Compton Petroleum announces second quarter results

CALGARY, Aug. 13 /PRNewswire-FirstCall/ -- Compton Petroleum Corporation ("Compton" or the "Company") is pleased to announce its financial and operating results for the quarter ended June 30, 2007.

The second quarter of 2007 was an active and productive quarter for Compton despite weather related operational delays and weakening natural gas prices. During the quarter we:

- continued with the interpretation of new 3D seismic data critical to identifying optimal well locations in southern and central Alberta, - completed the scheduled two week maintenance program (turn around) at the Mazeppa gas processing plant, - added to our technical teams, - secured future goods and services at significantly reduced costs, - finalized our longer term strategic plans and direction, and - continued the process of redeployment of capital into our focus natural gas resource plays through the planned divestiture of non-core properties and the expansion of our core areas through strategic acquisitions.

As stated in our Operational Update and Longer Term Strategic Direction news release of July 11, 2007, we are quickly moving towards becoming a pure natural gas resource play company. During the second quarter of 2007, much was achieved in positioning Compton for the expanded drilling programs necessary for production growth and the development of our natural gas resource plays.

Weather related delays compounded by a two week turn around at the Mazeppa gas plant for scheduled maintenance resulted in reduced production for the quarter, which is reflected and discussed in the following quarterly financial and operating reviews.

FINANCIAL SUMMARY ------------------------------------------------------------------------- ($000s, except per share Three Months Ended June 30 Six Months Ended June 30 amounts) 2007 2006 Change 2007 2006 Change ------------------------------------------------------------------------- Gross revenue $ 126,171 $ 134,778 -6% $ 267,048 $ 283,557 -6% Cash flow from operations(1) $ 48,582 $ 67,326 -28% $ 117,365 $ 140,922 -17% Per share - basic(1) $ 0.38 $ 0.53 -28% $ 0.91 $ 1.11 -18% - diluted(1) $ 0.36 $ 0.50 -28% $ 0.88 $ 1.05 -16% Operating earnings(1) $ 7,364 $ 17,947 -59% $ 25,297 $ 40,191 -37% Net earnings $ 45,307 $ 68,744 -34% $ 59,026 $ 106,746 -45% Per share - basic $ 0.35 $ 0.54 -35% $ 0.46 $ 0.84 -45% - diluted $ 0.34 $ 0.51 -33% $ 0.44 $ 0.80 -45% Capital expenditures $ 51,133 $ 96,039 -47% $ 112,500 $ 289,468 -61% ------------------------------------------------------------------------- (1) See advisory statements following Management's Discussion and Analysis. OPERATING SUMMARY ------------------------------------------------------------------------- Three Months Ended June 30 Six Months Ended June 30 2007 2006 Change 2007 2006 Change ------------------------------------------------------------------------- Average daily production Natural gas (mmcf/d) 130 137 -5% 139 139 0% Liquids (bbls/d) 7,199 9,821 -27% 7,959 10,118 -21% ------------------------------------------------------------------------- Total (boe/d) 28,918 32,645 -11% 31,105 33,333 -7% Realized prices Natural gas ($/mcf) $ 6.92 $ 5.86 18% $ 7.09 $ 6.73 5% Liquids ($/bbl) 60.49 67.09 -10% 57.74 60.93 -5% ------------------------------------------------------------------------- Total ($/boe) $ 47.94 $ 45.37 6% $ 47.43 $ 47.00 1% Field netback ($/boe) $ 28.55 $ 26.04 10% $ 28.22 $ 27.61 2% ------------------------------------------------------------------------- OPERATIONS REVIEW

Due to weather related issues, the first half of 2007 was a very difficult operating period for the industry as a whole and Compton in particular. An early spring break-up followed by wet weather lasting through May and June resulted in extremely poor field conditions that seriously delayed operations. We drilled 84 of a planned 153 wells during the first half of 2007 and field conditions prevented us from completing any well tie-ins during April and May. Additionally, field conditions limited well access delaying routine maintenance necessary to maintain and optimize production.

With improving field conditions and readily available services, we are confident that we will be able to complete our second half drilling program. During the month of July, we drilled 33 wells, and currently have eight drilling rigs operating and 12 pipeline and facility construction crews at work. We have substantial pipeline and facility infrastructure in all our core areas that enables us to reduce the time from rig release to on-stream production status.

On the positive side, second quarter operational delays have allowed us to realize on reduced goods and service costs that are now in evidence.

Drilling Summary

Of the 84 (75.5 net) wells drilled during the first half of this year, 86% or 72 wells were classified as development and 14% or 12 were exploratory wells. The following table summarizes our drilling results in the first half of the year.

------------------------------------------------------------------------- First Half 2007 Drill Summary Gas Oil D&A Total Net Success ------------------------------------------------------------------------- Southern Alberta 45 - 1 46 44.4 98% Central Alberta 15 5 2 22 16.5 91% Peace River Arch - 8 2 10 8.6 80% ------------------------------------------------------------------------- Standing, cased wells 6 6.0 ------------------------------------------------------------------------- Total 84 75.5 94% ------------------------------------------------------------------------- Southern Alberta ----------------

During the second quarter of 2007, we drilled eight wells with a 100% success rate in southern Alberta.

Plains Belly River and Edmonton Horseshoe Canyon CBM

We drilled seven Belly River wells during the second quarter, with all wells encountering multiple pay sections and uphole Edmonton sands and Horseshoe Canyon Coals. Locations were selected using Compton's seismic and geological models, which have been critical to identifying the better-quality producible zones. A total of approximately 290 Edmonton/Belly River wells are planned for 2007.

Rig release to on-stream timing for the Belly River program is improving as a result of acquiring pipeline surface leases concurrent with well surface leases. A review of the 19 sections that have been drilled by Compton to four wells per section in 2006 indicates that on average the second to fourth wells in the section were on-stream 110 days after rig release, and we continue to improve our tie-in times.

