Exhibit 99.2
Management’s Discussion & Analysis
This Management’s Discussion and Analysis (“MD&A”) for Compton Petroleum Corporation (“Compton” or the “Corporation”) should be read with the unaudited interim consolidated financial statements for the period ended June 30, 2010, as well as the audited consolidated financial statements and MD&A for the year ended December 31, 2009. Readers should also read the “Forward-Looking Statements” legal advisory contained at the end of this document. Non-GAAP Financial Measures and disclosure regarding use of boe equivalents is contained in the “Advisories” section located at the end of this document.
The interim consolidated financial statements and comparative information has been prepared in accordance with Canadian Generally Accepted Accounting Principles (“GAAP”). This document is dated as at August 5, 2010.
Compton Petroleum Corporation is a public company actively engaged in the exploration, development and production of natural gas, natural gas liquids, and crude oil in western Canada. The Corporation’s strategy is focused on creating value for shareholders by providing appropriate investment returns through the effective development and optimization of assets.
The Corporation’s operations are located in the deep basin fairway of the Western Canada Sedimentary Basin in the province of Alberta. In this large geographical region, Compton currently pursues three deep basin natural gas plays: the Gething/Rock Creek sands at Niton in central Alberta, the Basal Quartz sands at High River in southern Alberta, and the shallower Southern Plains sands in southern Alberta. In addition, the Corporation has an exploratory play at Callum/Cowley/Todd Creek in the Foothills area of southern Alberta. Each of these natural gas plays have multi-zone potential, providing future development and exploration opportunities. Natural gas represents approximately 84% of reserves and production.
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| ($000’s, except per share amounts) | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Average production (boe/d) | | | 19,481 | | | | 21,440 | | | | 19,446 | | | | 22,312 | |
| | | | | | | | | | | | | | | | | |
Capital expenditures(2) | | $ | 8,631 | | | $ | 16,245 | | | $ | 19,374 | | | $ | 32,131 | |
| | | | | | | | | | | | | | | | | |
Cash flow(1)(2) | | $ | 11,162 | | | $ | 9,572 | | | $ | 32,683 | | | $ | 31,613 | |
| Per share: basic | | $ | 0.04 | | | $ | 0.08 | | | $ | 0.12 | | | $ | 0.25 | |
diluted | | $ | 0.04 | | | $ | 0.08 | | | $ | 0.12 | | | $ | 0.25 | |
| | | | | | | | | | | | | | | | | |
Operating loss(1)(2)(3) | | $ | (21,511 | ) | | $ | (14,782 | ) | | $ | (26,283 | ) | | $ | (17,685 | ) |
| | | | | | | | | | | | | | | | | |
Net earnings (loss) (3) | | $ | (52,254 | ) | | $ | 19,848 | | | $ | (35,297 | ) | | $ | 2,480 | |
| Per share: basic | | $ | (0.20 | ) | | $ | 0.16 | | | $ | (0.13 | ) | | $ | 0.02 | |
diluted | | $ | (0.20 | ) | | $ | 0.16 | | | $ | (0.13 | ) | | $ | 0.02 | |
| | | | | | | | | | | | | | | | | |
| Revenue, net of royalties | | $ | 47,270 | | | $ | 52,601 | | | $ | 105,948 | | | $ | 109,461 | |
| | | | | | | | | | | | | | | | | |
Field netback (per boe)(1)(2) | | $ | 17.73 | | | $ | 17.97 | | | $ | 20.07 | | | $ | 19.40 | |
| (1) | Cash flow, operating loss and field netback are non-GAAP measures that are defined in this document |
| (2) | Prior periods have been revised to conform to current period presentation |
| (3) | Three and six months ended June 30, 2010 includes non-recurring costs of $13.3 million related to surplus office lease costs |
| Management’s Discussion & Analysis | - 1 - | Compton Petroleum - Q2 2010 |
North American natural gas prices continued to be at a low point in the price cycle over the second quarter, and expectations are that they will continue to remain depressed over the near term due to excess supplies of natural gas. In this environment, Compton continued its prudent approach in its capital investment decisions and focused its development strategy on optimizing asset value, reducing costs, and carefully managing its capital structure throughout the second quarter of 2010. As a result, Compton improved its operating efficiencies and partially offset the impact of lower natural gas prices on cash flows generated by operations, which remain below normalized levels.
