CALGARY, May 9 /CNW/ - Compton Petroleum Corporation ("Compton" or the "Company") is pleased to announce its financial and operating results for the quarter ended March 31, 2007 and the Company's strategic direction for the remainder of 2007 and 2008.
HIGHLIGHTS -- FIRST QUARTER 2007
- Drilled 71 wells with a 93% success rate.
- Natural gas production of 148 mmcf/d, up 4% from first quarter 2006.
- Total first quarter 2007 production averaged 33,316 boe/d, down 2%
from first quarter 2006.
- Revenue of $141 million, down 5% from first quarter 2006.
- Cash flow of $69 million, down 8% from a year ago.
- Capital expenditures of $106 million or $61 million net after
$45.9 million in minor non-core property divestitures.
HIGHLIGHTS -- STRATEGIC DIRECTION
- Expanded 2007 drilling program by up to 100 wells.
- Divestiture of oil properties in the Peace River Arch.
- Focus on core business of natural gas resource plays concentrated in
two core areas.
Financial Summary
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Three Months Ended March 31
($000s, except per share amounts) 2007 2006 Change
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Gross revenue $140,877 $148,779 -5%
Cash flow from operations(1) $ 68,783 $ 74,596 -8%
Per share - basic(1) $ 0.53 $ 0.58 -10%
- diluted(1) $ 0.52 $ 0.55 -5%
Operating earnings(1) $ 17,933 $ 22,403 -20%
Net earnings $ 13,719 $ 38,002 -64%
Per share - basic $ 0.11 $ 0.30 -63%
- diluted $ 0.10 $ 0.28 -64%
Capital expenditures (before divestitures) $106,059 $166,351 -36%
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(1) See cautionary statements following Management's Discussion and
Analysis.
OPERATING SUMMARY
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Three Months Ended March 31 2007 2006 Change
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Average production
Natural gas (mmcf/d) 148 142 4%
Liquids (bbls/d) 8,729 10,418 -16%
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Total (boe/d) 33,316 34,029 -2%
Realized prices
Natural gas ($/mcf) $ 7.24 $ 7.58 -4%
Liquids ($/bbl) 54.20 48.70 11%
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Total ($/boe) $ 46.98 $ 48.58 -3%
Field netback ($/boe) $ 30.84 $ 29.80 3%
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Strategic Direction for 2007
As outlined in Mr. Sapieha's President's Message presented in our 2006 Annual Report to Shareholders, our primary objective for 2007 is the continued development of our natural gas resource plays while setting the stage for accelerated drilling programs and production growth in 2008 and beyond. Our initial plans for 2007 were prepared giving full consideration to industry conditions existing in late 2006. These plans resulted in a relatively conservative 2007 budget, with emphasis placed on efficient operations and cost controls while setting the stage for expanded activities in 2008 and beyond.
Industry conditions have changed significantly since we prepared our
initial plans for 2007:
- natural gas prices have strengthened and, based upon fundamentals,
are expected to strengthen further;
- service sector costs are declining and operating efficiencies related
to reduced industry activity have begun to occur;
- technical and other personnel are more available; and
- opportunities for expansion, at reasonable costs, in our focus areas
are becoming available.
In relation to Compton itself:
- we are increasingly confident in our geological and geophysical
models and the repeatability of our drilling programs, evidenced by
our reserve growth achieved at very competitive costs;
- we have and are continuing to strengthen our technical teams and
staff complement and are moving forward with the development of
efficient control procedures and systems required for a manufacturing
and processing resource development model;
- future drilling and other services are being secured at much reduced
cost levels from 2006; and
- the receipt and in-house interpretation of seismic surveys conducted
in 2006 and early 2007, in southern Alberta and at Niton, have
assisted us in identifying an increasing number of excellent drill
locations. Currently in southern Alberta, we have identified and are
in the process of securing in excess of 256 well locations on our
Belly River/Edmonton play, well in excess of the 215 wells initially
planned for 2007.
We have always recognized the key to realizing on the value of our resource plays would be achieved through down-spacing and accelerated drilling programs necessary for production growth from unconventional and tight gas reservoirs. We also recognized such programs were dependent upon having the technical teams and systems in place to manage these programs. Additionally, commodity prices and the industry cost structure must be such that these programs would produce the desired economic returns.
We believe all the conditions, both from an industry point of view and the Company's development, are in place. Now is the time to accelerate our activities. Accordingly, we are now in the process of revising our short term plans and budget for the remainder of 2007 and developing a long term strategic plan for 2008 through 2010.
Integral to these plans are:
- an expanded drilling program for the second half of 2007 through the
addition of up to 100 drill wells, primarily in our southern Alberta
Belly River/Edmonton play and at Niton;
- divestiture of our Peace River Arch oil properties to strengthen our
balance sheet and provide the financial resources and flexibility
required for expanded drilling programs and other natural gas
resource play opportunities should they arise, with the divestitures
expected to close mid summer;
- the continued expansion of our technical teams including the
redeployment of personnel from the Peace River Arch to our focus
natural gas plays;
- the commencement of an expanded commodity hedge program to secure
downside price protection and reduce uncertainty in cash flow to fund
expanded capital programs.
We expect to have finalized our revised plans and budget for the remainder of 2007 by mid June. We will release the details of our revised budget, including planned capital expenditures and guidance relating to production and cash flow for 2007, together with a summary of our strategic plan for 2008 through 2010, following June 20th and 21st Board of Directors' meetings.
We are excited with our prospects for the remainder of 2007 and beyond. Given Compton's wealth of opportunities and evolving industry conditions, we believe now is the time to accelerate our activities.
OPERATIONS REVIEW
In the first quarter of 2007 we drilled 71 wells with a 93% success rate. The total number of wells drilled in the first three months of 2007 was less than the comparable period in 2006. Activity during the first quarter of 2007 was tempered by less shallow gas drilling attributable to a delay in shooting proprietary 3D seismic and the early onset of spring breakup. The 3D data is now in-house and has been fully interpreted by our technical teams, with positive results. Use of our extensive and proprietary seismic database continues to contribute materially to the targeted development of Compton's resource base. As we move forward in 2007, Compton's drilling program will continue to capitalize on this database to identify optimal well locations, while at the same time maximizing capital and other operating efficiencies.
Capital discipline remains foremost in Compton's strategy. We are committed to instituting a capital efficient resource manufacturing and processing model to develop our extensive resource base. As such, use of our seismic and geological models, when combined with opportunities to group or "batch" drill in areas where infrastructure is in place, will result in a significant increase of shallow gas drills following breakup. Additionally, our 2007 drilling program was designed to take advantage of anticipated lower service sector costs in the latter half of the year.
Drilling Summary
Of the 71 wells drilled during the quarter, 61, or 86%, were classified as development wells and 10, or 14%, as exploratory wells. The following table summarizes drilling results to March 31, 2007.
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Gas Oil D&A Total Net Success
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Southern Alberta 38 - 1 39 37 97%
Central Alberta 13 4 2 19 14 89%
Peace River Arch - 8 2 10 9 80%
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Standing, cased wells 3 3
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Total 71 63 93%
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Southern Alberta
Southern Alberta remains the primary focus of our activities. We hold in excess of 1,000 sections of land in southern Alberta that are prospective for multiple zones including Basal Quartz at Hooker, thrusted Belly River at Callum, Wabamun/Crossfield, the Plains Belly River, and the Edmonton Horseshoe Canyon coal bed methane.
During the first quarter of 2007, we drilled 39 (37 net) wells with a 97% success rate in southern Alberta.
Plains Belly River and Edmonton Horseshoe Canyon Coal Bed Methane
We drilled 34 Belly River wells in the first quarter. The drilling locations of these wells were identified using Compton's seismic and geological models, and all wells encountered multiple pay sections, including uphole Edmonton sands and Horseshoe Canyon coals. We completed facility expansions at Centron, Long Coulee, and Ghost Pine, and we are currently working on surface lease acquisitions for an additional 256 drilling locations in this area.
We continue to benefit from our extensive 3D seismic database. All locations for our 2007 well drilling program have been identified, and we are now identifying locations for the 2008 program. All of the elements of Compton's long term growth strategy are now in place: the well locations and pipelines have been surveyed, the rigs are contracted, and secondary services are being bid out. The end of spring break-up will mark the beginning of an aggressive drilling program that will see us drilling 215 Belly River/Edmonton Horseshoe Canyon wells by year end.
