CALGARY, May 12 /PRNewswire-FirstCall/ -- Compton Petroleum Corporation ("Compton" or the "Company") is pleased to announce its financial and operating results for the quarter ended March 31, 2008.
HIGHLIGHTS - FIRST QUARTER 2008
- Drilled 99 wells with a 96% success rate.
- Natural gas production of 170 mmcf/d, up 15% from first quarter 2007.
- Total first quarter 2008 production averaged 33,274 boe/d.
- Revenue of $162 million, up 15% from first quarter 2007.
- Realized prices of $53.64/boe, up 14% from first quarter 2007.
- Adjusted cash flow from operations of $69 million.
- Capital expenditures of $101 million, before acquisitions and
divestitures.
FINANCIAL SUMMARY
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Three Months Ended March 31
($000s, except per share amounts) 2008 2007 Change
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Gross revenue $162,433 $140,877 15%
Adjusted cash flow from operations(1) $ 69,322 $ 68,783 1%
Per share - basic(1) $ 0.54 $ 0.53 2%
- diluted(1) $ 0.52 $ 0.52 0%
Adjusted net earnings from operations(1) $ 17,404 $ 17,933 -3%
Per share - basic(1) $ 0.13 $ 0.14 -7%
- diluted(1) $ 0.13 $ 0.14 -7%
Net earnings $ 1,619 $ 13,719 -88%
Per share - basic $ 0.01 $ 0.11 -91%
- diluted $ 0.01 $ 0.10 -90%
Capital expenditures
(before acquisitions & divestitures) $100,948 $106,059 -5%
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(1) See cautionary statements at the beginning of Management's Discussion
and Analysis.
OPERATING SUMMARY
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Three Months Ended March 31 2008 2007 Change
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Average production
Natural gas (mmcf/d) 170 148 15%
Liquids (bbls/d) 5,009 8,729 -43%
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Total (boe/d) 33,274 33,316 0%
Realized prices
Natural gas ($/mcf) $ 7.48 $ 7.24 3%
Liquids ($/bbl) 94.97 54.20 62%
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Total ($/boe) $ 53.64 $ 46.98 14%
Field netback ($/boe) $ 41.06 $ 30.84 33%
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OPERATIONS REVIEW
Drilling Summary
Compton experienced an active first quarter in 2008. We drilled 99 wells with a 96% success rate. Of the 99 wells drilled during the quarter, 97 were classified as development wells and 2 as exploratory wells. The following table summarizes drilling results to March 31, 2008.
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Gas Oil D&A Total Net Success
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Southern Alberta 50 1 3 54 51 94%
Central Alberta 37 3 1 41 18 98%
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Standing, cased wells 4 4
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Total 87 4 4 99 73 96%
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DEEP BASIN GAS
Compton has two Deep Basin deep gas plays: the Basal Quartz sands at Hooker and the Gething/Rock Creek sands at Niton and Caroline in central Alberta.
Southern Alberta: Hooker
In the first three months of 2008, we drilled one well targeting the Basal Quartz at our Hooker natural gas resource play. The well at 9-17-17-29W4 was drilled with a 700 metre horizontal leg and was placed on production March 10, 2008. Initial production was approximately 5 mmcf/d, and the well is currently producing approximately 2.2 mmcf/d. Of significance is the fact that two offset vertical wells have shown minimal pressure interference from the new horizontal well. Both of the offset wells are within 800 meters of 9-17 and one has been on production since 2000 and has produced 4.7 bcf. This supports our reservoir models and the requirement for additional wells to recover the reserves from the Basal Quartz. The 9-17 well also supports the premise that horizontal well technology can be effectively used to access productivity from tighter rock on the periphery of the play.
Subsequent to quarter end, Compton has rig-released a second horizontal well at 15-30-16-29W4 and completed a multi stage frac on the well on April 25, 2008. The well is currently flowing back to the gas plant on cleanup at 2.5 mmcf/d. We are optimistic that the horizontal drill and completion technique is an important technical step forward in the development of the large known gas reserves existing on the periphery of this play. Two additional horizontal wells have been licensed and will spud once spring break-up road conditions permit.
The existing Basal Quartz play, as currently delineated, extends over four townships where Compton has an average working interest of approximately 85%. Infrastructure necessary to accommodate the accelerated production growth and development of this play is largely in place. Assuming continued horizontal drilling success at Hooker, Compton estimates there are in excess of 100 potential horizontal locations on Compton lands.
Central Alberta: Niton and Caroline
At our Niton and Caroline resource plays we drilled 15 wells in the first quarter of 2008, five of which were horizontal wells. All wells were successful and immediate follow-up locations are now being acquired.