The upper end of Management’s budget expectations was reached during the second quarter as a result of Compton’s focus on improving operational results and reducing costs. Results for the quarter included:
| | • | maintained average production at 19,481 boe/d, compared to 19,411 boe/d in the first quarter 2010 and approximately 1,200 boe/d ahead of plan; |
| | • | decreased operating and administrative expenditures by $2.4 million from the second quarter of 2009; |
| | • | improved drilling processes at Niton resulted in higher average initial production rates and lower drilling costs; |
| | • | the continued focus on well optimization and reliability enhanced base production performance; |
| | • | completed the sale of $115.0 million in assets at Niton effective June 30, 2010 and also, announced an agreement to sell an additional $35.2 million in assets at Gilby, which closed subsequent to the quarter; |
| | • | closed the final 0.75% of the overriding royalty transaction for proceeds of $14.3 million, bringing the total overriding royalty obligation to 5.0% and total proceeds of $95.0 million; |
| | • | strengthened the capital structure through further debt reduction, eliminating the Senior Credit Facility (the “Facility”) balance, and announced a Recapitalization Plan for Compton’s Senior Term Notes (the “Notes”) subsequent to June 30, 2010 (see Liquidity and Capital Resources - Senior Term Notes); |
| | • | reached agreement with the banking syndicate to increase the borrowing limit, extend the term of the Facility and reduce the interest margin by 0.5% from previous levels upon completion of the Recapitalization plan (see Senior Credit Facility); and |
| | • | renegotiated and renewed the Facility. |
Compton’s focus on evaluating assets, drilling and operating practices and implementing cost control initiatives over the past months is resulting in improved returns on investment for the Corporation and its shareholders.
CASH FLOW
Cash flow is considered a non-GAAP measure; it is commonly used in the oil and gas industry and by Compton to assist Management and investors in measuring the Corporation’s ability to finance capital programs and repay its debt. Cash flow 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 GAAP, as an indicator of the Corporation’s performance or liquidity. The following schedule sets out the reconciliation of cash flow from operations to cash flow.
| Management’s Discussion & Analysis | - 2 - | Compton Petroleum - Q2 2010 |
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| (000’s) | | | | | | | | | | | | |
| Cash flow from operating activities | | $ | 5,944 | | | $ | (3,195 | ) | | $ | 29,459 | | | $ | 10,921 | |
| Plus: Terminated surplus office lease costs | | | 13,663 | | | | - | | | | 14,834 | | | | - | |
| Less: Change in non-cash working capital | | | 8,445 | | | | (12,767 | ) | | | 11,610 | | | | (20,692 | ) |
Cash flow(1) | | $ | 11,162 | | | $ | 9,572 | | | $ | 32,683 | | | $ | 31,613 | |
| Per share - basic | | $ | 0.04 | | | $ | 0.08 | | | $ | 0.12 | | | $ | 0.25 | |
- diluted | | $ | 0.04 | | | $ | 0.08 | | | $ | 0.12 | | | $ | 0.25 | |
| (1) | Cash flow is a non-GAAP measure that is defined in this document |
Cash flow for the second quarter of 2010 increased by approximately $1.6 million or 17% compared to 2009 as a result of:
| | • | realized risk management gains of $4.2 million compared to $3.8 million in 2009; |
| | • | higher average realized natural gas prices, excluding financial hedges, which increased 9% to $4.15 per mcf in 2010 compared to $3.80 per mcf in 2009; |
| | • | higher average realized liquids prices, which increased 32% to $66.00 per bbl compared to $49.93 per bbl in 2009; |
| | • | reduced operating and administrative costs, which resulted in savings of approximately $2.4 million in 2010; and |
| | • | strategic review and restructuring costs of $2.3 million in 2009. |
These factors were partially offset by:
| | • | a 9% decline in natural gas production volumes to 98 mmcf/d from 108 mmcf/d in 2009, resulting from normal production declines due to the reduced level of capital expenditures; |
| | • | a 10% decline in liquids production volumes to 3,076 bbls/d from 3,428 bbls/d in 2009, resulting from normal production declines due to the reduced level of capital expenditures; and |
| | • | a $2.5 million increase in asset retirement expenditures for abandonment and reclamation work. |
Cash flow for the six months ended June 30, 2010 increased by $1.1 million from the comparable period in 2009 as a result of:
| | • | higher average realized natural gas prices, excluding financial hedges, which increased 9% to $4.90 per mcf in 2010 compared to $4.51 per mcf in 2009; |
| | • | higher average realized liquids prices, which increased 52% to $66.81 per bbl compared to $43.99 per bbl in 2009; |