Callum Thrusted Belly River
At Callum, Compton drilled a horizontal well intended to maximize access to a recognized gas charged section while minimizing our surface impact. This well has been placed on continuous production since the beginning of April.
Our exploration program at Callum is designed to minimize our environmental footprint in this environmentally sensitive area. Compton continues to work with all stakeholders to design a mutually acceptable development program for this high impact resource play.
Hooker Basal Quartz
In the first three months of 2007, five wells were drilled targeting the lower Cretaceous Basal Quartz resource play at Hooker. Four wells were successful, with two of the wells currently producing more than 1.0 mmcf/d each. Completion operations will commence on the remaining wells following conclusion of break-up. Follow up infill locations are in place for the balance of our 20 well drilling program in this area.
Central Alberta
Central Alberta provides Compton with excellent multi-zone exploration and development drilling opportunities using analogous techniques gained through our experience with unconventional gas development in southern Alberta. Compton has an average 59% working interest in 580,053 (341,533 net) acres of land in central Alberta. In the first quarter of 2007, we drilled 21 (17 net) wells with an 89% success rate. Eight of these wells, one of which was horizontal, were drilled at Niton targeting the Gething and Rock Creek formations. All of our first quarter 2007 Niton wells were successful.
At Niton, Compton's 13-10-53-15W5M horizontal Rock Creek gas well continues to perform in excess of expectations. Since it was placed on-stream in October 2006, this well has produced over 1 Bcf of gas, and it continues to produce at rates in excess of 5.5 mmcf/d. Following this success, we have licensed one offset Rock Creek horizontal well, and we are in the process of obtaining two additional horizontal well licenses on adjacent sections. We have also obtained approval to increase our infrastructure capacity in the area in advance of our proposed drilling plans.
In the first quarter, Compton conducted an extensive 3D seismic program at Niton, which is currently being interpreted in-house. Multiple vertical and horizontal locations are planned for this area, targeting the Rock Creek, Gething, and Cardium formations. We plan to accelerate our exploitation of the resource potential in this area, where we have developed a long term competitive advantage through our continued investment in infrastructure, facilities, and land. The expansion of the Niton 7-34 gas plant was completed in the first quarter. We are now capable of processing up to 23 mmcf/d through our 100% owned plant.
Peace River Arch
The Peace River Arch area, located north of Grande Prairie, is Compton's conventional oil development area. The Company averages a 62% working interest in 188,160 (116,801 net) acres of land in the area. We drilled 10 (9 net) wells in the Arch with an 80% success rate during the first quarter of 2007.
Worsley
At Worsley, we completed our facilities expansion to approximately 14 mmcf/d. We drilled three vertical and six horizontal wells in the area. We are currently reviewing the production data for each well to determine future drilling opportunities.
Mazeppa Gas Plant
In the second quarter of 2007, the Mazeppa gas plant is scheduled for turnaround from April 27 to May 14. This regularly scheduled turnaround occurs every three years. The plant is capable of processing 90 mmcf/d of sour and 45 mmcf/d of sweet gas. The stand alone sweet gas plant side became fully operational again as of May 7, 2007, and the sour side of the plant is expected to be fully operational by May 14, 2007.
MANAGEMENT'S DISCUSSION AND ANALYSIS
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Management's Discussion and Analysis ("MD&A") is intended to provide both an historical and prospective view of our activities. The MD&A was prepared as at May 9, 2007 and should be read in conjunction with the interim unaudited consolidated financial statements for the three months ended March 31, 2007 and the audited consolidated financial statements for the year ended December 31, 2006, available in printed form on request and posted on the Company's website.
Additional advisories with respect to forward looking statements, the use of non-GAAP Financial Measures, and the use of BOE volumetric measures are set out at the end of this MD&A.
EXECUTIVE SUMMARY
- First quarter 2007 natural gas production of 148 mmcf/d, a 4% year
over year increase.
- Total first quarter 2007 production averaged 33,316 boe/d, a 2%
decrease from first quarter 2006 despite increased natural gas
volumes from our key resource plays.
- Cash flow from operations of $69 million, down 8% from first quarter
2006 due to lower year over year commodity prices and production
volumes.
- Net earnings of $13.7 million were negatively impacted by a
$17.3 million unrealized risk management loss due to mark-to-market
accounting of commodity price hedges.
RESULTS OF OPERATIONS
Cash Flow from Operations and Net Earnings
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Three Months Ended March 31
($000s, except per share amounts) 2007 2006 Change
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Cash flow from operations(1) $ 68,783 $ 74,596 -8%
Per share - basic $ 0.53 $ 0.58 -10%
- diluted $ 0.52 $ 0.55 -5%
Net earnings $ 13,719 $ 38,002 -64%
Per share - basic $ 0.11 $ 0.30 -63%
- diluted $ 0.10 $ 0.28 -64%
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(1) Cash flow from operations represents net income before depletion and
depreciation, future income taxes, and other non-cash expenses.
Cash flow from operations for the first quarter of 2007 decreased from the comparative period in 2006 due largely to lower liquids production volumes and reduced natural gas prices. Additionally, the recent sale of two minor non-core properties has lowered production volumes, on average, by approximately 700 boe/d, a factor that has also negatively impacted our revenue and cash flow in the first quarter of 2007. However, cash flow increased 15% from the fourth quarter of 2006 primarily as a result of higher realized commodity prices and a 12% and 14% reduction in quarter over quarter operating costs and general and administrative costs, respectively.
Lower commodity prices reduced net earnings for the first quarter of 2007 as compared to the first quarter of 2006. Additionally, fluctuations in unrealized risk management activities, measured on a mark-to-market basis, further affected earnings. An unrealized loss of $17.3 million was recorded in the first quarter of 2007, as compared to an unrealized gain of $16.9 million recognized in the first quarter of 2006. The 2007 loss was partially offset by a $5.6 million unrealized foreign exchange gain associated with our U.S. denominated Senior Notes.
OPERATING EARNINGS
Operating earnings is a non-GAAP measure that adjusts net earnings by non-operating items that we believe reduce the comparability of our underlying financial performance between periods. The following reconciliation of operating earnings has been prepared to provide investors with information that is more comparable between periods.
Summary of Operating Earnings
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Three Months Ended March 31
($000s, except per share amounts) 2007 2006
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Net earnings, as reported $ 13,719 $ 38,002
Non-operational items, after tax
Unrealized foreign exchange (gain) loss (4,683) 296
Unrealized risk management (gain) loss 11,759 (10,854)
Stock-based compensation 1,539 1,532
Effect of tax rate changes on future income
tax liabilities (4,401) (6,573)
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Operating earnings $ 17,933 $ 22,403
Per share - basic $ 0.14 $ 0.18
- diluted $ 0.14 $ 0.17
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REVENUE
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Three Months Ended March 31 2007 2006 Change
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Average production
Natural gas (mmcf/d) 148 142 4%
Liquids (light oil & ngls) (bbls/d) 8,729 10,418 -16%
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Total (boe/d) 33,316 34,029 -2%
Benchmark prices
AECO ($/GJ)
Monthly index 7.07 $ 8.79 -20%
Daily index 7.00 $ 7.16 -2%
WTI (U.S.$/bbl) 58.12 $ 63.48 -8%
Edmonton Par ($/bbl) 67.13 $ 68.96 -3%
Realized prices
Natural gas ($/mcf) $ 7.24 $ 7.58 -4%
Liquids ($/bbl) 54.20 48.70 11%
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Total ($/boe) $ 46.98 $ 48.58 -3%
Revenue ($000s)
Natural gas $ 96,079 $ 96,582 -1%
Crude oil and ngls 44,798 52,197 -14%
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Total $140,877 $148,779 -5%
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Natural gas production rose by 4% on a year over year basis. This increase, however, was offset by reduced liquids volumes, primarily from our Cecil and Worsley oil properties, resulting in a 2% overall decrease in production when comparing the first quarters of 2006 and 2007.
We market our natural gas using both 30 day AECO indexed and daily AECO indexed contracts. Approximately 39% of our gas was sold on monthly evergreen contracts, and approximately 50% on indexed daily contracts. The remaining 11% of Compton's natural gas production remains committed to aggregator contracts, which received a price during the current quarter that was, on average, $0.99/mcf less than prices received on non-aggregator volumes.
ROYALTIES ------------------------------------------------------------------------- Three Months Ended March 31 2007 2006 ------------------------------------------------------------------------- Royalties ($000s) $ 28,646 $ 34,566 Percentage of revenues 20.3% 23.4% -------------------------------------------------------------------------
The Alberta royalty structure is based upon commodity prices and well productivity, with higher prices and well productivity attracting higher royalty rates. The decrease in the overall royalty rate was associated with lower prices experienced in the current quarter.
OPERATING EXPENSES ------------------------------------------------------------------------- Three Months Ended March 31 2007 2006 ------------------------------------------------------------------------- Operating expenses ($000s) $ 26,032 $ 21,884 Operating expenses per boe ($/boe) $ 8.68 $ 7.15 -------------------------------------------------------------------------
Prior to the first quarter of 2007, operating costs were reported net of incidental third party revenue from processing, compression, road use, water disposal, and other related items. Commencing with the first quarter of 2007, such amounts are included in revenue, and operating costs are reported excluding such recoveries. Prior period figures have been restated to reflect this reclassification.
Operating expenses for the first quarter of 2007 increased 19% over the first quarter of 2006 as a result of costs associated with accelerated activity throughout the oil and gas industry. On a quarter over quarter basis, our operating costs fell by $1.03/boe, or approximately 12%, due to lower liquids volumes, which attract higher operating costs, as well as our focused efforts to streamline operations.
TRANSPORTATION ------------------------------------------------------------------------- Three Months Ended March 31 2007 2006 ------------------------------------------------------------------------- Transportation costs ($000s) $ 2,482 $ 3,072 Transportation costs per boe ($/boe) $ 0.83 $ 1.00 ------------------------------------------------------------------------- Lower transportation costs in first three months of 2007 resulted from lower trucking costs associated with decreased crude oil production. GENERAL AND ADMINISTRATIVE EXPENSES ------------------------------------------------------------------------- Three Months Ended March 31 ($000s, except where noted) 2007 2006 ------------------------------------------------------------------------- General and administrative expenses $ 9,338 $ 9,617 Capitalized general and administrative expenses (2,165) (2,616) Operator recoveries (764) (613) ------------------------------------------------------------------------- Total general and administrative expenses $ 6,409 $ 6,388 General and administrative per boe ($/boe) $ 2.14 $ 2.09 ------------------------------------------------------------------------- General and administrative costs remained relatively constant on a year over year basis. However, general and administrative costs were reduced by 14% from the previous quarter as a result of a reversal of an over provision for certain year end expenses. INTEREST EXPENSE ------------------------------------------------------------------------- Three Months Ended March 31 ($000s, except where noted) 2007 2006 ------------------------------------------------------------------------- Interest on bank debt, net $ 5,209 $ 3,136 Interest on Senior Notes 10,445 6,796 ------------------------------------------------------------------------- Interest charges $ 15,654 $ 9,932 Finance charges (110) 427 ------------------------------------------------------------------------- Total interest and finance charges $ 15,544 $ 10,359 Total interest and finance charges per boe ($/boe) $ 5.18 $ 3.38 ------------------------------------------------------------------------- Weighted average annual debt ------------------------------------------------------------------------- Three months ended March 31 ($000s, except where noted) 2007 2006 ------------------------------------------------------------------------- Bank debt $327,444 $303,421 Effective interest rate 6.35% 4.93% Senior notes (US$) $437,932 $306,750 Effective interest rate 8.15% 7.76% -------------------------------------------------------------------------
Interest expenses relating to bank debt for the first three months of 2007 increased from the comparative prior year period as a result of increased borrowings incurred to fund our 2006 and 2007 drilling programs, as well as increases in short term interest rates.
The year over year increase in interest rates relating to our Senior Notes reflect the adoption on a prospective basis of Handbook Section 3855 "Financial Instruments" and the determination of interest expense using the effective interest rate method. This method equates interest expense to the yield on the Senior Notes after any reduction in the face value for costs of issue including any discount or premium.
DEPLETION AND DEPRECIATION ------------------------------------------------------------------------- Three Months Ended March 31 2007 2006 ------------------------------------------------------------------------- Depletion and depreciation ($000s) $ 38,794 $ 34,410 Depletion and depreciation per boe ($/boe) $ 12.94 $ 11.24 -------------------------------------------------------------------------
Strong commodity prices have accelerated capital programs and competition throughout the oil and gas industry, raising the demand for and costs of goods and services. This increase in costs is reflected in increased finding, development, and on-stream costs which in turn have resulted in an increase in depletion and depreciation rates in the current quarter in comparison to the prior comparative period and fourth quarter of 2006.
INCOME TAXES
Income taxes are recorded using the liability method of accounting. Future income taxes are calculated based on the difference between the accounting and income tax basis of an asset or liability. Note 11 in the financial statements details the calculation of the provision and the effective tax rate for the period. The classification of future income taxes between current and non-current is based upon the classification of the liabilities and assets to which the future income tax amounts relate. The classification of a future income tax amount as current does not imply a cash settlement of the amount within the following twelve month period.
RISK MANAGEMENT
Our financial results are impacted by external market risks associated with fluctuations in commodity prices, interest rates, and the Canadian/U.S. currency exchange rate. We use various financial instruments for non-trading purposes to manage and partially mitigate our exposure to these risks.
Financial instruments used to manage risk are subject to periodic settlements throughout the term of the instruments. Such settlements may result in a gain or loss which is recognized as a risk management gain or loss at the time of settlement. The mark-to-market value of an instrument outstanding at the end of a reporting period reflects the value of the instrument based upon market conditions existing as of that date. Any change in value from that determined at the end of the prior period is recognized as an unrealized risk management gain or loss.
Risk management gains and losses recognized in the quarter are summarized in the following table.
Risk Management Gains and Losses ------------------------------------------------------------------------- Three Months Ended March 31 ($000s) 2007 2006 ------------------------------------------------------------------------- Commodity contracts Realized (gain) $ (8,753) $ (1,986) Unrealized loss (gain) 16,486 (18,902) Cross currency interest rate swap Unrealized loss 838 1,747 Foreign currency contracts Realized (gain) - (23) Unrealized loss - 301 ------------------------------------------------------------------------- Total risk management loss (gain) $ 8,571 $(18,863) ------------------------------------------------------------------------- Realized (gain) $ (8,753) $ (2,009) Unrealized loss (gain) 17,324 (16,854) ------------------------------------------------------------------------- Total risk management loss (gain) $ 8,571 $(18,863) ------------------------------------------------------------------------- Outstanding Commodity Contracts The following table outlines commodity hedge contracts that are currently in place. ------------------------------------------------------------------------- Commodity Term Amount Average Price Index ------------------------------------------------------------------------- Natural gas Collar April 2007 - Oct. 2007 45,000 GJ/d $6.61 - $8.71 AECO Crude oil Collar Jan. 2007 - Dec. 2007 3,000 bbls/d U.S.$75.00 - $84.55 WTI ------------------------------------------------------------------------- CAPITAL EXPENDITURES ------------------------------------------------------------------------- Three Months Ended March 31 ($000s) 2007 % 2006 % ------------------------------------------------------------------------- Land and seismic $ 13,258 12% $ 24,959 15% Drilling and completions 64,468 61% 101,494 61% Production facilities and equipment 28,333 27% 39,898 24% ------------------------------------------------------------------------- Sub-total $106,059 100% 166,351 100% Property acquisitions (divestitures) net (45,261) 27,431 ------------------------------------------------------------------------- Sub-total 60,798 193,782 MPP 569 (353) ------------------------------------------------------------------------- Total capital expenditures $ 61,367 $193,429 -------------------------------------------------------------------------
Capital expenditures before acquisitions and divestitures for the three months ended March 31, 2007 decreased significantly from the comparative period in 2006, primarily as a result of a year over year decrease in drilling activity.
To assist in funding our capital programs, we entered into agreements for the divestiture of two minor non-operated properties prior to year end in 2006. Net proceeds of $45.9 million were received subsequent to December 31, 2006 and, as such, have been recognized in our first quarter 2007 financial statements. These funds will be redeployed in the ongoing development of our resource plays and we plan to continue this strategy of capital redeployment in the future.