The horizontal well at 4-27-52-17W5 at Niton in central Alberta, referred to in our news release of March 6, 2008, was placed on continuous production on March 28th. The well came on production at 9 mmcf/d and is expected to exhibit a typical tight gas well production profile. Including the 4-27 well, Compton has five horizontal wells in township 52-17W5 with a sixth well currently drilling. Production from these wells is facility constrained with only 4-27 currently producing. Pipeline and compression facilities are being installed and are expected to be operational by mid to late May. These facilities will accommodate all wells in the 11 well program planned for township 52-17W5.
During the previous week Compton rig released three horizontal wells in the Niton area. The rigs were drilling in three separate townships targeting the Rock Creek formation following-up on the successes in townships 53-15W5 and 52-17W5. Compton has 272 gross sections of land in the Niton area and, based upon results to date, the Company has the potential for over 300 Ellerslie and Rock Creek horizontal drilling locations on Compton lands in the area.
With the success that Compton has experienced drilling horizontal wells into the Basal Quartz at our southern Alberta Hooker resource play, we will be drilling horizontal wells in the geologically similar Gething Sands at Niton, spudding our first well in the second half of this year.
At Bigoray, the 00/04-30-051-09W5/2 well watered out in the Spirit River zone. The uphole completion was previously a high rate gas zone that proved to be limited. The original well bore event continues to produce successfully from the Ellerslie.
Foothills
In the foothills at Cowley, we will drill two horizontal multi stage frac wells during the second quarter of 2008. We have identified and are moving to license three more wells in this area.
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.
SHALLOW GAS
The Plains Belly River and overlying Edmonton Horseshoe Canyon shallow gas zones cover more than 1,200 sections of Compton held land in southern Alberta. The entire 900 metre gas-charged section is comprised of multiple Belly River sands, silts, and shales, overlain by the Edmonton/Horseshoe Canyon coals that similarly include sands, silts, and shales. Going forward, we will focus on downspacing, development drilling, and recompletions in order to establish a resource manufacturing and processing model designed to maximize production and capital efficiency.
Plains Belly River and Edmonton Coal Bed Methane
We drilled 55 Belly River wells in the first quarter, two of which were horizontal. Pending the outcome of our horizontal wells drilled in this area, we delayed drilling an additional 20 wells initially planned for the quarter. We are currently testing the horizontal wells and believe it will take 10 additional Belly River horizontal wells to fully determine the effectiveness of this drilling technique on this play type. We are in the process of acquiring surface locations for these wells.
As we move into the second quarter of 2008, we have continued to be active in southern Alberta despite the occurrence of spring break-up in most areas. In April, we drilled six Belly River wells, all of which were successful.
MANAGEMENT'S DISCUSSION AND ANALYSIS
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Management's Discussion and Analysis ("MD&A") is intended to provide both a historical and prospective view of our activities. The MD&A was prepared as at May 9, 2008 and should be read in conjunction with the interim unaudited consolidated financial statements for the three months ended March 31, 2008 and the audited consolidated financial statements for the year ended December 31, 2007, 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 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 adjusted cash flow from operations, cash flow per share, adjusted net earnings from operations, adjusted EBITDA, and enterprise value. These terms are not defined by GAAP in Canada and consequently are referred to as non-GAAP measures. Non-GAAP measures do not have any standardized meaning and therefore reported amounts may not be comparable to similarly titled measures reported by other companies.
Adjusted 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. Adjusted 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.
Adjusted net earnings from operations represents net earnings excluding certain items that are largely non-operational in nature and should not be considered an alternative to, or more meaningful than, net earnings as determined in accordance with Canadian GAAP. Adjusted net earnings from operations is used by the Company to facilitate comparability of earnings between periods.
Use of BOE Equivalents
The oil and natural gas industry commonly expresses production volumes and reserves on a barrel of oil equivalent ("boe") basis whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. The intention is to sum oil and natural gas measurement units into one basis for improved measurement of results and comparisons with other industry participants. Compton has used the 6:1 boe measure which is the approximate energy equivalency of the two commodities at the burner tip. However, boe does not represent a value equivalency at the plant gate where Compton sells its production volumes and therefore may be a misleading measure if used in isolation.
EXECUTIVE SUMMARY
- First quarter 2008 natural gas production of 170 mmcf/d, a 15% year
over year increase.
- Total first quarter 2008 production averaged 33,274 boe/d. While
consistent with a year ago, the 2008 period reflects the major oil
property disposition in September 2007.
- Adjusted cash flow from operations of $69 million.
- Adjusted net earnings from operations of $17.4, comparable to the
first quarter of 2007 and an increase of $20.4 million over the last
quarter of 2007 as a result of higher overall commodity prices.