Callum Thrusted Belly River

During the second quarter, we expanded our drilling and exploration plans for this area. We are now planning a follow-up underbalanced extension to the well drilled during the first quarter of 2007, and we have identified two further horizontal locations from existing pads. In 2007, we now plan to drill approximately 5 wells at Callum.

We are working with all stakeholders in the area to proceed in an environmentally responsible manner and we remain committed to minimizing the impact of our activities.

Hooker Basal Quartz

Two wells were drilled during the second quarter targeting the lower Cretaceous Basal Quartz resource play at Hooker. Both wells were successful. To date this year, we have tied-in six wells at Hooker. We plan to drill approximately 18 wells in this area this year.

Central Alberta ---------------

In the second quarter of 2007, we drilled four wells in central Alberta with a 100% success rate.

Niton

We drilled three wells at Niton during the second quarter. All wells were successful, encountering multiple pay zones.

We are aggressively developing the Edson Rock Creek P gas pool through horizontal drilling and expanded compression facilities. As a follow up to our horizontal Edson well 13-10-53-15W5M that is currently producing approximately 6 mmcf/d, we drilled Edson 1-10-53-15W5M. This Rock Creek well recently tested inline at 3 mmcf/d. A multi-stage fracture of the horizontal leg is scheduled for early August. We have five additional horizontal wells into Rock Creek P pool licensed for the third quarter.

To accommodate production volumes from this exciting gas play, we twinned our 100% owned Edson 7-20-53-15W5M compressor station on June 30, 2007. By August 31, 2007, Compton will have twinned a two mile pipeline section south of the Rosevear gas plant to expand current gas handling capability at the 7-20-53-15W5M compressor to 20 mmcf/d. This project is scheduled to be completed by mid-September 2007 to coincide with our drilling plans in the area.

Subsequent to the end of the second quarter, we drilled a successful vertical exploration gas well at Edson 4-31-52-16W5M. Drilling was timed to reach total depth to coincide with a nine section adjacent Crown land sale in mid July. We acquired all nine sections, and are currently developing plans to drill additional horizontal Rock Creek wells.

Peace River Arch ----------------

At Cecil and Worsley, we have increased production from our conventional light oil assets. Regular field operations, delayed during the second quarter by wet field conditions, have resumed including artificial lift modifications resulting in an increase in production to approximately 6,700 boe/d, up from June 2007 average of 5,700 boe/d.

MANAGEMENT'S DISCUSSION AND ANALYSIS -------------------------------------------------------------------------

Management's Discussion and Analysis ("MD&A") is intended to provide both an historical and prospective view of our activities. The MD&A was prepared as at August 13, 2007 and should be read in conjunction with the interim unaudited consolidated financial statements for the six months ended June 30, 2007 and the audited consolidated financial statements for the year ended December 31, 2006, available in printed form on request and posted on Compton'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.

RESULTS OF OPERATIONS Cash Flow from Operations, Operating Earnings, and Net Earnings ------------------------------------------------------------------------- ($000s, except per share Three Months Ended June 30 Six Months Ended June 30 amounts) 2007 2006 Change 2007 2006 Change ------------------------------------------------------------------------- Cash flow from operations(1) $ 48,582 $ 67,326 -28% $ 117,365 $ 140,922 -17% Per share - basic $ 0.38 $ 0.53 -28% $ 0.91 $ 1.11 -18% - diluted $ 0.36 $ 0.50 -28% $ 0.88 $ 1.05 -16% Operating earnings $ 7,364 $ 17,947 -59% $ 25,297 $ 40,191 -37% Net earnings $ 45,307 $ 68,744 -34% $ 59,026 $ 106,746 -50% Per share - basic $ 0.35 $ 0.54 -35% $ 0.46 $ 0.84 -45% - diluted $ 0.34 $ 0.51 -33% $ 0.44 $ 0.80 -45% ------------------------------------------------------------------------- (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 three and six months of 2007 decreased over comparable periods in 2006 due primarily to reduced production volumes. The decrease in production resulted from expected high initial decline rates on new production, reduced field activities, including first half drilling, and weather related delays in placing new drill wells on-stream. The regularly scheduled plant turn around that occurs every three years at Mazeppa further reduced production by approximately 1,600 boe/d for the second quarter.

Net earnings for the three and six months ended June 30, 2007 decreased from comparative periods in 2006 due primarily to decreased production volumes. Year to date earnings have been impacted by unrealized foreign exchange gains, unrealized risk management activities, and the effect of future income tax recoveries resulting from reductions in statutory corporate income tax rates. The impact of these items is summarized in the schedule of Operating Earnings presented below.

OPERATING EARNINGS

Operating earnings is a non-GAAP measure that adjusts net earnings by non-operating items, net of tax, that we believe reduce the comparability of our underlying financial performance between periods. The following reconciliation of operating earnings has been prepared to provide investors with information that is more comparable between periods.

Summary of Operating Earnings ------------------------------------------------------------------------- Three Months Six Months ($000s, except Ended June 30 Ended June 30 per share amounts) 2007 2006 2007 2006 ------------------------------------------------------------------------- Net earnings, as reported $ 45,307 $ 68,744 $ 59,026 $ 106,746 Non-operational items, after tax Unrealized foreign exchange (gain) loss (33,807) (19,573) (38,491) (19,275) Unrealized risk management loss (gain) 59 1,921 11,819 (9,120) Stock-based compensation 1,603 1,513 3,142 3,071 Effect of tax rate changes on future income tax liabilities (5,798) (34,658) (10,199) (41,231) ------------------------------------------------------------------------- Operating earnings $ 7,364 $ 17,947 $ 25,297 $ 40,191 Per share - basic $ 0.06 $ 0.14 $ 0.20 $ 0.32 - diluted $ 0.06 $ 0.13 $ 0.19 $ 0.30 -------------------------------------------------------------------------

The major items impacting operating earnings relate to unrealized foreign exchange gains associated with our U.S. dollar denominated Senior Notes and federal and provincial tax rate changes enacted during the second quarters of 2006 and 2007 (see note 11 of our Financial Statements).