LIQUIDITY AND CAPITAL RESOURCES
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As at March 31, As at Dec. 31,
($000s, except where noted) 2007 2006
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Working capital deficiency(1) $ 27,608 $ 21,163
Senior secured credit facilities 315,000 330,000
Senior term notes 504,891 524,385
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Total indebtedness $847,499 $875,548
Shareholders' equity $749,720 $734,124
Debt to cash flow from operations(1)(2) 3.3 3.4
Debt to book capitalization(1) 53% 54%
Debt to market capitalization(1) 36% 39%
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(1) Excludes unrealized risk management items net of related future
income taxes.
(2) Based on trailing 12 month cash flow from operations.
Our corporate debt is structured to provide us with financial flexibility. Of our existing debt, 60% consists of Senior Notes that are not due until 2013, giving us the ability to draw on our senior secured credit facilities to assist in funding our planned 2007 capital program. During the quarter, we adopted Handbook Section 3855 "Financial Instruments." As a result, certain costs of issue associated with the Senior Notes previously recorded as deferred financing charges are netted against the carrying value of the Senior Notes.
Our borrowing base is determined based upon year end reserves. With the increase in 2006 reserves over 2005, we anticipate the borrowing base will increase. We do not, however, expect to request an increase in our authorized credit facilities at this time. Currently we have authorized senior secured credit facilities of $500 million, of which $185 million remain available.
During the fourth quarter of 2006, we entered into agreements for the sale of two minor, non-core properties. The sale of these properties were recorded in 2007 concurrent with the closing of sales. The sale of additional non-core properties and certain major conventional oil properties remains a potential source of funds for the continued development of our overall natural gas resource play strategy.
We believe internally generated cash flow from operations, proceeds from property dispositions, and funds available through our expanded credit facilities will be more than sufficient to fund our planned 2007 capital program, while still maintaining an appropriate capital structure.
STRATEGIC DIRECTION FOR 2007
As outlined in Mr. Sapieha's President's Message presented in our 2006 Annual Report to Shareholders, our primary objective for 2007 is the continued development of our natural gas resource plays while setting the stage for accelerated drilling programs and production growth in 2008 and beyond. Our initial plans for 2007 were prepared giving full consideration to industry conditions existing in late 2006. These plans resulted in a relatively conservative 2007 budget, with emphasis placed on efficient operations and cost controls while setting the stage for expanded activities in 2008 and beyond.
Inustry conditions have changed significantly since we prepared our initial plans for 2007:
- natural gas prices have strengthened and, based upon fundamentals,
are expected to strengthen further;
- service sector costs are declining and operating efficiencies related
to reduced industry activity have begun to occur;
- technical and other personnel are more available; and
- opportunities for expansion, at reasonable costs, in our focus areas
are becoming available.
In relation to Compton itself:
- we are increasingly confident in our geological and geophysical
models and the repeatability of our drilling programs, evidenced by
our reserve growth achieved at very competitive costs;
- we have and are continuing to strengthen our technical teams and
staff complement and are moving forward with the development of
efficient control procedures and systems required for a manufacturing
and processing resource development model;
- future drilling and other services are being secured at much reduced
cost levels from 2006; and
- the receipt and in-house interpretation of seismic surveys conducted
in 2006 and early 2007, in southern Alberta and at Niton, have
assisted us in identifying an increasing number of excellent drill
locations. Currently in southern Alberta, we have identified and are
in the process of securing in excess of 256 well locations on our
Belly River/Edmonton play, well in excess of the 215 wells initially
planned for 2007.
We have always recognized the key to realizing on the value of our resource plays would be achieved through down-spacing and accelerated drilling programs necessary for production growth from unconventional and tight gas reservoirs. We also recognized such programs were dependent upon having the technical teams and systems in place to manage these programs. Additionally, commodity prices and the industry cost structure must be such that these programs would produce the desired economic returns.
We believe all the conditions, both from an industry point of view and the Company's development, are in place. Now is the time to accelerate our activities. Accordingly, we are now in the process of revising our short term plans and budget for the remainder of 2007 and developing a long term strategic plan for 2008 through 2010.
Integral to these plans are:
- an expanded drilling program for the second half of 2007 through the
addition of up to 100 drill wells, primarily in our southern Alberta
Belly River/Edmonton play and at Niton;
- divestiture of our Peace River Arch oil properties to strengthen our
balance sheet and provide the financial resources and flexibility
required for expanded drilling programs and other natural gas
resource play opportunities should they arise, with the divestitures
expected to close mid summer;
- the continued expansion of our technical teams including the
redeployment of personnel from the Peace River Arch to our focus
natural gas plays;
- the commencement of an expanded commodity hedge program to secure
downside price protection and reduce uncertainty in cash flow to fund
expanded capital programs.
We expect to have finalized our revised plans and budget for the remainder of 2007 by mid June. We will release the details of our revised budget, including planned capital expenditures and guidance relating to production and cash flow for 2007, together with a summary of our strategic plan for 2008 through 2010, following June 20th and 21st Board of Directors' meetings.
We are excited with our prospects for the remainder of 2007 and beyond. Given Compton's wealth of opportunities and evolving industry conditions, we believe now is the time to accelerate our activities.
ADDITIONAL DISCLOSURES
Changes in Accounting Policies
On January 1, 2007, the Company adopted the Canadian Institute of Chartered Accountants ("CICA") Handbook Section 1530, "Comprehensive Income", Handbook Section 3855, "Financial Instruments - Recognition and Measurement", Handbook Section 3865, "Hedges", and Handbook Section 1506, "Accounting Changes".
The adoption of these standards has had no significant impact on the Company's net earnings and no impact on cash flow. The effects of the implementation of the new standards are:
a) Comprehensive income
The new standard introduced the statements of comprehensive income
and accumulated other comprehensive income to temporarily provide for
gains, losses, and other amounts arising from changes in fair value
until they are realized and recorded in net earnings. The company has
determined that it had no comprehensive income nor accumulated other
comprehensive income for the period ended March 31, 2007.
b) Financial instruments
The financial instruments standard establishes recognition and
measurement criteria for financial assets, financial liabilities, and
derivatives. All financial instruments are required to be measured at
fair value on initial recognition of the instrument except in
specific circumstances. Measurement in subsequent periods depends on
whether the financial instrument has been classified as "held for
trading", "available for sale", "held to maturity", "loans and
receivables", or "other financial liabilities" as defined by the
standard.
Financial assets and financial liabilities "held for trading" are
measured at fair value with changes in those fair values recognized
in net earnings. Financial assets "available for sale" are measured
at fair value, with changes in those fair values recognized in other
comprehensive income. Financial assets "held to maturity", "loans and
receivables", and "other financial liabilities" are measured at
amortized cost using the effective interest method.
Cash and deposits, included in other current assets, are classified
as "held for trading" and are measured at carrying value, which
approximates fair value due to the short term nature of these
instruments. Investments included in other current assets are
designated as "held for trading", accounts receivable are classified
as "loans and receivables" and accounts payable, bank debt, and
senior term notes are classified as "other financial liabilities".
Transitional provisions are outlined in the financial instrument
standard and require prospective treatment without restatement of
prior periods. In addition, the provisions require that, upon
adoption at January 1, 2007, valuation adjustments, net of tax, are
recognized in the opening balance of retained earnings.
At January 1, 2007, the following transitional adjustments were
required.
- $14.0 million of deferred financing charges were reclassified as a
reduction of senior term notes to reflect the adopted policy of
capitalizing long term debt transaction costs, commissions,
premiums, and discounts within long term debt. The costs
capitalized will be amortized using the effective interest method.
Previously, the Company deferred these costs and amortized them
straight line over the life of the related senior term notes. The
adoption of this standard resulted in a $0.3 million net increase
to opening retained earnings.
- $3.97 million of deferred risk management loss, $2.7 million net,
previously recognized at January 1, 2004 upon initial adoption of
CICA Accounting Guideline 13, "Hedging Relationships" was
reclassified as a reduction to opening retained earnings.
- The fair value measurement of investments resulted in a
$1.1 million net increase to opening retained earnings.
c) Hedges
At January 1, 2007, the Company did not designate any of its risk
management activities as accounting hedges and as a result, the
adoption of this standard had no impact on the current period
consolidated financial statements.
d) Accounting changes
The adoption of Handbook Section 1506, "Accounting Changes" has had
no impact on the March 31, 2007 consolidated financial statements.