RESULTS OF OPERATIONS
Adjusted cash flow from operations is a non-GAAP term that represents net earnings adjusted for non-cash items. We consider adjusted cash flow from operations to be a key financial measure as it demonstrates our ability to generate the cash flow necessary to fund future growth through capital investment. Adjusted cash flow from operations may not be comparable to similar measures presented by other companies.
Adjusted cash flow from operations and Net Earnings
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Three Months Ended March 31
($000s, except per share amounts) 2008 2007 Change
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Adjusted cash flow from operations $ 69,322 $ 68,783 1%
Per share - basic $ 0.54 $ 0.53 2%
- diluted $ 0.52 $ 0.52 0%
Net earnings $ 1,619 $ 13,719 -88%
Per share - basic $ 0.01 $ 0.11 -91%
- diluted $ 0.01 $ 0.10 -90%
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The following table reconciles net earnings to adjusted cash flow from operations:
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Three months ended March 31, 2008 2007
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Operating activities
Net earnings $ 1,619 $ 13,719
Amortization and other (107) 511
Depletion and depreciation 41,807 38,794
Accretion of asset retirement obligations 812 651
Unrealized foreign exchange (gain) loss 17,910 (5,580)
Future income taxes 3,286 610
Unrealized risk management (gain) loss 773 17,324
Stock-based compensation 2,249 2,267
Asset retirement expenditures (940) (1,201)
Non-controlling interest 1,913 1,688
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Adjusted cash flow from operations $ 69,322 $ 68,783
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ADJUSTED NET EARNINGS FROM OPERATIONS
Adjusted net earnings from operations 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 adjusted net earnings from operations has been prepared to provide investors with information that is more comparable between periods.
Summary of Adjusted net earnings from operations(1)
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Three Months Ended March 31
($000s, except per share amounts) 2008 2007
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Net earnings, as reported $ 1,619 $ 13,719
Non-operational items, after tax
Unrealized foreign exchange (gain) loss 15,268 (4,683)
Unrealized risk management (gain) loss 543 11,759
Stock-based compensation(2) 1,586 1,539
Effect of tax rate changes on future income
tax liabilities (1,612) (4,401)
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Adjusted net earnings from operations $ 17,404 $ 17,933
Per share - basic $ 0.13 $ 0.14
- diluted $ 0.13 $ 0.14
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(1) Adjusted net earnings from operations was referred to as Operating
Earnings in prior years.
(2) Excludes compensation costs related to the Restricted Share Unit
Plan.
REVENUE
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Three Months Ended March 31 2008 2007 Change
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Average production
Natural gas (mmcf/d) 170 148 15%
Liquids (light oil & ngls) (bbls/d) 5,009 8,729 -43%
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Total (boe/d) 33,274 33,316 0%
Benchmark prices
Natural Gas
AECO ($/GJ)
Monthly index $ 6.75 $ 7.07 -5%
Daily index $ 7.49 $ 7.00 7%
Crude Oil
WTI (U.S.$/bbl) $ 97.85 $ 58.12 68%
Edmonton sweet light ($/bbl) $ 97.44 $ 67.13 45%
Realized prices
Natural gas ($/mcf) $ 7.48 $ 7.24 3%
Liquids ($/bbl) 94.97 54.20 62%
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Total ($/boe) $ 53.64 $ 46.98 14%
Revenue ($000s)
Natural gas $115,439 $ 96,079 20%
Crude oil and ngls 46,994 44,798 5%
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Total $162,433 $140,877 15%
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Natural gas production rose by 15% on a year over year basis, while liquids volumes decreased by 43% over the same period due primarily to the sale of oil producing assets at the end of the third quarter of 2007. Revenue attributable to natural gas volumes grew by 20% over the first quarter of 2007 due to slightly higher realized natural gas prices and significantly increased natural gas production.
We market our natural gas using both 30 day AECO indexed and daily AECO indexed contracts. Approximately 49% of our gas was sold on monthly evergreen contracts, and approximately 42% on indexed daily contracts. The remaining 9% of Compton's natural gas production remains committed to aggregator contracts, which received a price during the current quarter that was, on average, $0.80/mcf less than prices received on non-aggregator volumes.
ROYALTIES
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Three Months Ended March 31 2008 2007
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Royalties ($000s) $ 33,487 $ 28,646
Percentage of revenues 20.6% 20.3%
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The Alberta royalty structure is based upon commodity prices and well productivity, with higher prices and well productivity attracting higher royalty rates. As a percentage of total revenue, our royalties remained consistent with the comparable period in 2007.
OPERATING EXPENSES
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Three Months Ended March 31 2008 2007
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Operating expenses ($000s) $ 28,842 $ 26,032
Operating expenses per boe ($/boe) $ 9.53 $ 8.68
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Operating expenses for the first quarter of 2008 increased 11% over the first quarter of 2007 as a result of costs associated with accelerated activity throughout the oil and gas industry. Additionally, the first quarter of 2008 experienced significantly colder weather than the first quarter of 2007, resulting in increased operating costs associated with difficult operating conditions. For a similar reason first quarter 2008 operating costs increased 5% over the fourth quarter of 2007.
TRANSPORTATION
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Three Months Ended March 31 2008 2007
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Transportation costs ($000s) $ 2,254 $ 2,482
Transportation costs per boe ($/boe) $ 0.74 $ 0.83
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Transportation expenses for the first quarter of 2008 fell by 9% over the first quarter of 2007 as a result of reduced trucking requirements associated with lower oil volumes.
GENERAL AND ADMINISTRATIVE EXPENSES
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Three Months Ended March 31
($000s, except where noted) 2008 2007
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General and administrative expenses $ 12,054 $ 9,338
Capitalized general and administrative expenses (2,458) (2,165)
Operator recoveries (674) (764)
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Total general and administrative expenses $ 8,922 $ 6,409
General and administrative per boe ($/boe) $ 2.95 $ 2.14
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General and administrative expenses increased by 39% year over year primarily as a result of increased personnel costs, higher rent associated with additional office space, and other escalating overhead expenses such as insurance and consulting fees.
STRATEGIC REVIEW EXPENSES
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Three Months Ended March 31 2008 2007
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Strategic review costs ($000s) $ 2,568 -
Strategic review costs per boe ($/boe) $ 0.85 -
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In the first quarter of 2008, we incurred approximately $2.6 million in expenses associated with the strategic review process. Compton has estimated direct costs associated with and resulting from the review process could total approximately $22 million. These costs include among others, consulting and advisory fees, legal fees, and costs relating to employee retention.
INTEREST EXPENSE
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Three Months Ended March 31
($000s, except where noted) 2008 2007
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Interest on bank debt, net $ 6,458 $ 5,209
Interest on Senior Notes 8,980 10,445
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Interest charges $ 15,438 $ 15,654
Finance charges 413 (110)
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Total interest and finance charges $ 15,851 $ 15,544
Total interest and finance charges per boe ($/boe) $ 5.23 $ 5.18
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Weighted average debt
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Three months ended March 31
($000s, except where noted) 2008 2007
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Bank debt $433,664 $327,444
Effective interest rate 5.96% 6.35%
Senior unsecured notes (US$450,000) $451,610 $437,932
Effective interest rate 8.00% 8.15%
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Interest expenses relating to bank debt for the first three months of 2008 increased from the comparative prior year period as a result of increased borrowings incurred to fund our 2007 and 2008 drilling programs. Interest charges payable in US dollars on our Senior Notes have decreased by 14% due to the strengthening of the Canadian dollar relative to the US dollar over this time period.
Interest on our senior unsecured notes is payable in US dollars at a fixed annual rate of 7.625%. This equates to interest costs of US$34.3 million per year relating to the notes. During the last quarter of 2007, we entered into foreign exchange contracts that fixed the exchange rate of the interest payments and, as a result, we will incur Canadian dollar interest costs of $34.2 million per year through to December 1, 2010 on the notes. This will result in an overall reduction of $4.2 million in 2008 interest costs relating to the senior notes as compared to 2007. At the time of issuance of the notes, we received Canadian dollar proceeds of $510 million. Based upon the proceeds received, the effective fixed rate of interest on the notes is 6.7% per year through to December 1, 2010.
DEPLETION AND DEPRECIATION
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Three Months Ended March 31 2008 2007
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Depletion and depreciation ($000s) $ 41,807 $ 38,794
Depletion and depreciation per boe ($/boe) $ 13.81 $ 12.94
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Strong commodity prices have accelerated capital programs and competition throughout the oil and gas industry, raising the demand for and costs of goods and services. This increase in costs is reflected in increased finding, development, and on-stream costs which in turn have resulted in an increase in depletion and depreciation rates in the current quarter in comparison to the prior comparative period.
INCOME TAXES
Income taxes are recorded using the liability method of accounting. Future income taxes are calculated based on the difference between the accounting and income tax basis of an asset or liability. Note 12 in the financial statements details the calculation of the provision and the effective tax rate for the period. The classification of future income taxes between current and non-current is based upon the classification of the liabilities and assets to which the future income tax amounts relate. The classification of a future income tax amount as current does not imply a cash settlement of the amount within the following twelve month period.