| | • | reduced operating and administrative costs, which resulted in savings of approximately $6.5 million in 2010; and |
| | • | strategic review and restructuring costs of $2.8 million in 2009. |
These factors were partially offset by:
| | • | a 13% decline in natural gas production volumes to 98 mmcf/d from 113 mmcf/d in 2009, resulting from normal production declines due to the reduced level of capital expenditures; |
| | • | a 12% decline in liquids production volumes to 3,156 bbls/d from 3,541 bbls/d in 2009, resulting from normal production declines due to the reduced level of capital expenditures; |
| | • | realized risk management gains in 2010 of $4.2 million compared to $13.5 million in 2009; and |
| | • | a $5.7 million increase in asset retirement expenditures for abandonment and reclamation work. |
| Management’s Discussion & Analysis | - 3 - | Compton Petroleum - Q2 2010 |
NET EARNINGS (LOSS)
Net loss for the second quarter of 2010 was $52.3 million, an earnings decrease of $72.1 million when compared to the $19.8 million net earnings in the same period for 2009. In addition to the factors that impacted cash flow, second quarter 2010 results were affected by:
| | • | non-cash unrealized foreign exchange loss of $20.3 million in 2010 compared to gains of $43.9 million in 2009; |
| | • | non-cash unrealized risk management losses of $5.2 million in 2010 compared to $1.8 million in 2009; |
| | • | surplus office lease and related surrender costs in 2010 of $13.7 million; and |
| | • | increased royalty costs in the second quarter of 2010 reflecting the effect of a 5.0% overriding royalty interest on existing production in 2010. In addition, royalty rates were higher due to higher commodity prices and lower gas cost allowance adjustments in 2010 compared to the same period in 2009. |
These factors were partially offset by:
| | • | an increase of $11.6 million in future income tax recoveries during 2010. |
Net loss for the six months ended June 30, 2010 was $35.3 million, an earnings decrease of $37.8 million when compared to the $2.5 million net earnings in the same period for 2009. In addition to the factors that impacted year-to-date cash flow, results were affected by:
| | • | non-cash unrealized foreign exchange losses of $6.3 million in 2010 compared to gains of $27.9 million in 2009; |
| | • | surplus office lease and related surrender costs in 2010 of $14.8 million; |
| | • | the effect of a 5.0% overriding royalty interest on existing production in 2010; and |
| | • | a $4.1 million decrease in future income tax recoveries in 2010. |
| | These factors were partially offset by: |
| | • | non-cash unrealized risk management gains of $9.7 million in 2010 compared to losses of $2.5 million in 2009. |
OPERATING EARNINGS (LOSS)
Operating earnings (loss) is an after tax non-GAAP measure used by the Corporation to facilitate comparability of earnings between periods. Operating earnings is derived by adjusting net earnings for certain items that are largely non-operational in nature, or one-time non-recurring items. Operating earnings (loss) should not be considered more meaningful than or an alterative to net earnings as determined in accordance with GAAP. The following provides the calculation of operating earnings (loss).
| Management’s Discussion & Analysis | - 4 - | Compton Petroleum - Q2 2010 |
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| ($000’s, except per share amounts) | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Net earnings (loss), as reported | | $ | (52,254 | ) | | $ | 19,848 | | | $ | (35,297 | ) | | $ | 2,480 | |
| Non-operational items | | | | | | | | | | | | | | | | |
| Unrealized foreign exchange and other (gain) loss | | | 20,250 | | | | (43,965 | ) | | | 6,300 | | | | (27,945 | ) |
| Unrealized market-to-market hedging (gain) loss | | | 5,252 | | | | 1,829 | | | | (9,725 | ) | | | 2,494 | |
| Other expenses | | | 13,663 | | | | 2,340 | | | | 14,834 | | | | 2,756 | |
| Tax effect | | | (8,422 | ) | | | 5,166 | | | | (2,395 | ) | | | 2,530 | |
Operating loss(1) | | $ | (21,511 | ) | | $ | (14,782 | ) | | $ | (26,283 | ) | | $ | (17,685 | ) |
| Per share - basic | | $ | (0.08 | ) | | $ | (0.12 | ) | | $ | (0.10 | ) | | $ | (0.14 | ) |
- diluted | | $ | (0.08 | ) | | $ | (0.12 | ) | | $ | (0.10 | ) | | $ | (0.14 | ) |
| (1) | Prior periods have been revised to conform to current period presentation |
CAPITAL EXPENDITURES
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| ($000’s) | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Land and seismic | | $ | 1,712 | | | $ | 1,786 | | | $ | 3,577 | | | $ | 4,041 | |
| Drilling and completions | | | 5,285 | | | | 5,406 | | | | 16,507 | | | | 13,143 | |
| Alberta drilling credits | | | (2,741 | ) | | | - | | | | (4,721 | ) | | | - | |
| Production facilities and equipment | | | 6,907 | | | | 2,366 | | | | 10,258 | | | | 6,599 | |