Changes in Internal Control over Financial Reporting
During the quarter ended March 31, 2007, we made two material changes to internal control over financial reporting. On March 1, 2007 we converted our production accounting and royalty management information systems. These changes were implemented to improve both operational efficiencies and internal controls. The conversion was not due to any identified internal control weaknesses. The implementations were subject to our change management procedures which are effective.
There were no other changes during the quarter ended March 31, 2007 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.
-------------------------------------------------------------------------
2007 2006 2005
Q1 Q4 Q3 Q2 Q1 Q4 Q3 Q2
-------------------------------------------------------------------------
Total revenue
(millions) $ 141 $ 130 $ 127 $ 135 $ 149 $ 185 $ 147 $ 124
Cash flow from
operations
(millions) $ 69 $ 55 $ 60 $ 67 $ 74 $ 90 $ 74 $ 62
Per share
- basic $ 0.53 $ 0.43 $ 0.47 $ 0.53 $ 0.58 $ 0.71 $ 0.58 $ 0.49
- diluted $ 0.52 $ 0.42 $ 0.45 $ 0.50 $ 0.55 $ 0.67 $ 0.56 $ 0.47
Net earnings
(millions) $ 14 $ (10)$ 31 $ 69 $ 38 $ 38 $ 11 $ 22
Per share
- basic $ 0.11 $(0.08)$ 0.24 $ 0.54 $ 0.30 $ 0.30 $ 0.09 $ 0.18
- diluted $ 0.10 $(0.08)$ 0.23 $ 0.51 $ 0.28 $ 0.28 $ 0.08 $ 0.17
Operating earnings
(millions) $ 18 $ 12 $ 13 $ 18 $ 22 $ 33 $ 26 $ 19
Production
Natural gas
(mmcf/d) 148 148 142 137 142 133 130 130
Liquids
(bbls/d) 8,729 8,600 9,249 9,821 10,418 8,879 7,351 7,249
-------------------------------------------------------------------------
Total (boe/d) 33,316 33,245 32,843 32,645 34,029 31,042 29,041 28,877
Average price
Natural gas
(mmcf/d) $ 7.24 $ 6.48 $ 5.38 $ 5.86 $ 7.58 $11.12 $ 8.41 $ 7.23
Liquids
(bbls/d) 54.20 48.44 57.53 59.41 48.70 58.39 65.20 54.63
-------------------------------------------------------------------------
Total ($/boe) $46.98 $42.60 $42.03 $45.37 $48.58 $64.58 $54.97 $47.05
-------------------------------------------------------------------------
In the first quarter of 2007, revenue and cash flow from operations increased from the fourth quarter of 2006 due to increased production and higher commodity prices. On a quarter over quarter basis, net earnings increased by approximately 180 percent 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.
ADVISORIES
Management's Discussion and Analysis ("MD&A") is intended to provide both an historical and prospective view of the Company's activities. The MD&A was prepared as at May 9, 2006 and should be read in conjunction with the interim unaudited consolidated financial statements for the three months ended March 31, 2007 and the audited consolidated financial statements and MD&A for the year ended December 31, 2006, available in printed form on request and posted on the Company's website.
Forward Looking Statements
Certain information regarding the Company contained herein constitutes forward looking statements under the meaning of applicable securities laws, including the United States Private Securities Litigation Reform Act of 1995. Forward looking statements include estimates, plans, expectations, opinions, forecasts, projections, guidance or other statements that are not statements of fact, including statements regarding (i) cash flow, production, capital expenditures, and planned wells in 2006, and (ii) other risks and uncertainties described from time to time in the reports and filings made by Compton with securities regulatory authorities. Although Compton believes that the expectations reflected in such forward looking statements are reasonable, it can give no assurance that such expectations will prove to have been correct. There are many factors that could cause forward looking statements not to be correct, including risks and uncertainties inherent in the Company business. These risks include, but are not limited to: crude oil and natural gas price volatility, exchange rate fluctuations, availability of services and supplies, operating hazards and mechanical failures, uncertainties in the estimates of reserves and in projections of future rates of production and timing of development expenditures, general economic conditions, the actions or inactions of third party operators and regulatory pronouncements. Compton may, as considered necessary in the circumstances, update or revise forward looking information, whether as a result of new information, future events, or otherwise. The Company's forward looking statements are expressly qualified in their entirety by this cautionary statement.
Non-GAAP Financial Measures
Included in the MD&A and elsewhere in this report are references to terms used in the oil and gas industry such as cash flow from operations, cash flow per share and operating earnings. These terms are not defined by GAAP in Canada and consequently are referred to as non-GAAP measures. Non-GAAP measures do not have any standardized meaning and therefore reported amounts may not be comparable to similarly titled measures reported by other companies.
Cash flow from operations should not be considered an alternative to, or more meaningful than, cash provided by operating, investing and financing activities or net earnings as determined in accordance with Canadian GAAP, as an indicator of the Company's performance or liquidity. Cash flow from operations is used by Compton to evaluate operating results and the Company's ability to generate cash to fund capital expenditures and repay debt.
Operating earnings represents net earnings excluding certain items that are largely non-operational in nature and should not be considered an alternative to, or more meaningful than, net earnings as determined in accordance with Canadian GAAP. Operating earnings is used by the Company to facilitate comparability of earnings between periods.
Use of BOE Equivalents
The oil and natural gas industry commonly expresses production volumes and reserves on a barrel of oil equivalent ("boe") basis whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. The intention is to sum oil and natural gas measurement units into one basis for improved measurement of results and comparisons with other industry participants. Compton has used the 6:1 boe measure which is the approximate energy equivalency of the two commodities at the burner tip. However, boe does not represent a value equivalency at the plant gate where Compton sells its production volumes and therefore may be a misleading measure if used in isolation.
Compton is an independent, public company actively engaged in the exploration, development, and production of natural gas, natural gas liquids, and crude oil in western Canada. Compton also controls and manages the operations of the Mazeppa Processing Partnership ("MPP"), which owns significant midstream assets critical to the Company's activities in southern Alberta. The accounts of MPP are consolidated in the Company's financial statements.
-------------------------------------------------------------------------
Compton Petroleum Corporation
Consolidated Balance Sheets
(thousands of dollars)
-------------------------------------------------------------------------
March 31, December 31,
2007 2006
----------- -----------
(unaudited)
Assets
Current
Cash $ 10,974 $ 11,876
Accounts receivable 87,076 83,535
Unrealized risk management gain (Note 12a) 6,139 22,625
Other current assets 28,539 24,869
Future income taxes 1,554 1,479
----------- -----------
134,282 144,384
Property and equipment 2,000,305 1,977,062
Goodwill 7,914 7,914
Deferred financing charges and other (Note 14) 169 14,144
Deferred risk management loss (Note 12c) - 3,968
----------- -----------
$2,142,670 $2,147,472
----------- -----------
----------- -----------
Liabilities
Current
Accounts payable $ 154,197 $ 141,443
Unrealized risk management loss (Note 12d) 5,093 4,604
Future income taxes 1,873 7,269
----------- -----------
161,163 153,316
Bank debt (Note 3) 315,000 330,000
Senior term notes (Note 4) 504,891 524,385
Asset retirement obligations (Note 6) 31,112 29,791
Unrealized risk management loss (Note 12d) 7,165 6,816
Future income taxes 307,874 302,690
Non-controlling interest (Note 7) 65,745 66,350
----------- -----------
1,392,950 1,413,348
----------- -----------
Shareholders' equity
Capital stock (Note 8) 234,343 231,992
Contributed surplus (Note 9a) 18,607 16,974
Retained earnings 496,770 485,158
----------- -----------
749,720 734,124
----------- -----------
$2,142,670 $2,147,472
----------- -----------
----------- -----------
See accompanying notes to the consolidated financial statements.
-------------------------------------------------------------------------
Compton Petroleum Corporation
Consolidated Statements of Earnings
(unaudited) (thousands of dollars, except per share amounts)
-------------------------------------------------------------------------
Three months ended March 31, 2007 2006
----------------------------------------------------------- -----------
Revenue
Oil and natural gas revenues $ 140,877 $ 148,779
Royalties (28,646) (34,566)
----------- -----------
112,231 114,213
----------- -----------
Expenses
Operating 26,032 21,884
Transportation 2,482 3,072
General and administrative 6,409 6,388
Interest and finance charges (Note 5) 15,544 10,359
Depletion and depreciation 38,794 34,410
Foreign exchange (gain) loss (Note 13) (5,522) 365
Accretion of asset retirement obligations 651 568
Stock-based compensation 3,266 2,379
Risk management (gain) loss (Note 12e) 8,571 (18,863)
----------- -----------
96,227 60,562
----------- -----------
Earnings before taxes and non-controlling
interest 16,004 53,651
----------- -----------
Income taxes (Note 11)
Current (13) 414
Future 610 13,720
----------- -----------
597 14,134
----------- -----------
Earnings before non-controlling interest 15,407 39,517
Non-controlling interest 1,688 1,515
----------- -----------
Net earnings $ 13,719 $ 38,002
----------- -----------
----------- -----------
Net earnings per share (Note 10)
Basic $ 0.11 $ 0.30
----------- -----------
----------- -----------
Diluted $ 0.10 $ 0.28
----------- -----------
----------- -----------
-------------------------------------------------------------------------
Compton Petroleum Corporation
Consolidated Statements of Retained Earnings
(unaudited) (thousands of dollars)
-------------------------------------------------------------------------
Three months ended March 31, 2007 2006
----------------------------------------------------------- -----------
Retained earnings, as previously reported $ 485,158 $ 360,719
Accounting policy adjustments (Note 2) (1,320) -
----------- -----------
Retained earnings, as restated 483,838 360,719
Net earnings 13,719 38,002
Premium on redemption of shares (Note 8) (787) (1,221)
----------- -----------
Retained earnings, end of period $ 496,770 $ 397,500
----------- -----------
----------- -----------
See accompanying notes to the consolidated financial statements.
-------------------------------------------------------------------------
Compton Petroleum Corporation
Consolidated Statements of Cash Flow
(unaudited) (thousands of dollars)
-------------------------------------------------------------------------
Three months ended March 31, 2007 2006
----------------------------------------------------------- -----------
Operating activities
Net earnings $ 13,719 $ 38,002
Amortization and other 511 424
Depletion and depreciation 38,794 34,410
Accretion of asset retirement obligations 651 568
Unrealized foreign exchange (gain) loss (5,580) 368
Future income taxes 610 13,720
Unrealized risk management (gain) loss 17,324 (16,854)
Stock-based compensation 2,267 2,379
Asset retirement expenditures (1,201) (936)
Non-controlling interest 1,688 1,515
----------- -----------
68,783 73,596
Change in non-cash working capital (6,671) 23,391
----------- -----------
62,112 96,987
----------- -----------
Financing activities
Issuance (repayment) of bank debt (15,000) 91,100
Proceeds from share issuances (net) 1,877 860
Distributions to partner (2,293) (2,292)
Redemption of common shares (946) (1,374)
Issue costs on senior notes - (281)
Change in non-cash working capital 10,924 (1,449)
----------- -----------
(5,438) 86,564
----------- -----------
Investing activities
Property and equipment additions (105,428) (165,662)
Property acquisitions - (27,531)
Property dispositions 45,261 700
Change in non-cash working capital 2,591 4,756
----------- -----------
(57,576) (187,737)
----------- -----------
Change in cash (902) (4,186)
Cash, beginning of period 11,876 8,598
----------- -----------
Cash, end of period $ 10,974 $ 4,412
----------- -----------
----------- -----------
See accompanying notes to the consolidated financial statements.
-------------------------------------------------------------------------
Compton Petroleum Corporation
Notes to the Consolidated Financial Statements
(unaudited) (Tabular amounts in thousands of dollars,
unless otherwise stated)
March 31, 2007
-------------------------------------------------------------------------
1. Basis of presentation
Compton Petroleum Corporation (the "Company") 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 in accordance with Accounting Guideline 15 ("AcG-15"),
Consolidation of Variable Interest Entities, as outlined in Note 7.
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, 2006. 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, 2006 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, 2007, the Company adopted the Canadian Institute of
Chartered Accountants ("CICA") Handbook Section 1530, "Comprehensive
Income", Handbook Section 3855, "Financial Instruments - Recognition
and Measurement" Handbook Section 3861, "Financial Instruments -
Disclosure and Presentation", Handbook Section 3865, "Hedges", and
Handbook Section 1506, "Accounting Changes".
The adoption of these standards has had no significant impact on the
Company's net earnings or cash flows. The effects of the
implementation of the new standards are discussed below.
e) Comprehensive income
The new standard introduced the statements of comprehensive income
and accumulated other comprehensive income to temporarily provide
for gains, losses and other amounts arising from changes in fair
value until they are realized and recorded in net earnings. The
company has determined that it had no comprehensive income nor
accumulated other comprehensive income for the period ended
March 31, 2007.
f) Financial instruments
The financial instruments standard establishes recognition and
measurement criteria for financial assets, financial liabilities
and derivatives. All financial instruments are required to be
measured at fair value on initial recognition of the instrument
except in specific circumstances. Measurement in subsequent
periods depends on whether the financial instrument has been
classified as "held for trading", "available for sale", "held to
maturity", "loans and receivables" or "other financial
liabilities" as defined by the standard.
Financial assets and financial liabilities "held for trading" are
measured at fair value with changes in those fair values
recognized in net earnings. Financial assets "available for sale"
are measured at fair value, with changes in those fair values
recognized in other comprehensive income. Financial assets "held
to maturity", "loans and receivables" and "other financial
liabilities" are measured at amortized cost using the effective
interest method.
Cash and deposits, included in other current assets, are
classified as "held for trading" and are measured at carrying
value, which approximates fair value due to the short term nature
of these instruments. Investments included in other current assets
are designated as "held for trading", accounts receivable are
classified as "loans and receivables" and accounts payable, bank
debt and senior term notes are classified as "other financial
liabilities".
Transitional provisions are outlined in the financial instrument
standard and require retroactive adjustment without restatement of
prior periods. In addition, the provisions require that, upon
adoption at January 1, 2007, transitional adjustments, net of tax,
are recognized in the opening balance of retained earnings.
At January 1, 2007, the following transitional adjustments were
required.
- $14.0 million of deferred financing charges were reclassified
as a reduction of senior term notes to reflect the adopted
policy of netting long term debt transaction costs within long
term debt. The costs capitalized will be amortized using the
effective interest method. Previously, the Company deferred
these costs and amortized them straight line over the life of
the related senior term notes. The adoption of this standard
resulted in a $0.3 million net increase to opening retained
earnings.
- $3.97 million of deferred risk management loss, $2.7 million
net, previously recognized at January 1, 2004 upon initial
adoption of CICA Accounting Guideline 13, "Hedging
Relationships" was reclassified as a reduction to opening
retained earnings.
- The fair value measurement of investments resulted in a
$1.1 million net increase to opening retained earnings.
Net effect on opening retained earnings as a result of the
transitional provisions is as follows:
Deferred financing charge adjustments $ 318
Deferred risk management loss $ (2,743)
January 1, 2007 fair value of investments $ 1,105
---------
Total adjustment to opening retained earnings $ (1,320)
---------
---------
g) Hedges
At January 1, 2007, the Company did not designate any of its risk
management activities as accounting hedges and as a result, the
adoption of this standard had no impact on the current period
consolidated financial statements.
h) Accounting changes
The adoption of Handbook Section 1506, "Accounting Changes" has
had no impact on the March 31, 2007 consolidated financial
statements.
3. Credit facilities
March 31, December 31,
2007 2006
------------ ------------
Authorized $ 500,000 $ 500,000
------------ ------------
------------ ------------
Prime rate $ 45,000 $ 35,000
Bankers' acceptance 270,000 295,000
------------ ------------
Utilized $ 315,000 $ 330,000
------------ ------------
------------ ------------
As at March 31, 2007, the Company had arranged authorized senior
credit facilities with a syndicate of banks in the amount of
$500 million. Advances under the facilities can be drawn and
currently bear interest as follows:
Prime rate plus 0.95%
Bankers' Acceptance rate plus 1.95%
LIBOR rate plus 1.95%
Margins are determined based on the ratio of total consolidated debt
to consolidated cash flow. The facilities reach term on July 4, 2007,
and, if not renewed, will mature 366 days later on July 4, 2008.
These facilities are currently under review by the Company's banking
syndicate and are expected to be renewed under similar terms and
conditions.