RISK MANAGEMENT
Our financial results are impacted by external market risks associated with fluctuations in commodity prices, interest rates, and the Canadian/U.S. currency exchange rate. We use various financial instruments for non-trading purposes to manage and partially mitigate our exposure to these risks.
Financial instruments used to manage risk are subject to periodic settlements throughout the term of the instruments. Such settlements may result in a gain or loss which is recognized as a risk management gain or loss at the time of settlement. The mark-to-market value of an instrument outstanding at the end of a reporting period reflects the value of the instrument based upon market conditions existing as of that date. Any change in value from that determined at the end of the prior period is recognized as an unrealized risk management gain or loss.
Risk management gains and losses recognized in the quarter are summarized in the following table.
Risk Management Gains and Losses
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Three Months Ended March 31 ($000s) 2008 2007
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Commodity contracts
Realized (gain) loss $ (611) $ (8,753)
Unrealized (gain) loss 27,097 16,486
Foreign currency contracts
Realized (gain) loss - 838
Unrealized (gain) loss (26,324) -
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Total risk management (gain) loss $ 162 $ 8,571
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Realized (gain) loss $ (611) $ (8,753)
Unrealized (gain) loss 773 17,324
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Total risk management (gain) loss $ 162 $ 8,571
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Unrealized risk management gains and losses may or may not be realized based upon the underlying market conditions at the time of settlement.
RISK MANAGEMENT - OUTSTANDING CONTRACTS
Commodity hedge contracts in place as at May 9, 2008 are:
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Commodity Term Amount Average Price Index
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Natural gas
Collars April 2008 - Oct. 2008 66,667 mcf/d $7.50 - $8.93 AECO
Fixed April 2008 - Oct. 2008 19,048 mcf/d $7.86 AECO
Collars Nov. 2008 - March 2009 28,571 mcf/d $8.40 - $10.00 AECO
Fixed Nov. 2008 - March 2009 9,524 mcf/d $8.51 AECO
Crude oil
Fixed March 2008 - Dec. 2008 1,000 bbls/d U.S.$93.00/bbl WTI
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FOREIGN EXCHANGE CONTRACTS
On March 31, 2008, Compton had the following foreign exchange contracts in place:
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Mark to
Contract Amount USD Rate Amount CDN Term Market
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Matures on
Currency December 1,
Swap $450,000,000 96.9750 $436,387,500 2010 $ 33,822
Equal payments
on May 30 and
Currency Nov. 30
Swap $78,435,000 99.5500 $78,082,043 until 2010 3,338
Cross
Currency Equal payments
Interest on May 15 and
Rate BA plus Nov. 15
Swap $24,502,500 4.845% $35,801,232 until 2009 (6,885)
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Total unrealized foreign exchange gain $ 30,275
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CAPITAL EXPENDITURES
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Three Months Ended March 31 ($000s) 2008 % 2007 %
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Land and seismic $ 6,104 6% $ 13,258 12%
Drilling and completions 65,776 65% 64,468 61%
Production facilities and equipment 29,068 29% 28,333 27%
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Sub-total $100,948 100% $106,059 100%
Property acquisitions (divestitures)
net 10,518 (45,261)
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Sub-total $111,466 60,798
MPP 61 569
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Total capital expenditures $111,527 $ 61,367
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Capital spending, before acquisitions and divestments, during the first quarter of 2008 remained relatively consistent with that of the comparable period in 2007, although an additional 10 net wells were drilled during the first quarter of 2008 as compared to the prior year. A total of 53 Belly River natural gas wells were drilled during the first quarter of 2008 as compared to 34 Belly River wells during the same time period in 2007. The sale of the Worsley property during 2007 resulted in no oil wells being drilled in the Peace River Arch area in 2008 as compared to the 10 wells drilled in the area during 2007. The shallow Belly River wells are significantly less costly to drill and complete than were the Worsley oil wells resulting in year over year expenditures being relatively consistent, despite the year over year increased number of wells drilled.
LIQUIDITY AND CAPITAL RESOURCES
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As at March 31, As at Dec. 31,
($000s, except where noted) 2008 2007
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Senior term notes $462,555 $444,645
Associated unrealized exchange (gain) (33,822) (14,146)
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$428,733 $430,499
Bank debt 435,000 400,000
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Long term debt $863,733 $830,499
Working capital deficiency 47,323 39,216
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Total indebtedness $911,056 $869,715
Shareholders' equity $875,017 $869,956
Debt to adjusted EBITDA(1)(2) 3.5x 3.6x
Debt to total capitalization(1) 51% 50%
Debt to enterprise value(1) 39% 41%
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(1) Excludes risk management items net of related future income taxes.
(2) Based on trailing 12 month adjusted EBITDA.