| Asset retirement expenditures | | | (2,875 | ) | | | (406 | ) | | | (6,628 | ) | | | (903 | ) |
| Corporate and other | | | 343 | | | | 7,093 | | | | 381 | | | | 9,251 | |
| Capital investment | | | 8,631 | | | | 16,245 | | | | 19,374 | | | | 32,131 | |
| | | | | | | | | | | | | | | | | |
| Acquisitions | | | | | | | | | | | | | | | | |
| Property | | | 150 | | | | 304 | | | | 150 | | | | 304 | |
| Divestitures | | | | | | | | | | | | | | | | |
| Property | | | (117,501 | ) | | | (1,168 | ) | | | (117,557 | ) | | | (1,168 | ) |
| Overriding royalty | | | (14,289 | ) | | | - | | | | (23,469 | ) | | | - | |
| Acquisitions (divestitures), net | | | (131,640 | ) | | | (864 | ) | | | (140,876 | ) | | | (864 | ) |
| | | | | | | | | | | | | | | | | |
| Net capital expenditures | | $ | (123,009 | ) | | $ | 15,381 | | | $ | (121,502 | ) | | $ | 32,167 | |
Capital spending, before acquisitions and divestitures, decreased by 47% in the second quarter and 40% on a year-to-date basis for 2010 compared to the same periods in 2009. This continued to be lower than anticipated, largely due to the reduced costs of drilling and the deferral of capital expenditures as a result of weather related constraints, the implementation of the Alberta Drilling Credit program in 2010, which further offset capital expenditures, and higher asset retirement costs.
Capital spending was directed towards the development of Compton’s core natural gas plays in the Southern Plains during the second quarter. Compton drilled or participated in a total of 7 wells (6.6 net), all of which were operated, during the second quarter of 2010 as compared to a total of 1 operated well (0.5 net) drilled during 2009.
FREE CASH FLOW
Free cash flow is a non-GAAP measure that Compton defines as cash flow in excess of capital investment, excluding net acquisitions and divestitures, and is used by Management to determine the funds available for other investing activities and/or other financing activities.
Compton’s second quarter 2010 free cash flow surplus of $2.7 million is $10.2 million higher as compared to the second quarter of 2009 due to lower capital expenditures in 2010 and the focused cost reduction initiatives since the strategic review and restructuring completed in 2009. This was partially offset by a reduction in overall sales volumes, and higher asset retirement expenditures. On a year-to-date basis, the same factors affecting the second quarter resulted in a free cash flow surplus of $12.2 million, an increase of $14.6 million over 2009.
| Management’s Discussion & Analysis | - 5 - | Compton Petroleum - Q2 2010 |
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| ($000’s) | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Cash flow | | $ | 11,162 | | | $ | 9,572 | | | $ | 32,683 | | | $ | 31,613 | |
| Less: capital investment | | | (8,631 | ) | | | (17,057 | ) | | | (19,374 | ) | | | (33,937 | ) |
| Free cash flow | | $ | 2,531 | | | $ | (7,485 | ) | | $ | 13,309 | | | $ | (2,324 | ) |
PRODUCTION VOLUMES AND REVENUE
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| | | | | | | | | | | | | |
| Average production | | | | | | | | | | | | |
Natural gas (mmcf/d) | | | 98 | | | | 108 | | | | 98 | | | | 113 | |
Liquids (bbls/d) | | | 3,076 | | | | 3,428 | | | | 3,156 | | | | 3,540 | |
Total (boe/d) | | | 19,481 | | | | 21,440 | | | | 19,446 | | | | 22,312 | |
| | | | | | | | | | | | | | | | | |
| Benchmark prices | | | | | | | | | | | | | | | | |
AECO ($/GJ) | | | | | | | | | | | | | | | | |
| Monthly index | | $ | 3.66 | | | $ | 3.47 | | | $ | 4.37 | | | $ | 4.40 | |
| Daily index | | $ | 3.69 | | | $ | 3.27 | | | $ | 4.19 | | | $ | 3.97 | |
WTI (US$/bbl) | | $ | 78.03 | | | $ | 59.62 | | | $ | 78.37 | | | $ | 51.35 | |
Edmonton sweet light ($/bbl) | | $ | 75.21 | | | $ | 65.90 | | | $ | 77.66 | | | $ | 57.71 | |
| | | | | | | | | | | | | | | | | |
Realized prices(1) | | | | | | | | | | | | | | | | |
Natural gas ($/mcf) | | $ | 4.15 | | | $ | 3.80 | | | $ | 4.90 | | | $ | 4.51 | |
Liquids ($/bbl) | | | 66.00 | | | | 49.93 | | | | 66.81 | | | | 43.99 | |
Total ($/boe) | | $ | 31.41 | | | $ | 27.15 | | | $ | 35.48 | | | $ | 29.76 | |
| | | | | | | | | | | | | | | | | |
Revenue ($000’s)(1) | | | | | | | | | | | | | | | | |
| Natural gas | | $ | 37,210 | | | $ | 37,396 | | | $ | 86,734 | | | $ | 92,005 | |
| Liquids | | | 20,580 | | | | 16,728 | | | | 42,324 | | | | 31,018 | |
| Total | | $ | 57,790 | | | $ | 54,124 | | | $ | 129,058 | | | $ | 123,023 | |
| (1) | Prior periods have been revised to conform to current period presentation |
Production volumes for the second quarter of 2010 were 9% lower than in 2009 primarily due to natural declines and limited new production additions in 2010. While the sale of assets at Niton and Gilby did not materially affect second quarter production in 2010, the sale will reduce future production volumes.