REVENUE ------------------------------------------------------------------------- Three Months Ended June 30 Six Months Ended June 30 2007 2006 Change 2007 2006 Change ------------------------------------------------------------------------- Average production Natural gas (mmcf/d) 130 137 -5% 139 139 0% Liquids (light oil & ngls) (bbls/d) 7,199 9,821 -27% 7,959 10,118 -21% ------------------------------------------------------------------------- Total (boe/d) 28,918 32,645 -11% 31,105 33,333 -7% Benchmark prices AECO ($/GJ) Monthly index $ 7.07 $ 5.95 19% $ 7.03 $ 7.37 -5% Daily index $ 7.00 $ 5.70 23% $ 6.85 $ 6.43 7% WTI (U.S.$/bbl) $ 58.16 $ 70.70 -18% $ 61.60 $ 67.09 -8% Edmonton Par ($/bbl) $ 67.12 $ 78.55 -15% $ 69.51 $ 73.75 -6% Realized prices Natural gas ($/mcf) $ 6.92 $ 5.86 18% $ 7.09 $ 6.79 5% Liquids ($/bbl) 60.49 67.09 -10% 57.74 59.93 -5% ------------------------------------------------------------------------- Total ($/boe) $ 47.94 $ 45.37 6% $ 47.43 $ 46.55 1% Revenue ($000s) Natural gas $ 82,112 $ 73,071 12% $ 178,191 $ 169,653 5% Crude oil and ngls 44,059 61,707 -29% 88,857 113,904 -22% ------------------------------------------------------------------------- Total $ 126,171 $ 134,778 -6% $ 267,048 $ 283,557 -6% -------------------------------------------------------------------------

Production for the three and six months ended June 30, 2007 decreased from the comparative periods largely as a result of reduced drilling during the past three quarters necessary to offset normal tight gas production declines. Tie-in activities were temporarily delayed in the second quarter of 2007 due to an early and extended spring break up, followed by wet weather during the months of May and June.

Total revenue for the second quarter of 2007 decreased from the comparative period in 2006 due to reduced production. Revenue for the six months ended June 30, 2007 was similarly affected.

Approximately 10% of Compton's natural gas production is marketed through aggregator contracts during the quarter, which received a price that was, on average, $1.16/mcf less than prices received on non-aggregator volumes.

ROYALTIES ------------------------------------------------------------------------- Three Months Six Months Ended June 30 Ended June 30 2007 2006 2007 2006 ------------------------------------------------------------------------- Royalties ($000s) $ 23,307 $ 31,465 $ 51,953 $ 66,031 Percentage of revenues 18.5% 23.6% 19.5% 23.5% -------------------------------------------------------------------------

The Alberta royalty structure is based upon commodity prices and well productivity, with higher prices and well productivity attracting higher royalty rates.

The average royalty rate in the second quarter of 2007 was lower than the comparable period in 2006 due to reduced well tie-ins and therefore lower productivity associated with high initial declines of typical resource play wells. Additionally, significant positive annual Alberta royalty adjustments, including gas cost allowance of approximately $2.4 million, reduced the overall royalty rate during the quarter.

OPERATING EXPENSES ------------------------------------------------------------------------- Three Months Six Months Ended June 30 Ended June 30 2007 2006 2007 2006 ------------------------------------------------------------------------- Operating expenses ($000s) $ 23,472 $ 22,839 $ 49,504 $ 44,723 Operating expenses per boe ($/boe) $ 8.92 $ 7.69 $ 8.79 $ 7.41 -------------------------------------------------------------------------

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.

Total operating costs during the second quarter were less than those incurred during the first quarter of 2007, however, on a unit of production basis, they were marginally higher due to lower production volumes and the fixed nature of many of the costs.

TRANSPORTATION EXPENSES ------------------------------------------------------------------------- Three Months Six Months Ended June 30 Ended June 30 2007 2006 2007 2006 ------------------------------------------------------------------------- Transportation expenses ($000s) $ 4,252 $ 3,128 $ 6,734 $ 6,200 Transportation expenses per boe ($/boe) $ 1.62 $ 1.05 $ 1.20 $ 1.03 -------------------------------------------------------------------------

Transportation expenses for the three and six months ended June 30, 2007 were higher than the comparable period due to late trucking charges recognized during the quarter. Trucking charges are expected to decrease in subsequent quarters.

GENERAL AND ADMINISTRATIVE EXPENSES ------------------------------------------------------------------------- Three Months Six Months ($000s, except Ended June 30 Ended June 30 where noted) 2007 2006 2007 2006 ------------------------------------------------------------------------- General and administrative expenses $ 11,431 $ 8,677 $ 20,806 $ 18,564 Capitalized general and administrative expenses (1,404) (518) (3,606) (1,479) Operator recoveries (804) (1,890) (1,568) (4,428) ------------------------------------------------------------------------- Total general and administrative expenses $ 9,223 $ 6,269 $ 15,632 $ 12,657 General and administrative expenses per boe ($/boe) $ 3.50 $ 2.11 $ 2.78 $ 2.10 -------------------------------------------------------------------------

Employee costs associated with increased personnel levels, as well as a general increase in salaries necessary to attract and retain qualified personnel in a very competitive industry, was the major contributor to higher general and administrative expenses in the three and six months ended June 30, 2007. Other increases included costs associated with the current regulatory environment and the acquisition of additional office space.

INTEREST AND FINANCE CHARGES ------------------------------------------------------------------------- Three Months Six Months ($000s, except Ended June 30 Ended June 30 where noted) 2007 2006 2007 2006 ------------------------------------------------------------------------- Interest on bank debt, net $ 6,039 $ 2,673 $ 11,248 $ 5,809 Interest on senior notes 9,798 9,691 20,243 16,487 ------------------------------------------------------------------------- Interest charges $ 15,837 $ 12,364 $ 31,491 $ 22,296 Finance charges 141 1,179 31 1,606 ------------------------------------------------------------------------- Total interest and finance charges $ 15,978 $ 13,543 $ 31,522 $ 23,902 Total interest and finance charges per boe ($/boe) $ 6.07 $ 4.56 $ 5.60 $ 3.96 -------------------------------------------------------------------------

Interest costs in the three and six months ended June 30, 2007 increased from the comparative periods due to higher debt levels. With the sale of our Peace River Arch assets, expected to close during the third quarter of 2007, we anticipate that interest charges will reduce accordingly.