Our senior term notes are payable in US dollars and are translated into Canadian Dollars at the period end at the then prevailing exchange rate. Any change from the prior period is recognized as an unrealized exchange gain or loss and decreases or increases the carrying value of the notes. At March 31, 2008 the carrying value of the notes increased by $17.9 million from December 31, 2007 as a result of the unrealized loss on translation at March 31, 2008. In 2007, we entered into foreign exchange contracts relating to the senior notes that effectively fixes their liability in Canadian dollars through to December 1, 2010. The unrealized mark-to-market gain on these contracts is recognized as a reduction to the notes in determining total debt and capitalization as determined above.
Note 5 to the financial statements discusses our capital structure and certain non-GAAP measure and targets utilized in managing our capital structure. We have targeted a total debt to capitalization ratio of between 40% and 50% and a total debt to adjusted EBITDA ratio of between 2.5 to 1 and 3.0 to 1. As at March 31, 2008 our debt to capitalization ratio of 52% and our debt to adjusted EBITDA of 3.5 to 1 exceeded our targeted ranges. The Company is in the process of divesting of certain non-core assets. Proceeds from these divestments are expected to be such that, subsequent to closing, the Company will be within the range of its stated capital structure targets. Agents have been appointed to manage the property sales and preliminary bids are due on May 27, 2008. The divestments are expected to close on or about June 30, 2008.
Our corporate debt is structured to provide us with financial flexibility and coincide with the nature of our asset base. As of December 31, 2007 the reserve life index of our proved reserves was approximately 12 years. Of our existing debt, 48% consists of long term senior unsecured notes that are not due until 2013. This structure provides us the ability to draw on our senior secured credit facilities to assist in funding our planned capital programs.
The borrowing base on which our syndicated credit facility is based is determined in relation to our year end reserves. The credit facility is currently under annual review and with the increase in our 2007 reserves we do not anticipate any reduction to the borrowing base. Initially, the proceeds from the property sales referred to above will be applied to reduce our outstanding bank debt and our borrowing base may be reduced to reflect the reduction in reserves associated with these dispositions. Any such change is expected to be minimal and largely offset by the increase in reserves and stronger commodity prices. Currently we have authorized senior secured credit facilities of $500 million, of which $65 million remains available.
We believe internally generated cash flow from operations and the proceeds from planned property dispositions will be more than sufficient to fund our planned capital program.
STRATEGIC DIRECTION FOR 2008
2008 Plan Update
During the later part of 2007 and during the first quarter of 2008 we have achieved considerable success using multi stage frac technology combined with horizontal wells drilled into tight natural gas formations. At Niton in central Alberta we have drilled a total of 16 horizontal wells targeting the Rock Creek formation and most recently, we have applied this technology to the Basal Quartz formation at Hooker in southern Alberta with very positive results. We are currently assessing the application of this technology to the Belly River play in southern Alberta where we are testing two horizontal wells drilled in 2008.
Although wells drilled and completed using this technology are approximately twice the cost of vertical wells, results to date indicate their potential to increase capital efficiencies and enhance the present values of reserves in developing our natural gas resource plays.
Our initial 2008 drilling program and capital budget only minimally reflected the use of this technology. Additionally, our budget was based upon what now appears to be overly conservative commodity prices for the year. In view of these positive developments, we are in the process of revisiting our drilling program and capital budget for the remainder of 2008 to incorporate increased horizontal drilling and multi stage frac completions and stronger commodity prices. We expect this revised budget to be completed in late May.
Strategic Review
As previously announced, the Board of Directors, in response to concerns raised by Centennial Energy Partners LLC, has implemented a formal review of Compton's business plans and various strategic alternatives available to the Company. The review is being conducted by a Special Committee of the Board, assisted by Tristone Capital Inc. and UBS Securities Canada Inc., who have been engaged as financial advisors and independent counsel.
The initial phase of this review is ongoing and consists of a comprehensive analysis by the advisors, working independently, of Compton's business plans and various strategic alternatives available to the Company, including asset divestments, equity alternatives, strategic alliances, joint venture opportunities mergers or a corporate transaction. The advisors are scheduled to report to the Special Committee near the end of May and provide their recommendations for consideration by the Special Committee.
Guidance
The update to our 2008 budget plans and the outcome of the strategic review process, as discussed above, both have the potential to materially impact Compton's future direction and activities. Updated guidance will be provided once these issues have been addressed.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
There were no changes during the quarter ended March 31, 2008 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ADDITIONAL DISCLOSURES
On January 1, 2008, Compton 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 our consolidated financial statements. The effects of the implementation of the new standards are discussed below.
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.
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.