The senior credit facilities are secured by a first fixed and
floating charge debenture in the amount of $1.0 billion covering all
the Company's assets and undertakings.
4. Senior term notes
March 31, December 31,
2007 2006
------------ ------------
Senior term notes
U.S.$450 million, 7.625% due
December 1, 2013 $ 518,805 $ 524,385
Unamortized transaction costs (13,914) -
------------ ------------
Carrying Value $ 504,891 $ 524,385
------------ ------------
------------ ------------
On November 22, 2005 a wholly owned subsidiary of the Company issued
US$300 million senior term notes maturing December 1, 2013. On
April 4, 2006 an additional US$150 million was issued under the same
terms and conditions as the original issue. The notes bear interest
at 7.625% and are subordinate to the Company's bank credit
facilities. The yield to maturity, using the effective interest rate,
was 8.15% as at March 31, 2007.
The notes are not redeemable by the Company prior to December 1,
2009, except in limited circumstances. After that time, they can be
redeemed in whole or part, at the rates indicated below:
December 1, 2009 103.813%
December 1, 2010 101.906%
December 1, 2011 and thereafter 100.000%
Pursuant to the adoption of Handbook Section 3861, "Financial
Instruments - Disclosure and Presentation", transaction costs
relating to the issue of the senior term notes reduces the face value
of the notes as discussed in Note 2.
5. Interest and finance charges
Amounts charged to interest expense during the period ended are:
Three months ended March 31, 2007 2006
------------------------------------------------------- ------------
Interest on bank debt, net $ 5,209 $ 3,136
Interest on senior term notes 10,445 6,796
Finance charges (110) 427
------------ ------------
$ 15,544 $ 10,359
------------ ------------
------------ ------------
Finance charges include the amortization of deferred issue costs and
other interest expense net of interest revenue from cash management
activities.
6. Asset retirement obligations
The following table presents a reconciliation of the beginning and
ending aggregate carrying amount of the obligations associated with
the retirement of oil and gas assets:
March 31, December 31,
2007 2006
------------ ------------
Asset retirement obligations, beginning
of period $ 29,791 $ 20,770
Liabilities incurred 1,014 7,031
Liabilities settled and disposed (344) (267)
Accretion expense 651 2,257
------------ ------------
Asset retirement obligations, end
of period $ 31,112 $ 29,791
------------ ------------
------------ ------------
7. Non-controlling interest
Mazeppa Processing Partnership ("MPP" or "the Partnership") is a
limited partnership organized under the laws of the province of
Alberta and owns certain midstream facilities, including gas plants
and pipelines in Southern Alberta. The Company processes a
significant portion of its production from the area through these
facilities pursuant to a processing agreement with MPP. The Company
does not have an ownership position in MPP, however, the Company,
through a management agreement, manages the activities of MPP and is
considered to be the primary beneficiary of MPP's operations.
Pursuant to AcG-15, these consolidated financial statements include
the assets, liabilities and operations of the Partnership. Equity in
the Partnership, attributable to the partners of MPP, is recorded on
consolidation as a non-controlling interest and is comprised of the
following:
March 31, December 31,
2007 2006
------------ ------------
Non-controlling interest, beginning
of period $ 66,350 $ 68,898
Earnings attributable to non-controlling
interest 1,688 6,623
Distributions to limited partner (2,293) (9,171)
------------ ------------
Non-controlling interest, end of period $ 65,745 $ 66,350
------------ ------------
------------ ------------
MPP has guaranteed payment of certain obligations of its limited
partner under a credit agreement between the limited partner and a
syndicate of lenders. The maximum liability of the Partnership under
the guarantee is limited to amounts due and payable to MPP by the
Company pursuant to the processing agreement. The processing
agreement has a five year term ending April 1, 2009, at which time
Compton may renew the agreement, purchase the Partnership units or
allow the sale of the Partnership units to a third party. The maximum
liability at March 31, 2007 is $19.1 million. The Company has
determined that its exposure to loss under these arrangements is
minimal, if any.
8. Capital stock
Issued and outstanding
March 31, 2007 December 31, 2006
------------------------- -------------------------
Number Number
of shares Amount of shares Amount
----------- ----------- ----------- -----------
(000s) (000s)
Common shares
outstanding,
beginning of period 128,503 $ 231,992 127,263 $ 226,444
Shares issued under
stock option plan 649 2,510 1,489 5,993
Shares repurchased (88) (159) (249) (445)
----------- ----------- ----------- -----------
Common shares
outstanding,
end of period 129,064 $ 234,343 128,503 $ 231,992
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
The Company maintains a Normal Course Issuer Bid program on an annual
basis. Under the current program, the Company may purchase for
cancellation up to 6,000,000 of its common shares, representing
approximately 5.0% of the issued and outstanding common shares at the
time the bid received regulatory approval. During the three months
ended March 31, 2007 the Company purchased for cancellation 88,300
common shares at an average price of $10.71 per share (December 31,
2006 - 248,900 shares at an average price of $13.79 per share)
pursuant to the normal course issuer bid. The excess of the purchase
price over book value has been charged to retained earnings.
9. Stock-based compensation plans
a) Stock option plan
The Company has a stock option plan for employees, including
Directors and Officers. The exercise price of each option
approximated the market price for the common shares on the date
the option was granted. Options granted under the plan before
June 1, 2003 are generally fully exercisable after four years and
expire ten years after the grant date. Options granted under the
plan after June 1, 2003 are generally fully exercisable after four
years and expire five years after the grant date.
The following tables summarize the information relating to stock
options:
March 31, 2007 December 31, 2006
------------------ ------------------
Weighted Weighted
average average
Stock exercise Stock exercise
Options price Options price
--------- --------- --------- ---------
(000s) (000s)
Outstanding, beginning of period 11,611 $ 7.79 11,446 $ 6.13
Granted 1,403 $11.42 2,228 $13.99
Exercised (649) $ 2.89 (1,489) $ 3.14
Cancelled (134) $11.72 (574) $10.92
--------- --------- --------- ---------
Outstanding, end of period 12,231 $ 8.42 11,611 $ 7.79
--------- --------- --------- ---------
--------- --------- --------- ---------
Exercisable, end of period 6,815 $ 5.84 6,593 $ 4.82
--------- --------- --------- ---------
--------- --------- --------- ---------
The range of exercise prices of stock options outstanding and
exercisable at March 31, 2007 is as follows:
Outstanding Options Exercisable Options
----------------------------------- ---------------------
Weighted
average
remaining Weighted Weighted
Range of Number of contractual average Number of average
exercise options life exercise options exercise
prices outstanding (years) price outstanding price
--------------------------- ----------- -------- ----------- --------
(000s) (000s)
$1.25 - $3.99 2,776 3.3 $ 2.67 2,776 $ 2.67
$4.00 - $6.99 2,176 3.5 $ 4.92 1,919 $ 4.82
$7.00 - $9.99 1,262 2.3 $ 7.73 724 $ 7.60
$10.00 - $11.99 2,806 4.1 $11.22 407 $10.91
$12.00 - $13.99 1,733 3.3 $12.67 624 $12.54
$14.00 - $18.39 1,478 3.9 $14.67 365 $14.66
----------- ----------- -------- ----------- --------
12,231 3.5 $ 8.42 6,815 $ 5.84
----------- ----------- -------- ----------- --------
----------- ----------- -------- ----------- --------
The Company has recorded stock-based compensation expense in the
consolidated statement of earnings for stock options granted to
employees, Directors and Officers after January 1, 2003 using the
fair value method.
The fair value of each option granted is estimated on the date of
grant using the Black-Scholes option pricing model with weighted
average assumptions for grants as follows:
------------------------------------------------------------------
Three months ended March 31, 2007 2006
------------------------------------------------------------------
------------------------------------------------------------------
Weighted average fair value of options
granted $ 4.25 $ 7.55
------------------------------------------------------------------
Risk-free interest rate 4.0% 4.0%
------------------------------------------------------------------
Expected life (years) 5.0 5.0
------------------------------------------------------------------
Expected volatility 39.3% 44.0%
------------------------------------------------------------------
The following table presents the reconciliation of contributed
surplus with respect to stock-based compensation:
March 31, December 31,
2007 2006
------------ ------------
Contributed surplus, beginning of year $ 16,974 $ 9,173
Stock-based compensation expense 2,267 9,121
Stock options exercised (634) (1,320)
------------ ------------
Contributed surplus, end of period $ 18,607 $ 16,974
------------ ------------
------------ ------------
b) Share appreciation rights plan
CICA Handbook section 3870 requires recognition of compensation
costs with respect to changes in the intrinsic value for the
variable component of fixed share appreciation rights ("SARs").
