Compton Petroleum Corporation News
Compton Petroleum announces first quarter results
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 ————————————————————————————————————- Three Months Ended March 31 ($000s, except per share amounts) 2008 2007 Change ————————————————————————————————————- 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 $106,059 -5% ————————————————————————————————————- (1) See cautionary statements at the beginning of Management's Discussion and Analysis. OPERATING SUMMARY ————————————————————————————————————- Three Months Ended March 31 2008 2007 Change ————————————————————————————————————- Average production Natural gas (mmcf/d) 170 148 15% Liquids (bbls/d) 5,009 8,729 -43% ————————————————————————————————————- Total (boe/d) 33,274 33,316 0% Realized prices Natural gas ($/mcf) $ 7.48 $ 7.24 3% Liquids ($/bbl) 94.97 54.20 62% ————————————————————————————————————- Total ($/boe) $ 53.64 $ 46.98 14% Field netback ($/boe) $ 41.06 $ 30.84 33% ————————————————————————————————————- OPERATIONS REVIEW Drilling Summary
————————————————————————————————————- Gas Oil D&A Total Net Success ————————————————————————————————————- Southern Alberta 50 1 3 54 51 94% Central Alberta 37 3 1 41 18 98% ————————————————————————————————————- Standing, cased wells 4 4 ————————————————————————————————————- Total 87 4 4 99 73 96% ————————————————————————————————————- DEEP BASIN GAS
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
Subsequent to quarter end,
The existing Basal Quartz play, as currently delineated, extends over four townships where
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
During the previous week
With the success that
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
Foothills
In the foothills at
Our exploration program at Callum is designed to minimize our environmental footprint in this environmentally sensitive area.
SHALLOW GAS
The Plains Belly River and overlying Edmonton Horseshoe Canyon shallow gas zones cover more than 1,200 sections of
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
————————————————————————————————————-
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
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
The forward-looking statements contained herein are made as of the date of this MD&A solely for the purpose of generally disclosing
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
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
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.
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 ————————————————————————————————————- Three Months Ended March 31 ($000s, except per share amounts) 2008 2007 Change ————————————————————————————————————- 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% ————————————————————————————————————-
The following table reconciles net earnings to adjusted cash flow from operations:
————————————————————————————————————- 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 ————————————————————————————————————- Adjusted cash flow from operations $ 69,322 $ 68,783 ————————————————————————————————————- 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) ————————————————————————————————————- Three Months Ended March 31 ($000s, except per share amounts) 2008 2007 ————————————————————————————————————- 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) ————————————————————————————————————- Adjusted net earnings from operations $ 17,404 $ 17,933 Per share - basic $ 0.13 $ 0.14 - diluted $ 0.13 $ 0.14 ————————————————————————————————————- (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 ————————————————————————————————————- Three Months Ended March 31 2008 2007 Change ————————————————————————————————————- Average production Natural gas (mmcf/d) 170 148 15% Liquids (light oil & ngls) (bbls/d) 5,009 8,729 -43% ————————————————————————————————————- 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 ($/bbl) 94.97 54.20 62% ————————————————————————————————————- Total ($/boe) $ 53.64 $ 46.98 14% Revenue ($000s) Natural gas $115,439 $ 96,079 20% Crude oil and ngls 46,994 44,798 5% ————————————————————————————————————- Total $162,433 $140,877 15% ————————————————————————————————————-
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
ROYALTIES ————————————————————————————————————- Three Months Ended March 31 2008 2007 ————————————————————————————————————- Royalties ($000s) $ 33,487 $ 28,646 Percentage of revenues 20.6% 20.3% ————————————————————————————————————-
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 ————————————————————————————————————- Three Months Ended March 31 2008 2007 ————————————————————————————————————- Operating expenses ($000s) $ 28,842 $ 26,032 Operating expenses per boe ($/boe) $ 9.53 $ 8.68 ————————————————————————————————————-
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 ————————————————————————————————————- Three Months Ended March 31 2008 2007 ————————————————————————————————————- Transportation costs ($000s) $ 2,254 $ 2,482 Transportation costs per boe ($/boe) $ 0.74 $ 0.83 ————————————————————————————————————-
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 ————————————————————————————————————- Three Months Ended March 31 ($000s, except where noted) 2008 2007 ————————————————————————————————————- General and administrative expenses $ 12,054 $ 9,338 Capitalized general and administrative expenses (2,458) (2,165) Operator recoveries (674) (764) ————————————————————————————————————- Total general and administrative expenses $ 8,922 $ 6,409 General and administrative per boe ($/boe) $ 2.95 $ 2.14 ————————————————————————————————————-
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 ————————————————————————————————————- Three Months Ended March 31 2008 2007 ————————————————————————————————————- Strategic review costs ($000s) $ 2,568 - Strategic review costs per boe ($/boe) $ 0.85 - ————————————————————————————————————-
In the first quarter of 2008, we incurred approximately