Financial instruments disclosure and presentation
These new standards require increased disclosure of financial instruments with particular emphasis on the risks associated with recognized and unrecognized financial instruments and how those risks are managed by Compton as disclosed in Note 13 of the financial statements.
Capital Disclosures
The new standard requires disclosure about Compton's objectives, policies and process for managing its capital structure as disclosed in Note 6 of the financial statements.
QUARTERLY INFORMATION
The following table sets forth certain quarterly financial information of the Company for the eight most recent quarters.
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2008 2007
Q1 Q4 Q3 Q2 Q1
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Total revenue (millions) $ 162 $ 126 $ 108 $ 126 $ 141
Adjusted cash flow from
operations (millions) $ 69 $ 46 $ 33 $ 49 $ 69
Per share - basic $ 0.54 $ 0.35 $ 0.26 $ 0.38 $ 0.53
- diluted $ 0.52 $ 0.35 $ 0.25 $ 0.36 $ 0.52
Net earnings (millions) $ 2 $ 50 $ 20 $ 45 $ 14
Per share - basic $ 0.01 $ 0.39 $ 0.15 $ 0.35 $ 0.11
- diluted $ 0.01 $ 0.38 $ 0.15 $ 0.34 $ 0.10
Adjusted net earnings from
operations (millions) $ 17 $ (2) $ (2) $ 7 $ 18
Production
Natural gas (mmcf/d) 170 167 135 130 148
Liquids (bbls/d) 5,009 4,818 7,954 7,199 8,729
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Total (boe/d) 33,274 32,646 30,440 28,918 33,316
Average price
Natural gas ($/mcf) $ 7.48 $ 6.00 $ 5.23 $ 6.92 $ 7.24
Liquids ($/bbl) 94.97 77.60 61.91 60.49 54.20
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Total ($/boe) $ 53.64 $ 41.94 $ 38.56 $ 47.94 $ 46.98
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2006
Q4 Q3 Q2
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Total revenue (millions) $ 130 $ 127 $ 135
Adjusted cash flow from
operations (millions) $ 55 $ 60 $ 67
Per share - basic $ 0.43 $ 0.47 $ 0.53
- diluted $ 0.42 $ 0.45 $ 0.50
Net earnings (millions) $ (10) $ 31 $ 69
Per share - basic $ (0.08) $ 0.24 $ 0.54
- diluted $ (0.08) $ 0.23 $ 0.51
Adjusted net earnings from
operations (millions) $ 12 $ 13 $ 18
Production
Natural gas (mmcf/d) 148 142 137
Liquids (bbls/d) 8,600 9,249 9,821
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Total (boe/d) 33,245 32,843 32,645
Average price
Natural gas ($/mcf) $ 6.48 $ 5.38 $ 5.86
Liquids ($/bbl) 48.44 57.53 59.41
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Total ($/boe) $ 42.60 $ 42.03 $ 45.37
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Compton Petroleum Corporation
Consolidated Balance Sheets
(thousands of dollars)
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March 31, December 31,
2008 2007
------------ ------------
(unaudited)
Assets
Current
Cash $ 16,614 $ 8,665
Accounts receivable 99,097 83,144
Risk management gain (Note 13b) 1,341 1,835
Other current assets 25,434 19,772
Future income taxes 8,825 2,606
------------ ------------
151,311 116,022
Property and equipment 2,187,374 2,116,834
Goodwill 9,933 9,933
Other assets 332 291
Risk management gain (Note 13b) 36,319 14,320
------------ ------------
$ 2,385,269 $ 2,257,400
------------ ------------
------------ ------------
Liabilities
Current
Accounts payable $ 188,468 $ 150,796
Risk management loss (Note 13b) 30,427 8,832
Future income taxes 389 542
------------ ------------
219,284 160,170
Long term debt (Note 3) 885,274 832,188
Asset retirement obligations (Note 7) 38,329 36,696
Risk management loss (Note 13b) 2,265 1,585
Future income taxes 302,170 293,494
Non-controlling interest (Note 8) 62,930 63,311
------------ ------------
1,510,252 1,387,444
------------ ------------
Shareholders' equity
Capital stock (Note 4) 238,305 235,871
Contributed surplus (Note 9a) 25,838 24,233
Retained earnings 610,874 609,852
------------ ------------
875,017 869,956
------------ ------------
$ 2,385,269 $ 2,257,400
------------ ------------
------------ ------------
See accompanying notes to the consolidated financial statements.