Revenue increased by 7% for the second quarter of 2010 compared to 2009 due to higher realized natural gas and liquids prices, despite lower production volumes. Realized prices and revenues are before any hedging gains or losses. The impact from hedging on realized natural gas prices in the second quarter of 2010 was an increase of $0.40, compared to $0.33 per mcf in 2009.
FIELD NETBACK AND FUNDS FLOW NETBACK
Field netback and funds flow netback are non-GAAP measures used by the Corporation to analyze operating performance. Field netback equals the total petroleum and natural gas sales, including realized gains and losses on commodity hedge contracts, less royalties and operating and transportation expenses, calculated on a $/boe basis. Funds flow netback equals field netback less administrative and interest costs. Field netback and funds flow netback should not be considered more meaningful than or an alterative to net earnings (loss) as determined in accordance with GAAP. The following provides the calculation of field netback and funds flow netback.
| Management’s Discussion & Analysis | - 6 - | Compton Petroleum - Q2 2010 |
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| ($/boe) | | | | | | | | | | | | |
Realized price(1) | | $ | 31.41 | | | $ | 27.15 | | | $ | 35.48 | | | $ | 29.76 | |
| Processing revenue | | | 1.19 | | | | 0.59 | | | | 1.18 | | | | 0.70 | |
| Realized commodity hedge gain (loss) | | | 2.38 | | | | 1.95 | | | | 1.20 | | | | 3.33 | |
| Royalties | | | (5.72 | ) | | | (0.78 | ) | | | (6.46 | ) | | | (3.36 | ) |
| Operating expenses | | | (10.46 | ) | | | (10.01 | ) | | | (10.37 | ) | | | (10.15 | ) |
| Transportation | | | (1.07 | ) | | | (0.93 | ) | | | (0.96 | ) | | | (0.88 | ) |
| Field netback | | $ | 17.73 | | | $ | 17.97 | | | $ | 20.07 | | | $ | 19.40 | |
| | | | | | | | | | | | | | | | | |
| Administrative | | | (3.21 | ) | | | (3.66 | ) | | | (3.19 | ) | | | (3.28 | ) |
| Interest | | | (7.24 | ) | | | (7.55 | ) | | | (7.65 | ) | | | (7.09 | ) |
| Funds flow netback | | $ | 7.28 | | | $ | 6.76 | | | $ | 9.23 | | | $ | 9.03 | |
(1) Prior periods have been revised to conform to current period presentation
ROYALTIES
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| | | | | | | | | | | | | |
Crown royalties(1) | | $ | 4,198 | | | $ | (2,504 | ) | | $ | 8,059 | | | $ | 4,173 | |
| Overriding royalty | | | 2,782 | | | | - | | | | 5,488 | | | | - | |
| Other royalties | | | 3,160 | | | | 4,027 | | | | 9,183 | | | | 9,389 | |
| Net royalties | | $ | 10,140 | | | $ | 1,523 | | | $ | 22,730 | | | $ | 13,562 | |
| Percentage of revenues | | | 17.5 | % | | | 2.8 | % | | | 17.6 | % | | | 11.0 | % |
(1) Crown royalties are presented net of any gas cost allowance
Royalties as a percentage of revenues increased for both the second quarter of 2010 and on a year-to-date basis compared to 2009. Crown royalties have increased as a result of a reduction in the gas cost allowance in the second quarter of 2010 compared to 2009 of $4.8 million arising from a reduction in the Corporation’s capital expenditure program with the effect of increase the average crown royalty rate. The overriding royalty took effect for the fourth quarter of 2009 arising from the sale of an overriding royalty right to a third party.