DEPLETION AND DEPRECIATION ------------------------------------------------------------------------- Three Months Six Months Ended June 30 Ended June 30 2007 2006 2007 2006 ------------------------------------------------------------------------- Depletion and depreciation ($000s) $ 35,070 $ 34,866 $ 73,864 $ 69,276 Depletion and depreciation per boe ($/boe) $ 13.33 $ 11.74 $ 13.12 $ 11.48 -------------------------------------------------------------------------

Depletion and depreciation for the second quarter of 2007 was similar to the comparable period in 2006, although it increased on a per unit of production basis reflecting the higher industry cost structure. Currently, with lower industry activity, we are experiencing reduction in certain costs in the 10% to 20% range.

The depletion and depreciation rate in the second quarter of 2007 was consistent with the first quarter of 2007.

INCOME TAXES

Income taxes are recorded using the liability method of accounting. Future income taxes are calculated based on the difference between the accounting and income tax basis of an asset or liability. The classification of future income taxes between current and non-current is based upon the classification of the liabilities and assets to which the future income tax amounts relate. The classification of a future income tax amount as current does not imply a cash settlement of the amount within the following twelve month period.

CAPITAL EXPENDITURES ------------------------------------------------------------------------- Six Months Ended June 30 ($000s) 2007 % 2006 % ------------------------------------------------------------------------- Land and seismic $ 20,750 13 $ 31,972 12 Drilling and completions 88,989 58 157,790 61 Production facilities and equipment 44,067 29 70,321 27 ------------------------------------------------------------------------- Sub-total $ 153,806 100 $ 260,083 100 Property acquisitions (divestitures) net (45,241) 30,091 ------------------------------------------------------------------------- Sub-total $ 108,565 $ 290,174 MPP 3,935 (706) ------------------------------------------------------------------------- Total capital expenditures $ 112,500 $ 289,468 -------------------------------------------------------------------------

Capital expenditures in 2007 have decreased over the comparable period in 2006, reflecting the overall reduction in field activity.

We drilled a total of 84 wells during the six month period ended June 30, 2007, as compared to 179 wells drilled during the first half of 2006.

Revisions to our 2007 capital program were announced in detail in our news release of July 11, 2007. As summarized therein, we are now budgeting total capital expenditures of $450 million for the year, excluding acquisitions and planned dispositions. To June 30, 2007 we have incurred expenditures of $154 million, before acquisitions, or 34% of our planned capital spending for the year.

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 indicates the value of the instrument based upon market conditions existing as of that date. Any change in value from that determined at the end of the prior period is recognized as an unrealized Risk Management gain or loss.

Risk management gains and losses recognized in the quarter are summarized in the following table.

Risk Management (Gains) Losses ------------------------------------------------------------------------- Three Months Six Months Ended June 30 Ended June 30 ($000s) 2007 2006 2007 2006 ------------------------------------------------------------------------- Commodity contracts Realized $ (3,030) $ (9,767) $ (11,783) $ (11,753) Unrealized (3,033) 673 13,453 (18,229) Cross currency interest rate swap Realized 2,899 1,733 2,899 1,733 Unrealized 3,120 3,975 3,958 5,722 Foreign currency contracts Realized 173 (522) 173 (545) Unrealized - (1,715) - (1,414) ------------------------------------------------------------------------- Total risk management $ 129 $ (5,623) $ 8,700 $ (24,486) ------------------------------------------------------------------------- Realized $ 42 $ (8,556) $ (8,711) $ (10,565) Unrealized 87 2,933 17,411 (13,921) ------------------------------------------------------------------------- Total risk management $ 129 $ (5,623) $ 8,700 $ (24,486) ------------------------------------------------------------------------- Outstanding Commodity Contracts

Approximately 35% of current production is hedged for the balance of 2007 and we have begun to enter into hedge contracts relating to 2008 production. We plan to continue to expand this program with a goal of hedging approximately 50% of future production.

The following table outlines commodity hedge contracts which were in place during the second quarter of 2007 and/or 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 Collar Nov. 2007 - March 2008 10,000 GJ/d $7.88 - $10.00 AECO Crude oil Collar Jan. 2007 - Dec. 2007 3,000 bbls/d U.S.$75.00 - WTI $84.55 ------------------------------------------------------------------------- LIQUIDITY AND CAPITAL RESOURCES ------------------------------------------------------------------------- ($000s, except where noted) As at As at June 30, Dec. 31, 2007 2006 ------------------------------------------------------------------------- Working capital (surplus) deficiency(1) $ (21,230) $ 23,163 Bank debt 368,615 328,000 Senior term notes 466,062 524,385 ------------------------------------------------------------------------- Total indebtedness $ 813,447 $ 875,548 ------------------------------------------------------------------------- Shareholders' equity $ 769,941 $ 734,124 Debt to cash flow from operations(2) 3.5 3.4 Debt to book capitalization 51% 54% Debt to market capitalization 33% 39% ------------------------------------------------------------------------- (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 Compton with financial flexibility. Approximately 57% of our existing debt is not due until 2013. With the sale of our Peace River Arch assets, anticipated to close during the third quarter of 2007, we expect bank debt to be reduced significantly, thereby reducing our debt to cash flow ratio and providing us with the necessary liquidity to pursue our drilling programs.

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. Further, our capital expenditures can be readily adjusted as warranted by changing market and industry conditions.

OUTLOOK AND GUIDANCE

As outlined in our July 11, 2007 News release, 2007 Operational Update and Longer-Term Strategic Direction, we have revised our 2007 budget to reflect first half 2007 activities, the proposed acquisition of Stylus Energy Inc., and the divestment of non-core properties including our conventional light oil assets in the Peace River Arch at Cecil and Worsley. Additionally, our revised plans for 2007 reflect an accelerated drilling program during the second half of the year.