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Compton Petroleum Corporation
Consolidated Statements of Earnings and Other Comprehensive Income
(unaudited) (thousands of dollars, except per share amounts)
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Three months ended March 31, 2008 2007
--------------------------------------------- ------------ ------------
Revenue
Oil and natural gas revenues $ 162,433 $ 140,877
Royalties (33,487) (28,646)
------------ ------------
128,946 112,231
------------ ------------
Expenses
Operating 28,842 26,032
Transportation 2,254 2,482
General and administrative 8,922 6,409
Stock-based compensation 2,996 3,266
Strategic review (Note 16) 2,568 -
Interest and finance charges (Note 10) 15,851 15,544
Foreign exchange (gain) loss (Note 14) 17,906 (5,522)
Risk management (gain) loss (Note 13c) 162 8,571
Depletion and depreciation 41,807 38,794
Accretion of asset retirement obligations 812 651
------------ ------------
122,120 96,227
------------ ------------
Earnings before taxes and non-controlling
interest 6,826 16,004
------------ ------------
Income taxes (Note 12)
Current 8 (13)
Future 3,286 610
------------ ------------
3,294 597
------------ ------------
Earnings before non-controlling interest 3,532 15,407
Non-controlling interest 1,913 1,688
------------ ------------
Net earnings 1,619 13,719
------------ ------------
------------ ------------
Other comprehensive income - -
------------ ------------
Comprehensive income $ 1,619 $ 13,719
------------ ------------
------------ ------------
Net earnings per share (Note 11)
Basic $ 0.01 $ 0.11
------------ ------------
------------ ------------
Diluted $ 0.01 $ 0.10
------------ ------------
------------ ------------
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Compton Petroleum Corporation
Consolidated Statements of Retained Earnings
(unaudited) (thousands of dollars)
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Three months ended March 31, 2008 2007
--------------------------------------------- ------------ ------------
Retained earnings, as previously reported $ 609,852 $ 485,158
Accounting policy adjustments - (1,320)
------------ ------------
Retained earnings, as adjusted 609,852 483,838
Net earnings 1,619 13,719
Premium on redemption of shares (Note 4) (597) (787)
------------ ------------
Retained earnings, end of period $ 610,874 $ 496,770
------------ ------------
------------ ------------
See accompanying notes to the consolidated financial statements.
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Compton Petroleum Corporation
Consolidated Statements of Cash Flow
(unaudited) (thousands of dollars)
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Three months ended March 31, 2008 2007
--------------------------------------------- ------------ ------------
Operating activities
Net earnings $ 1,619 $ 13,719
Amortization and other (107) 511
Depletion and depreciation 41,807 38,794
Accretion of asset retirement obligations 812 651
Unrealized foreign exchange (gain) loss 17,910 (5,580)
Future income taxes 3,286 610
Unrealized risk management (gain) loss 773 17,324
Stock-based compensation 2,249 2,267
Asset retirement expenditures (940) (1,201)
Non-controlling interest 1,913 1,688
------------ ------------
69,322 68,783
Change in non-cash working capital 326 4,253
------------ ------------
69,648 73,036
------------ ------------
Financing activities
Issuance (repayment) of bank debt 35,238 (15,000)
Proceeds from share issuances (net) 1,918 1,877
Distributions to partner (2,292) (2,293)
Redemption of common shares (724) (946)
------------ ------------
34,140 (16,362)
------------ ------------
Investing activities
Property and equipment additions (101,050) (105,428)
Property acquisitions (10,998) -
Property dispositions 480 45,261
Change in non-cash working capital 15,729 2,591
------------ ------------
(95,839) (57,576)
------------ ------------
Change in cash 7,949 (902)
Cash, beginning of period 8,665 11,876
------------ ------------
Cash, end of period $ 16,614 $ 10,974
------------ ------------
------------ ------------
See accompanying notes to the consolidated financial statements.
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Compton Petroleum Corporation
Notes to the Consolidated Financial Statements
(unaudited)
(Tabular amounts in thousands of dollars, unless otherwise stated)
March 31, 2008
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1. Basis of presentation
Compton Petroleum Corporation (the "Company" or "Compton") explores for
and produces petroleum and natural gas reserves in the Western Canadian
Sedimentary Basin.
These consolidated financial statements include the accounts of the
Company and its wholly owned subsidiaries. The consolidated financial
statements also include the accounts of Mazeppa Processing Partnership
(the "Partnership" or "MPP") in accordance with Accounting Guideline 15
("AcG-15"), Consolidation of Variable Interest Entities, as outlined in
Note 8.
These consolidated interim financial statements have been prepared by
Management in accordance with accounting principles generally accepted in
Canada. Certain information and disclosure normally required to be
included in notes to annual consolidated financial statements have been
condensed or omitted. The consolidated interim financial statements
should be read in conjunction with the audited consolidated financial
statements and the notes thereto in the Company's annual report for the
year ended December 31, 2007. The consolidated interim financial
statements have been prepared following the same accounting policies and
methods of compu