In March 2010, the Alberta government announced changes to its royalty framework following a competitive review process. These changes result in a reduction of future royalty rates beginning in January 2011. These rate reductions are focused on lowering the progressive royalty rates applicable in a higher commodity price environment than that being experienced by the Corporation under current economic conditions. This change is not anticipated to have a near term impact on the Corporation given its current production profile and the outlook for gas prices remaining in the low range of the gas price cycle.
OPERATING EXPENSES
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| | | | | | | | | | | | | |
Operating expenses ($000’s) | | $ | 18,544 | | | $ | 19,529 | | | $ | 36,484 | | | $ | 40,998 | |
Operating expenses ($/boe) | | $ | 10.46 | | | $ | 10.01 | | | $ | 10.37 | | | $ | 10.15 | |
Operating expenses per boe for both the second quarter and the first six months of 2010 have increased from the comparable periods in 2009 4% and 2%, respectively. The increases were a result of reduced production levels in 2010, which increases were partially offset by cost savings arising from the cost control initiatives implemented in 2010.
| Management’s Discussion & Analysis | - 7 - | Compton Petroleum - Q2 2010 |
TRANSPORTATION
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| | | | | | | | | | | | | |
Transportation costs ($000’s) | | $ | 1,893 | | | $ | 1,822 | | | $ | 3,392 | | | $ | 3,548 | |
Transportation costs ($/boe) | | $ | 1.07 | | | $ | 0.93 | | | $ | 0.96 | | | $ | 0.88 | |
Pipeline tariffs and trucking rates for liquids are primarily dependent upon production location and distance from the sales point. Regulated pipelines transport natural gas within Alberta at tolls approved by the government. Compton incurs charges for the transportation of its production from the wellhead to the point of sale.
Transportation expenses per boe increased by 15% in the second quarter of 2010, and 9% on a year-to-date basis, over the comparable periods in 2009. The increases result from an overall reduction in pipelined production volumes for 2010, and increased trucked liquids volumes related to total volumes in specific producing areas during the second quarter of 2010.
ADMINISTRATIVE EXPENSES
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| | | | | | | | | | | | | |
| Gross administrative expenses | | $ | 7,736 | | | $ | 8,602 | | | $ | 15,883 | | | $ | 17,172 | |
| Capitalized administrative expenses | | | (1,016 | ) | | | (589 | ) | | | (2,563 | ) | | | (1,719 | ) |
| Operator recoveries | | | (1,030 | ) | | | (863 | ) | | | (2,081 | ) | | | (2,218 | ) |
Administrative expenses ($000’s) | | $ | 5,690 | | | $ | 7,150 | | | $ | 11,239 | | | $ | 13,235 | |
Administrative expenses ($/boe) | | $ | 3.21 | | | $ | 3.66 | | | $ | 3.19 | | | $ | 3.56 | |
Administrative expenses per boe decreased in both the second quarter of 2010 and on a year-to-date basis for 2010 as compared to the same periods in 2009. The 12% and 10% respective reductions were primarily as a result of cost control initiatives following the strategic review completed in 2009. The overall reductions were despite the impact of reduced production volumes for 2010.
STOCK-BASED COMPENSATION
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| ($000’s) | | | | | | | | | | | | |
| Stock option plan | | $ | 797 | | | $ | 848 | | | $ | 1,225 | | | $ | 1,103 | |
Employee share purchase plan(1) | | | 267 | | | | 182 | | | | 551 | | | | 777 | |
| Stock-based compensation | | $ | 1,064 | | | $ | 1,030 | | | $ | 1,776 | | | $ | 1,880 | |
(1) Number of shares purchased (2010 - 296,402; 2009 - 435,334)
The Corporation has instituted various compensation arrangements, the value of which is determined in relation to the market value of Compton’s capital stock. These arrangements are designed to attract, motivate and retain individuals, and to align their success with that of shareholders. Details relating to stock-based compensation arrangements are presented in Note 9 to the unaudited interim consolidated financial statements.
| Management’s Discussion & Analysis | - 8 - | Compton Petroleum - Q2 2010 |
OTHER EXPENSES
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| ($000’s, except where noted) | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Terminated surplus office lease costs | | $ | 13,663 | | | $ | - | | | $ | 14,834 | | | $ | - | |
| Strategic review and restructuring costs | | | - | | | | 2,340 | | | | - | | | | 2,756 | |
Total costs ($000’s) | | $ | 13,663 | | | $ | 2,340 | | | $ | 14,834 | | | $ | 2,756 | |
Total costs ($/boe) | | $ | 7.71 | | | $ | 1.20 | | | $ | 4.21 | | | $ | 0.68 | |
Surplus office lease costs relate to the rent on unused office space and a one time payment of $11.6 million to return unused office space to the landlord, terminating the Corporations obligation under the lease for the space. The office lease surrender payment reduces the rent obligation in future periods.