We now plan to drill approximately 435 wells during 2007, an increase of 105 wells from our original 2007 budget. Capital expenditures will be approximately $450 million, and cash flow from operations is expected to be in the range of $210 to $220 million. Annual average production is expected to be in the range of 31,000 to 32,000 boe/d, with an average production rate for December 2007 ranging between 37,000 and 38,000 boe/d.

Changes in Internal Control over Financial Reporting

There were no changes during the quarter ended June 30, 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 Q2 Q1 Q4 Q3 ------------------------------------------------------------------------- Total revenue (millions) $ 126 $ 141 $ 130 $ 127 Cash flow from operations (millions) $ 49 $ 69 $ 55 $ 60 Per share - basic $ 0.38 $ 0.53 $ 0.43 $ 0.47 - diluted $ 0.36 $ 0.52 $ 0.42 $ 0.45 Net earnings (millions) $ 45 $ 14 $ (10) $ 31 Per share - basic $ 0.35 $ 0.11 $ (0.08) $ 0.24 - diluted $ 0.34 $ 0.10 $ (0.08) $ 0.23 Operating earnings (millions) $ 7 $ 18 $ 12 $ 13 Production Natural gas (mmcf/d) 130 148 148 142 Liquids (bbls/d) 7,199 8,729 8,600 9,249 ------------------------------------------------------------------------- Total (boe/d) 28,918 33,316 33,245 32,843 Average price Natural gas (mmcf/d) $ 6.92 $ 7.24 $ 6.48 $ 5.38 Liquids (bbls/d) 60.49 54.20 48.44 57.53 ------------------------------------------------------------------------- Total ($/boe) $ 47.94 $ 46.98 $ 42.60 $ 42.03 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 2006 2005 Q2 Q1 Q4 Q3 ------------------------------------------------------------------------- Total revenue (millions) $ 135 $ 149 $ 185 $ 147 Cash flow from operations (millions) $ 67 $ 74 $ 90 $ 74 Per share - basic $ 0.53 $ 0.58 $ 0.71 $ 0.58 - diluted $ 0.50 $ 0.55 $ 0.67 $ 0.56 Net earnings (millions) $ 69 $ 38 $ 38 $ 11 Per share - basic $ 0.54 $ 0.30 $ 0.30 $ 0.09 - diluted $ 0.51 $ 0.28 $ 0.28 $ 0.08 Operating earnings (millions) $ 18 $ 22 $ 33 $ 26 Production Natural gas (mmcf/d) 137 142 133 130 Liquids (bbls/d) 9,821 10,418 8,879 7,351 ------------------------------------------------------------------------- Total (boe/d) 32,645 34,029 31,042 29,041 Average price Natural gas (mmcf/d) $ 5.86 $ 7.58 $ 11.12 $ 8.41 Liquids (bbls/d) 67.09 48.70 58.39 65.20 ------------------------------------------------------------------------- Total ($/boe) $ 45.37 $ 48.58 $ 64.86 $ 54.97 -------------------------------------------------------------------------

In the second quarter of 2007, revenue declined slightly due to reduced production. Net earnings, however, increased compared to the first quarter of 2007, largely due to an unrealized foreign exchange gain.