INTEREST EXPENSE ————————————————————————————————————- Three Months Ended March 31 ($000s, except where noted) 2008 2007 ————————————————————————————————————- Interest on bank debt, net $ 6,458 $ 5,209 Interest on Senior Notes 8,980 10,445 ————————————————————————————————————- Interest charges $ 15,438 $ 15,654 Finance charges 413 (110) ————————————————————————————————————- Total interest and finance charges $ 15,851 $ 15,544 Total interest and finance charges per boe ($/boe) $ 5.23 $ 5.18 ————————————————————————————————————- Weighted average debt ————————————————————————————————————- Three months ended March 31 ($000s, except where noted) 2008 2007 ————————————————————————————————————- 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% ————————————————————————————————————-
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
DEPLETION AND DEPRECIATION ————————————————————————————————————- Three Months Ended March 31 2008 2007 ————————————————————————————————————- Depletion and depreciation ($000s) $ 41,807 $ 38,794 Depletion and depreciation per boe ($/boe) $ 13.81 $ 12.94 ————————————————————————————————————-
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 ————————————————————————————————————- Three Months Ended March 31 ($000s) 2008 2007 ————————————————————————————————————- 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) - ————————————————————————————————————- Total risk management (gain) loss $ 162 $ 8,571 ————————————————————————————————————- Realized (gain) loss $ (611) $ (8,753) Unrealized (gain) loss 773 17,324 ————————————————————————————————————- Total risk management (gain) loss $ 162 $ 8,571 ————————————————————————————————————-
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: ————————————————————————————————————- Commodity Term Amount Average Price Index ————————————————————————————————————- 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 ————————————————————————————————————- FOREIGN EXCHANGE CONTRACTS
On
————————————————————————————————————- Mark to Contract Amount USD Rate Amount CDN Term Market ————————————————————————————————————- 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) ————————————————————————————————————- Total unrealized foreign exchange gain $ 30,275 ————————————————————————————————————- CAPITAL EXPENDITURES ————————————————————————————————————- Three Months Ended March 31 ($000s) 2008 % 2007 % ————————————————————————————————————- 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% ————————————————————————————————————- Sub-total $100,948 100% $106,059 100% Property acquisitions (divestitures) net 10,518 (45,261) ————————————————————————————————————- Sub-total $111,466 60,798 MPP 61 569 ————————————————————————————————————- Total capital expenditures $111,527 $ 61,367 ————————————————————————————————————-
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
LIQUIDITY AND CAPITAL RESOURCES ————————————————————————————————————- As at March 31, As at Dec. 31, ($000s, except where noted) 2008 2007 ————————————————————————————————————- Senior term notes $462,555 $444,645 Associated unrealized exchange (gain) (33,822) (14,146) ————————————————————————————————————- $428,733 $430,499 Bank debt 435,000 400,000 ————————————————————————————————————- Long term debt $863,733 $830,499 Working capital deficiency 47,323 39,216 ————————————————————————————————————- 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% ————————————————————————————————————- (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
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
Our corporate debt is structured to provide us with financial flexibility and coincide with the nature of our asset base. As of
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
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
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
The initial phase of this review is ongoing and consists of a comprehensive analysis by the advisors, working independently, of
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
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
There were no changes during the quarter ended
ADDITIONAL DISCLOSURES
On
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
Capital Disclosures
The new standard requires disclosure about
QUARTERLY INFORMATION
The following table sets forth certain quarterly financial information of the Company for the eight most recent quarters.
————————————————————————————————————- 2008 2007 Q1 Q4 Q3 Q2 Q1 ————————————————————————————————————- 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 ————————————————————————————————————- 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 ($/bbl) 94.97 77.60 61.91 60.49 54.20 ————————————————————————————————————- Total ($/boe) $ 53.64 $ 41.94 $ 38.56 $ 47.94 $ 46.98 ————————————————————————————————————- ———————————————————————————- 2006 Q4 Q3 Q2 ———————————————————————————- 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 ———————————————————————————- Total (boe/d) 33,245 32,843 32,645 Average price Natural gas ($/mcf) $ 6.48 $ 5.38 $ 5.86 Liquids ($/bbl) 48.44 57.53 59.41 ———————————————————————————- Total ($/boe) $ 42.60 $ 42.03 $ 45.37 ———————————————————————————- ————————————————————————————————————- Compton Petroleum Corporation Consolidated Balance Sheets (thousands of dollars) ————————————————————————————————————- 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. ————————————————————————————————————- Compton Petroleum Corporation Consolidated Statements of Earnings and Other Comprehensive Income (unaudited) (thousands of dollars, except per share amounts) ————————————————————————————————————- 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 —————— —————— —————— —————— ————————————————————————————————————- Compton Petroleum Corporation Consolidated Statements of Retained Earnings (unaudited) (thousands of dollars) ————————————————————————————————————- 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. ————————————————————————————————————- Compton Petroleum Corporation Consolidated Statements of Cash Flow (unaudited) (thousands of dollars) ————————————————————————————————————- 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 —————— ———-
Search Our News Using Google Search
Can't find what you want? Try using Google:
