008 2007
September 30, Contracts Currency Total Total
----------- ----------- ----------- -----------
Unrealized change in
fair value $ (8,614) $ 3,947 $ (4,667) $ 22,257
Realized cash
settlements 19,032 (27,360) (8,328) (14,412)
----------- ----------- ----------- -----------
Total (gain) loss $ 10,418 $ (23,413) $ (12,995) $ 7,845
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
Three months ended Commodity Foreign 2008 2007
September 30, Contracts Currency Total Total
----------- ----------- ----------- -----------
Unrealized change in
fair value $ (71,619) $ 19,197 $ (52,422) $ 4,846
Realized cash
settlements 9,939 (31,080) (21,141) (5,701)
----------- ----------- ----------- -----------
Total (gain) loss $ (61,680) $ (11,883) $ (73,563) $ (855)
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
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 September 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 $2.1 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, when
appropriate, Compton enters into agreements to fix the exchange rate
of Canadian dollars to US dollars 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. Additionally, the
Company entered into a series of foreign exchange contracts relating
to the semi-annual interest settlement obligations until November 30,
2010.
During the period ended September 30, 2008 the Company sold the
foreign exchange contracts for proceeds of $34.7 million in
contemplation of a corporate transaction.
- 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 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.
During the period ended September 30, 2008 the Company collapsed the
cross currency interest rate swap contract at a cost of $3.6 million
in contemplation of a corporate transaction.
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 unresolved
differences with partners. Substantially all of the receivable
balances at September 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 September 30, 2008,
four financial institutions held all 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 available $260 million of unused credit facility
under the recently renewed syndicated banking agreement. The Company
also has the ability to modify the capital expenditure program when
circumstances warrant, to preserve cash.
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 $ 147,831 $ - $ - $ - $ 147,831
Bank debt - 240,000 - - 240,000
Senior
term
notes - - - 476,955 476,955
----------- ----------- ----------- ----------- -----------
$ 147,831 $ 240,000 $ - $ 476,955 $ 864,786
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
14. Foreign exchange (gain) loss
Amounts charged to foreign exchange (gain) loss during the period ended
are as follows:
Three months ended Nine months ended
September 30, September 30,
----------------------- -----------------------
2008 2007 2008 2007
----------- ----------- ----------- -----------
Foreign exchange on
translation of US$ debt $ 19,173 $ (30,195) $ 32,899 $ (76,050)
Other foreign exchange (2,266) 151 (2,233) 793
----------- ----------- ----------- -----------
Total (gain) loss $ 16,907 $ (30,044) $ 30,666 $ (75,257)
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
15. Supplemental cash flow information
Amounts actually paid during the period for interest expense and capital
taxes are as follows:
Three months ended Nine months ended
September 30, September 30,
----------------------- -----------------------
2008 2007 2008 2007
----------- ----------- ----------- -----------
Interest paid $ 4,928 $ 7,334 $ 35,438 $ 38,320
Taxes paid 44 41 44 41
----------- ----------- ----------- -----------
$ 4,972 $ 7,375 $ 35,482 $ 38,361
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
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 had determined to seek a
buyer for all of the capital stock of the Company. On October 30, 2008,
the Company announced the corporate sale process has been terminated as
an acceptable offer for all of the Company's common shares had not been
forthcoming. The Company also announced that all marketing efforts to
effect a corporate sale had ceased.
The Company has estimated direct costs associated with, and resulting
from the review process will total approximately $25 million. These costs
include among others, consulting and advisory fees, legal fees, and costs
relating to employee retention. As at September 30, 2008, the Company has
recorded $8.9 million of strategic review related expenses. The balance
of the costs will be recognized as incurred during the fourth quarter of
2008.
17. Reclassification
Certain amounts disclosed for prior periods have been reclassified to
conform with current period presentation.
CONFERENCE CALL
Compton will be conducting a conference call and audio webcast November 12, 2008 at 9:30 a.m. (MT) or 11:30 a.m. (ET) to discuss the Company's 2008 third quarter financial and operating results. To participate in the conference call, please contact the Conference Operator at 9:20 a.m. (MT), ten minutes prior to the call.
Conference Operator Dial-in Number: Toll-Free: 1-800-814-4862
Local Toronto: 1-416-646-3097
Audio webcast URL:
http://phx.corporate-ir.net/phoenix.zhtml?c(equal sign)69018&p(equal sign)irol-EventDetails&EventId(equal sign)
2011803
The audio replay will be available two hours after the conclusion of the conference call and will be accessible until November 19, 2008. Callers may dial toll-free 877-289-8525 and enter access code 21287891 (followed by the pound key).
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.
%SEDAR: 00003803E %CIK: 0001043572