The strategic review and restructuring process undertaken by Management was completed in 2009.
INTEREST AND FINANCE CHARGES
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| ($000’s, except where noted) | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Interest on senior credit facility, net | | $ | 1,326 | | | $ | 2,214 | | | $ | 2,678 | | | $ | 4,266 | |
| Interest on senior term notes | | | 9,267 | | | | 10,484 | | | | 18,644 | | | | 21,658 | |
| Interest expense | | | 10,593 | | | | 12,698 | | | | 21,322 | | | | 25,924 | |
| Finance charges and amortization of transaction cost | | | 2,308 | | | | 2,026 | | | | 5,655 | | | | 2,717 | |
Total interest and finance charges ($000’s) | | $ | 12,901 | | | $ | 14,724 | | | $ | 26,977 | | | $ | 28,641 | |
Total interest and finance charges ($/boe) | | $ | 7.28 | | | $ | 7.55 | | | $ | 7.66 | | | $ | 7.09 | |
Interest expense for the second quarter of 2010 decreased by 17% and 18% for the first six months of 2010 compared to the same period in 2009. Although interest rates increased in 2010, the overall decrease was as a result of reduced borrowings on the revolving Facility and lower interest related to the US dollar denominated Notes resulting from a strengthening of the Canadian dollar in relation to the US dollar.
Finance charges and amortization of transaction costs for the second quarter of 2010 increased by 14% compared to the same period in 2009, and on a year to date basis by 108% as a result of higher fees for unutilized credit.
Total interest and finance charges increased on a per boe basis in 2010 due to reduced production volumes.
Effective interest rates on a weighted average debt basis are presented below.
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| ($000’s, except where noted) | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Senior credit facility | | $ | 85,868 | | | $ | 316,429 | | | $ | 93,153 | | | $ | 316,243 | |
| Effective interest rate | | | 6.18 | % | | | 3.71 | % | | | 4.46 | % | | | 3.15 | % |
| | | | | | | | | | | | | | | | | |
| Senior note (US$) | | $ | 450,000 | | | $ | 450,000 | | | $ | 450,000 | | | $ | 450,000 | |
| Coupon rate (US$) | | | 7.625 | % | | | 7.625 | % | | | 7.625 | % | | | 7.625 | % |
| Effective interest rate (Cdn$) | | | 8.150 | % | | | 8.150 | % | | | 8.150 | % | | | 8.150 | % |
| Management’s Discussion & Analysis | - 9 - | Compton Petroleum - Q2 2010 |
RISK MANAGEMENT
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| ($000’s, except where noted) | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Commodity contracts | | | | | | | | | | | | |
| Realized (gain) loss | | $ | (4,213 | ) | | $ | (3,800 | ) | | $ | (4,220 | ) | | $ | (13,455 | ) |
| Unrealized (gain) loss | | | 5,264 | | | | 1,829 | | | | (9,725 | ) | | | 2,494 | |
| Foreign currency contracts | | | | | | | | | | | | | | | | |
| Unrealized (gain) loss | | | (12 | ) | | | - | | | | - | | | | - | |
| Total risk management (gain) loss | | $ | 1,039 | | | $ | (1,971 | ) | | $ | (13,945 | ) | | $ | (10,961 | ) |
| | | | | | | | | | | | | | | | | |
| Realized (gain) loss | | $ | (4,213 | ) | | $ | (3,800 | ) | | $ | (4,220 | ) | | $ | (13,455 | ) |
| Unrealized (gain) loss | | | 5,252 | | | | 1,829 | | | | (9,725 | ) | | | 2,494 | |
| Total risk management (gain) loss | | $ | 1,039 | | | $ | (1,971 | ) | | $ | (13,945 | ) | | $ | (10,961 | ) |
The Corporation’s financial results are impacted by external market risks associated with fluctuations in commodity prices, interest rates, and the Canadian/US dollar exchange rate. Compton utilizes various financial instruments for non-trading purposes to manage and mitigate exposure to these risks. Financial instruments are not designated for hedge accounting and accordingly are recorded at fair value on the consolidated balance sheets, with subsequent changes recognized in consolidated net earnings (loss) and other comprehensive income.