In the first quarter of 2007, revenue and cash flow from operations increased from the fourth quarter of 2006 due primarily to higher commodity prices. On a quarter over quarter basis, net earnings increased by approximately 240 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 August 13, 2007 and should be read in conjunction with the interim unaudited consolidated financial statements for the six months ended June 30, 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 2007, 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 Compton'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 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. Compton'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 from operations 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) ------------------------------------------------------------------------- June December 30, 2007 31, 2006 ----------- ----------- (unaudited) Assets Current Cash $ 14,279 $ 11,876 Accounts receivable and other 81,201 83,535 Other current assets 31,553 22,869 Unrealized risk management gain (Note 12a) 9,172 22,625 Future income taxes 2,065 1,479 ----------- ----------- 138,270 142,384 Property and equipment 2,015,695 1,977,062 Goodwill 7,914 7,914 Deferred financing charges and other (Note 14) 202 14,144 Deferred risk management loss (Note 12c) - 3,968 ----------- ----------- $2,162,081 $2,145,472 ----------- ----------- ----------- ----------- Liabilities Current Accounts payable $ 105,803 $ 141,443 Unrealized risk management loss (Note 12d) 6,770 4,604 Future income taxes 2,798 7,269 ----------- ----------- 115,371 153,316 Bank debt (Note 3) 368,615 328,000 Senior term notes (Note 4) 466,062 524,385 Asset retirement obligations (Note 6) 31,051 29,791 Unrealized risk management loss (Note 12d) 8,608 6,816 Future income taxes 310,080 302,690 Non-controlling interest (Note 7) 65,353 66,350 ----------- ----------- 1,365,140 1,411,348 ----------- ----------- Shareholders' equity Capital stock (Note 8) 235,103 231,992 Contributed surplus (Note 9a) 20,756 16,974 Retained earnings 541,082 485,158 ----------- ----------- 796,941 734,124 ----------- ----------- $2,162,081 $2,145,472 ----------- ----------- ----------- ----------- 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 Six months ended June 30, June 30, ----------------------- ----------------------- 2007 2006 2007 2006 ----------- ----------- ----------- ----------- Revenue Oil and natural gas revenues $ 126,171 $ 134,778 $ 267,048 $ 283,557 Royalties (23,307) (31,465) (51,953) (66,031) ----------- ----------- ----------- ----------- 102,864 103,313 215,095 217,526 ----------- ----------- ----------- ----------- Expenses Operating 23,472 22,839 49,504 44,723 Transportation 4,252 3,128 6,734 6,200 General and administrative 9,223 6,269 15,632 12,657 Interest and finance charges (Note 5) 15,978 13,543 31,522 23,902 Depletion and depreciation 35,070 34,866 73,864 69,276 Foreign exchange (gain) loss (Note 13) (39,691) (24,066) (45,213) (23,701) Accretion of asset retirement obligations 612 460 1,263 1,028 Stock-based compensation 3,982 2,309 7,248 4,688 Risk management (gain) loss (Note 12e) 129 (5,623) 8,700 (24,486) ----------- ----------- ----------- ----------- 53,027 53,725 149,254 114,287 ----------- ----------- ----------- ----------- Earnings before taxes and non-controlling interest 49,837 49,588 65,841 103,239 ----------- ----------- ----------- ----------- Income taxes (Note 11) Current 10 (403) (3) 11 Future 2,619 (20,256) 3,229 (6,536) ----------- ----------- ----------- ----------- 2,629 (20,659) 3,226 (6,525) ----------- ----------- ----------- ----------- Earnings before non- controlling interest 47,208 70,247 62,615 109,764 Non-controlling interest 1,901 1,503 3,589 3,018 ----------- ----------- ----------- ----------- Net earnings $ 45,307 $ 68,744 $ 59,026 $ 106,746 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- Net earnings per share (Note 10) Basic $ 0.35 $ 0.54 $ 0.46 $ 0.84 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- Diluted $ 0.34 $ 0.51 $ 0.44 $ 0.80 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ------------------------------------------------------------------------- Compton Petroleum Corporation Consolidated Statements of Retained Earnings (unaudited) (thousands of dollars) ------------------------------------------------------------------------- Three months ended Six months ended June 30, June 30, ----------------------- ----------------------- 2007 2006 2007 2006 ----------- ----------- ----------- ----------- Retained earnings, beginning of period As previously reported $ 496,770 $ 397,500 $ 485,158 $ 360,719 Accounting policy adjustments (Note 2) - - (1,320) - ----------- ----------- ----------- ----------- As restated 496,770 397,500 483,838 360,719 Net earnings 45,307 68,744 59,026 106,746 Premium on redemption of shares (Note 8) (995) (743) (1,782) (1,964) ----------- ----------- ----------- ----------- Retained earnings, end of period $ 541,082 $ 465,501 $ 541,082 $ 465,501 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- See accompanying notes to the consolidated financial statements. ------------------------------------------------------------------------- Compton Petroleum Corporation Consolidated Statements of Cash Flow (unaudited) (thousands of dollars) ------------------------------------------------------------------------- Three months ended Six months ended June 30, June 30, ----------------------- ----------------------- 2007 2006 2007 2006 ----------- ----------- ----------- ----------- Operating activities Net earnings $ 45,307 $ 68,744 $ 59,026 $ 106,746 Amortization and other 1,415 672 1,926 1,096 Depletion and depreciation 35,070 34,866 73,864 69,276 Accretion of asset retirement obligations 612 460 1,263 1,028 Unrealized foreign exchange (gain) loss (40,275) (23,660) (45,855) (23,292) Future income taxes 2,619 (20,256) 3,229 (6,536) Unrealized risk management (gain) loss 87 2,933 17,411 (13,921) Stock-based compensation 2,362 2,309 4,629 4,688 Non-controlling interest 1,901 1,503 3,589 3,018 Asset retirement expenditures (516) (245) (1,717) (1,181) ----------- ----------- ----------- ----------- 48,582 67,326 117,365 140,922 Change in non-cash working capital 5,160 (30,519) (1,511) (7,128) ----------- ----------- ----------- ----------- 53,742 36,807 115,854 133,794 ----------- ----------- ----------- ----------- Financing activities Issuance (repayment) of bank debt 55,615 (34,000) 40,615 57,100 Proceeds from share issuances 725 1,547 2,602 2,407 Distributions to partner (2,293) (2,293) (4,586) (4,586) Redemption of common shares (1,173) (854) (2,119) (2,227) Issue costs on senior notes - (3,127) - (3,408) Issuance of senior notes - 174,930 - 174,930 Redemption of senior notes - (7,520) - (7,520) Change in non-cash working capital (11,068) 3,408 (144) 1,959 ----------- ----------- ----------- ----------- 41,806 132,091 36,368 218,655 ----------- ----------- ----------- ----------- Investing activities Property and equipment additions (50,597) (93,834) (156,025) (259,496) Property acquisitions (592) (2,660) (592) (30,191) Property dispositions 572 700 45,833 1,400 Change in non-cash working capital (41,626) (61,216) (39,035) (56,460) ----------- ----------- ----------- ----------- (92,243) (157,010) (149,819) (344,747) ----------- ----------- ----------- ----------- Change in cash 3,305 11,888 2,403 7,702 Cash, beginning of period 10,974 4,768 11,876 8,954 ----------- ----------- ----------- ----------- Cash, end