During the periods ended March 31, 2007 and 2006, 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 $1.2 million, which is included
in accounts payable as at March 31, 2007 (December 31, 2006 -
$1.2 million). All outstanding SARs having a variable component
expire at various times through 2011.
c) Employee retention program
In recognition of the shortage of qualified personnel that
currently exists within the industry, the Company implemented an
Employee Retention program in July 2006 for its existing
employees, excluding Officers and Directors. Under the program and
contingent upon various conditions present as at July 1, 2007, the
Company may incur additional compensation costs to a maximum
amount of $4.0 million. During the three months ended March 31,
2007 an additional $1.0 million was recorded in stock-based
compensation expense as a partial recognition of this potential
liability. Combined with the $1.4 million recognized in 2006 the
total accrual at March 31, 2007 was $2.4 million. Any amount
payable under the program will be paid on July 1, 2007 at which
time the final amount will be fully determinable.
10. Per share amounts
The following table summarizes the common shares used in calculating
net earnings per common share:
Three months ended March 31, 2007 2006
------------------------------------------------------- ------------
(000s) (000s)
Weighted average common shares outstanding
- basic 128,570 127,300
Effect of stock options 4,074 7,268
------------ ------------
Weighted average common shares outstanding
- diluted 132,644 134,568
------------ ------------
------------ ------------
11. Income taxes
The following table reconciles income taxes calculated at the
Canadian statutory rates with actual income taxes:
Three months ended March 31, 2007 2006
------------------------------------------------------- ------------
Earnings before taxes and non-controlling
interest $ 16,004 $ 53,651
------------ ------------
Canadian statutory rates 32.1% 35.6%
Expected income taxes $ 5,137 $ 19,100
Effect on taxes resulting from:
Non-deductible Crown charges - 673
Resource allowance - (289)
Non-deductible stock-based compensation 728 848
Federal capital tax - 401
Effect of tax rate changes (4,401) (6,573)
Non-taxable portion of foreign exchange
(gain) loss (896) 66
Other 29 (92)
------------ ------------
Provision for income taxes $ 597 $ 14,134
------------ ------------
Current
Income taxes $ (13) $ 13
Federal capital tax - 401
Future 610 13,720
------------ ------------
$ 597 $ 14,134
------------ ------------
------------ ------------
Effective tax rate 3.7% 26.3%
------------ ------------
------------ ------------
12. Financial instruments
Derivative financial instruments and risk management activities
The Company is exposed to risks from fluctuations in commodity
prices, interest rates and Canada/US currency exchange rates. The
Company utilizes various derivative financial instruments for non-
trading purposes to manage and mitigate its exposure to these risks.
Effective January 1, 2004, the Company elected to account for all
derivative financial instruments using the mark-to-market method.
Risk management activities during the period, utilizing derivative
instruments, relate to commodity price hedges, foreign currency swaps
and cross currency interest rate swap arrangements and are summarized
below:
a) Commodity price hedges
The commodity hedge contracts entered into are forward
transactions providing the Company with a range of prices on the
commodities sold. Outstanding hedge contracts and the associated
unrealized, mark-to-market, gains or losses, at March 31, 2007
are:
Daily Mark-to-
Notional Market
Commodity Term Volume Prices Received Gain (Loss)
--------- ---- ------ --------------- -----------
Natural gas Apr. 07 - $6.94/mcf -
Collar Oct. 07 42,857 mcf $9.14/mcf $ (1,036)
Crude oil Jan. 07 - US$75.00/bbl -
Collar Dec. 07 3,000 bbls US$84.55/bbl 7,175
-----------
Unrealized risk management gain $ 6,139
-----------
-----------
At December 31, 2006, the unrealized risk management gain on
outstanding commodity contracts was $22.6 million.
b) Foreign currency risk management
The Company is exposed to fluctuations in the exchange rate
between the Canadian dollar and U.S. dollar and when appropriate,
enters into agreements to fix the exchange rate in order to manage
the risk. At period end the Company had no outstanding contracts.
c) Deferred risk management loss
As at January 1, 2004, the Company recorded a liability and a
deferred risk management loss of $10.9 million relating to then
outstanding commodity hedges and the interest rate swap. The
deferred loss was amortized to earnings until December 31, 2006.
Upon adoption of Handbook Section 3855, "Financial Instruments -
Recognition and Measurement" the balance of the deferred risk
management loss, net of tax, was charged to opening retained
earnings as at January 1, 2007.
d) Cross currency interest rate swap
In 2002, the Company entered into interest rate swap arrangements,
expiring May 2009 that convert fixed rate U.S. dollar denominated
interest obligations into floating rate Canadian dollar
denominated interest obligations. At March 31, 2007, the Company
valued the liability relating to future unrealized losses on the
swap arrangements to be $12.3 million (December 31, 2006 -
$11.4 million) on a mark-to-market basis. The current portion of
this amount at March 31, 2007 is $5.1 million (December 31, 2006 -
$4.6 million).
e) Risk management (gain) loss
The following table summarizes (gains) and losses recognized
during the year relating to the foregoing:
March 31,
-------------------------------------------------------------------------
Commodity Interest 2007 2006
Contracts Rate Swap Total Total
----------------------------------------------------------- --------
Unrealized
Amortization of
deferred loss $ - $ - $ - $ 411
Change in fair value 16,486 838 17,324 (17,265)
----------------------------------------------------------- --------
16,486 838 17,324 (16,854)
Realized
Cash settlements (8,753) - (8,753) (2,009)
----------------------------------------------------------- --------
Total $ 7,733 $ 838 $ 8,571 $ (18,863)
----------------------------------------------------------- --------
13. Foreign exchange (gain) loss
Amounts charged to foreign exchange (gain) loss during the period
ended as follows:
Three months ended March 31, 2007 2006
----------------------------------------------------------- --------
Foreign exchange on translation of
U.S.$ debt $ (5,580) $ 368
Other foreign exchange 58 (3)
----------------------------------------------------------- --------
Total (gain) loss $ (5,522) $ 365
----------------------------------------------------------- --------
14. Deferred financing charges and other
March 31, December 31,
2007 2006
------------ ------------
Deferred financing charges $ - $ 14,008
Other 169 136
------------ ------------
$ 169 $ 14,144
------------ ------------
------------ ------------
At January 1, 2007 the balance in deferred financing charges has been
re-classified as a reduction of senior term notes according to the
new accounting standards outlined in Handbook Section 3855 "Financial
Instruments - Recognition and Measurement" and discussed in Note 2.
Prior periods have not been restated as defined in the transitional
provisions.
15. Supplemental cash flow information
Amounts actually paid during the period relating to interest expense
and capital taxes are as follows:
Three months ended March 31, 2007 2006
----------------------------------------------------------- ------------
Interest paid $ 4,181 $ 1,671
Taxes paid - 180
------------ ------------
$ 4,181 $ 1,851
------------ ------------
------------ ------------
16. Reclassification
Certain amounts disclosed for prior years have been reclassified to
conform with current period presentation.
CONFERENCE CALL
Compton will be conducting a conference call and audio webcast May 10, 2007 at 9:30 a.m. (MST) or 11:30 a.m. (EST) to discuss the Company's 2007 first quarter financial and operating results. To participate in the conference call, please contact the Conference Operator at 9:20 a.m. (MST), ten minutes prior to the call.
Conference Operator Dial-in Number: 416-915-5761 or toll-free
1-800-814-4861.
Audio webcast URL: http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID(equal sign)1850860
The audio replay will be available two hours after the conclusion of the conference call and will be accessible until May 18, 2007. Callers may dial toll-free 1-877-289-8525 and enter access code 21228639 (followed by the pound key).
Compton Petroleum Corporation is a Calgary-based public company actively engaged in the exploration, development, and production of natural gas, natural gas liquids, and crude oil in the Western Canada Sedimentary Basin. Compton's shares are listed on the Toronto Stock Exchange under the symbol CMT and on the New York Stock Exchange under the symbol CMZ.
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