of period $ 14,279 $ 16,656 $ 14,279 $ 16,656 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- See accompanying notes to the consolidated financial statements. ------------------------------------------------------------------------- Compton Petroleum Corporation Notes to the Consolidated Financial Statements (unaudited) (Tabular amounts in thousands of dollars, unless otherwise stated) June 30, 2007 ------------------------------------------------------------------------- 1. Basis of presentation Compton Petroleum Corporation (the "Company") 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 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 contained 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 had no significant impact on the Company's net earnings or cash flows. The impact 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 realized and recorded in net earnings. The Company has determined that it had no other comprehensive income nor accumulated other comprehensive income for the six month period ended June 30, 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 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) ----------- ----------- 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 June 30, 2007 consolidated financial statements. 3. Credit facilities June December 30, 2007 31, 2006 ----------- ----------- Authorized $ 500,000 $ 500,000 ----------- ----------- ----------- ----------- Prime rate $ 30,000 $ 35,000 Bankers' acceptance 340,000 295,000 Discount to maturity (1,385) (2,000) ----------- ----------- Utilized $ 368,615 $ 328,000 ----------- ----------- ----------- ----------- As at June 30, 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 0.75% Bankers' Acceptance rate plus 1.75% LIBOR rate plus 1.75% Margins are determined based on the ratio of total consolidated debt to consolidated cash flow. The facilities reached term on July 4, 2007, and were renewed under the same terms and conditions to July 2, 2008. If not renewed in 2008 they will mature 366 days later on July 3, 2009. 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 June December 30, 2007 31, 2006 ----------- ----------- Senior term notes U.S.$450 million, 7.625% due December 1, 2013 $ 478,530 $ 524,385 Unamortized transaction costs (12,468) - ----------- ----------- Carrying value $ 466,062 $ 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 June 30, 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 reduce 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 Six months ended June 30, June 30, ----------------------- ----------------------- 2007 2006 2007 2006 ----------- ----------- ----------- ----------- Interest on bank debt, net $ 6,039 $ 2,673 $ 11,248 $ 5,809 Interest on senior term notes 9,798 9,691 20,243 16,487 Finance charges 141 1,179 31 1,606 ----------- ----------- ----------- ----------- $ 15,978 $ 13,543 $ 31,522 $ 23,902 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- 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: June December 30, 2007 31, 2006 ----------- ----------- Asset retirement obligations, beginning of period $ 29,791 $ 20,770 Liabilities incurred 939 7,031 Liabilities settled and disposed (942) (267) Accretion expense 1,263 2,257 ----------- ----------- Asset retirement obligations, end of period $ 31,051 $ 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: June December 30, 2007 31, 2006 ----------- ----------- Non-controlling interest, beginning of period $ 66,350 $ 68,898 Earnings attributable to non-controlling interest 3,589 6,623 Distributions to limited partner (4,586) (9,171) ----------- ----------- Non-controlling interest, end of period $ 65,353 $ 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 June 30, 2007 is $16.8 million. The Company has determined that its exposure to loss under these arrangements is minimal, if any. 8. Capital stock Issued and outstanding June 30, 2007 December 31, 2006 ----------------------- ----------------------- Number of Number of shares Amount shares Amount ----------- ----------- ----------- ----------- (000s) (000s) Common shares outstanding, beginning of period 128,503 $ 231,992 127,263 $ 226,444 Shares issued under stock option plan 831 3,449 1,489 5,993 Shares repurchased (186) (338) (249) (445) ----------- ----------- ----------- ----------- Common shares outstanding, end of period 129,148 $ 235,103 128,503 $ 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 six months ended June 30, 2007, the Company purchased for cancellation 186,100 common shares at an average price of $11.39 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 fully exercisable and will expire ten years after the grant date. Options granted under the plan after June 1, 2003 are generally fully exercisable after four years and will expire five years after the grant date. The following tables summarize the information relating to stock options: June 30, 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 1,609 $11.54 2,228 $13.99 Exercised (831) $3.13 (1,489) $3.14 Forfeited (221) $11.65 (574) $10.92 ----------- ----------- ----------- ----------- Outstanding, end of period 12,168 $8.53 11,611 $7.79 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- Exercisable, end of period 7,113 $6.05 6,593 $4.82 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- The range of exercise prices of stock options outstanding and exercisable at June 30, 2007 is as follows: Outstanding Options Exercisable Options ---------------------------------- ------------------------ Weighted average Weighted Weighted Range of Number of remaining average Number of average exercise options contractual exercise options exercise prices outstanding life (years) price outstanding price ------------------------ ----------- ----------- ----------- ------------ (000s) (000s) $1.45 - $3.99 2,670 3.1 $2.72 2,670 $2.72 $4.00 - $6.99 2,135 3.3 $4.93 2,039 $4.89 $7.00 - $9.99 1,255 2.0 $7.74 854 $7.58 $10.00 - $11.99 2,776 3.9 $11.23 521 $10.89 $12.00 - $13.99 1,869 3.2 $12.66 661 $12.55 $14.00 - $18.39 1,463 3.6 $14.68 368 $14.68 ----------- ----------- ----------- ----------- ------------ 12,168 3.3 $8.53 7,113 $6.05 ----------- ----------- ----------- ----------- ------------ ----------- ----------- ----------- ----------- ------------ The Company has recorded stock-based compensation expense in the consolidated statements 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 Six months ended June 30, June 30, ----------------------- ----------------------- 2007 2006 2007 2006 ----------- ----------- ----------- ----------- Weighted average fair value of options granted $5.24 $6.17 $4.38 $7.40 Risk-free interest rate 4.3% 4.3% 4.0% 4.0% Expected life (years) 5.0 5.0 5.0 5.0 Expected volatility 38.6% 43.3% 39.2% 43.9% The following table presents the reconciliation of contributed surplus with respect to stock-based compensation: June December 30, 2007 31, 2006 ----------- ----------- Contributed surplus, beginning of year $ 16,974 $ 9,173 Stock-based compensation expense 4,630 9,121 Stock options exercised (848) (1,320) ----------- ----------- Contributed surplus, end of period $ 20,756 $ 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 June 30, 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 $1.1 million, which is included in accounts payable as at June 30, 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, the Company incurred additional compensation costs of $4.0 million of which $2.6 million was recognized during 2007. Amounts paid under the program were determined in relation to the market value of the Company's capital stock and accordingly have been included in stock based compensation. No further obligation exists pursuant to this program. 10. Per share amounts The following table summarizes the common shares used in calculating net earnings per common share: Three months ended Six months ended June 30, June 30, ----------------------- ----------------------- 2007 2006 2007 2006 ----------- ----------- ----------- ----------- (000s) (000s) (000s) (000s) Weighted average common shares outstanding - basic 129,149 127,726 128,861 127,514 Effect of stock options 4,003 6,013 4,015 6,662 ----------- ----------- ----------- ----------- Weighted average common shares outstanding - diluted 133,152 133,739 132,876 134,176 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- 11. Income taxes The following table reconciles income taxes calculated at the Canadian statutory rates with actual income taxes: Three months ended Six months ended June 30, June 30, ----------------------- ----------------------- 2007 2006 2007 2006 ----------- ----------- ----------- ----------- Earnings before taxes and non-controlling interest $ 49,837 $ 49,588 $ 65,841 $ 103,239 ----------- ----------- ----------- ----------- Canadian statutory rate 32.1% 34.5% 32.1% 34.5% Expected income taxes $ 15,998 $ 17,108 $ 21,135 $ 35,617 Effect on taxes resulting from: Non-deductible crown charges - (111) - 562 Resource allowance - 83 - (206) Non-deductible stock- based compensation 759 770 1,487 1,618 Federal capital tax - (401) - - Effect of tax rate changes (5,798) (34,658) (10,199) (41,231) Non-taxable capital (gains) losses (6,424) (4,083) (7,320) (4,017) Other (1,906) 633 (1,877) 1,132 ----------- ----------- ----------- ----------- Provision for income taxes $ 2,629 $ (20,659) $ 3,226 $ (6,525) ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- Current Income taxes $ 10 $ (2) $ (3) $ 11 Federal capital tax - (401) - - Future 2,619 (20,256) 3,229 (6,536) ----------- ----------- ----------- ----------- $ 2,629 $ (20,659) $ 3,226 $ (6,525) ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- Effective tax rate 5.3% (41.7%) 4.9% (6.3%) ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- The Canadian federal government, during the second quarters of 2007 and 2006, and the Alberta government, during the second quarter of 2006 enacted income tax rate changes. 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 June 30, 2007 are: Mark-to- Daily Market Notional Gain Commodity Term Volume Prices Received (Loss) --------- ---- -------- --------------- -------- Natural gas Apr. 07 Collar - Oct. 07 42,857 mcf $6.94/mcf - $9.14/mcf $ 4,789 Nov. 07 Collar - Mar. 08 9,524 mcf $8.27/mcf - $10.50/mcf 1,363 Crude oil Jan. 07 Collar - Dec. 07 3,000 bbls US$75.00/bbl - US$84.55/bbl 3,020 -------- Unrealized risk management gain $ 9,172 -------- -------- 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 significant 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 June 30, 2007, the Company valued the liability relating to unrealized losses on the swap arrangements to be $15.4 million (December 31, 2006 - $11.4 million) on a mark-to-market basis. The current portion of this amount at June 30, 2007 is $6.8 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: Three months ended June 30, ------------------------------------------------------ Commodity Foreign Interest 2007 2006 Contracts Currency Rate Swap Total Total ---------- ---------- ---------- ---------- ---------- Unrealized Amortization of deferred loss $ - $ - $ - $ - $ 410 Change in fair value (3,033) - 3,120 87 2,523 ---------- ---------- ---------- ---------- ---------- (3,033) - 3,120 87 2,933 Realized Cash settlements (3,030) 173 2,899 42 (8,556) ---------- ---------- ---------- ---------- ---------- Total $ (6,063) $ 173 $ 6,019 $ 129 $ (5,623) ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- Six months ended June 30, ------------------------------------------------------ Commodity Foreign Interest 2007 2006 Contracts Currency Rate Swap Total Total ---------- ---------- ---------- ---------- ---------- Unrealized Amortization of deferred loss $ - $ - $ - $ - $ 821 Change in fair value 13,453 - 3,958 17,411 (14,742) ---------- ---------- ---------- ---------- ---------- 13,453 - 3,958 17,411 (13,921) Realized Cash settlements (11,783) 173 2,899 (8,711) (10,565) ---------- ---------- ---------- ---------- ---------- Total $ 1,670 $ 173 $ 6,857 $ 8,700 $ (24,486) ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- 13. Foreign exchange (gain) loss Amounts charged to foreign exchange (gain) loss during the period ended were as follows: Three months ended Six months ended June 30, June 30, ----------------------- ----------------------- 2007 2006 2007 2006 ----------- ----------- ----------- ----------- Foreign exchange on translation of U.S.$ debt $ (40,275) $ (23,660) $ (45,855) $ (23,292) Other foreign exchange 584 (406) 642 (409) ----------- ----------- ----------- ----------- Total $ (39,691) $ (24,066) $ (45,213) $ (23,701) ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- 14. Deferred financing charges and other June 30, December 2007 31, 2006 ----------- ----------- Deferred financing charges $ - $ 14,008 Other 202 136 ----------- ----------- $ 202 $ 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 Six months ended June 30, June 30, ----------------------- ----------------------- 2007 2006 2007 2006 ----------- ----------- ----------- ----------- Interest paid $ 25,336 $ 18,177 $ 29,517 $ 19,848 Taxes paid $ - $ - $ - $ 180 16. Subsequent events a) Stylus acquisition On June 25, 2007, the Company made an offer to purchase for cash, by way of a take-over bid, all of the issued and outstanding common shares of Stylus Energy Inc. ("Stylus"), a publicly traded petroleum and natural gas company. The value of the offer is approximately $91 million including the assumption of approximately $12 million of net debt. The offer expires on August 14, 2007 unless withdrawn or extended and is subject to certain conditions as outlined in an offering document, dated July 5, 2007, mailed to Stylus shareholders. If all conditions of the offer are satisfied or waived, Compton is obliged to take up and pay for all Stylus shares tendered to the offer within three business days of the satisfaction or waiver of such conditions. b) Property divestments During the quarter, the Company initiated a program to divest of its non-core conventional oil properties at Cecil and Worsley. Under the divestment process, bids for the properties were received on July 31, 2007 and are being evaluated with closing expected by the end of September. 17. 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 August 14, 2007 at 9:30 am (MT) or 11:30 pm (ET) to discuss the Company's 2007 second quarter financial and operating results. To participate in the conference call, please contact the Conference Operator at 9:20 a.m. (MT), ten minutes prior to the call.

Conference Operator Dial-in Number: Toll-Free 1-866-250-4892 Local Toronto: 1-416-644-3426

Audio webcast URL: http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID=1967900

The audio replay will be available two hours after the conclusion of the conference call and will be accessible until August 21, 2007. Callers may dial toll-free 1-877-289-8525 and enter access code 21243010 (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.