Financial instruments utilized 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 realized risk management gain or loss at the time of settlement.
The mark-to-market values of financial instruments outstanding at the end of a reporting period reflect the values of the instruments based upon market conditions existing as of that date. Any change in the fair values of the instruments from that determined at the end of the previous reporting period is recognized as an unrealized risk management gain or loss. Unrealized risk management gains or losses may or may not be realized in subsequent periods depending upon subsequent moves in commodity prices, interest rates or exchange rates affecting the financial instruments.
Commodity hedges were put in place so that the Corporation has natural gas hedged for 40,250 giga joules (“GJ”) per day between an equivalent AECO floor price of $4.50 per GJ and a ceiling price of $7.02 per GJ. The Corporation has also entered into electricity hedges for a total of 84 mega watt hours (“MWh”) per day at a fixed price of $50.74/MWh. These hedges will be in effect throughout 2010 and 2011 as follows:
| Commodity | Term | Volume | Average Price | Index |
| | | | | |
| Natural gas | | | | |
| Collars | Jul./09 - Jun./11 | 30,250 GJ/d | $4.52 - $7.02/GJ | AECO |
| Collars | Jul./09 - Oct./11 | 10,000 GJ/d | $4.50 - $7.00/GJ | AECO |
| Electricity | | | | |
| Swap | Jan./10 - Dec./11 | 84 MWh/d | $50.74/MWh | AESO |
DEPLETION AND DEPRECIATION
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| | | | | | | | | | | | | |
Total depletion and depreciation ($000’s) | | $ | 34,262 | | | $ | 33,789 | | | $ | 68,365 | | | $ | 69,347 | |
Depletion and depreciation ($/boe) | | $ | 19.33 | | | $ | 17.32 | | | $ | 19.42 | | | $ | 17.17 | |
| Management’s Discussion & Analysis | - 10 - | Compton Petroleum - Q2 2010 |
Total depletion and depreciation expense remained relatively unchanged during the second quarter and for the year-to-date for 2010 as compared to the same periods in 2009. The impact of reductions in the Corporation’s overall depletable base following the sales of properties and the overriding royalty interest were offset by the increased depletion rate derived from reserve balances. On a per boe basis, the lower production volumes have increased depletion and depreciation expense by 12% in the second quarter of 2010, and 13% year to date, over the same periods in 2009.
FOREIGN EXCHANGE AND OTHER GAINS AND LOSSES
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| ($000’s) | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Foreign exchange (gain) loss on translation of US$ debt | | $ | 20,250 | | | $ | (43,965 | ) | | $ | 6,300 | | | $ | (27,945 | ) |
| Other foreign exchange (gain) loss | | | 197 | | | | (292 | ) | | | (62 | ) | | | (80 | ) |
| Marketable securities valuation (gain) loss | | | - | | | | (253 | ) | | | (1,861 | ) | | | 253 | |
| Total foreign exchange and other (gains) losses | | $ | 20,447 | | | $ | (44,510 | ) | | $ | 4,377 | | | $ | (27,772 | ) |
The foreign exchange losses recognized in the consolidated statements of earnings (loss) in 2010 resulted primarily from the translation of the US dollar denominated Notes into Canadian dollars with the weakening of the Canadian dollar. The Notes are translated and recorded in the financial statements at the period end exchange rate, with any change from prior periods being recognized as an unrealized foreign exchange gain or loss. The year to date loss for 2010 was partially offset by the gain on sale of certain marketable securities.
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.
Income tax recoveries of $11.8 million were recognized in the second quarter of 2010 as compared to $2.8 million for the comparable period in 2009. The $9.0 increase in 2010 arises as a result of higher operating losses, the change in timing for future settlement of tax assets and liabilities, and the change in tax rates applied.
| III. | Liquidity and Capital Resources |
CAPITAL STRUCTURE
The Corporation’s capital structure is comprised of Notes, Facility, working capital, MPP term financing and shareholders’ equity. The Corporation’s objectives when managing its capital structure are to:
| | (a) | ensure the Corporation can meet its financial obligations; |
| | (b) | retain an appropriate level of leverage relative to the risk of Compton’s underlying assets; and |
| | (c) | finance internally generated growth and potential acquisitions. |
Compton manages its capital structure based on changes in economic conditions and the Corporation’s planned capital requirements. Compton has the ability to adjust its capital structure by making modifications to its capital expenditure program, divesting of assets and by issuing new debt or equity.
| Management’s Discussion & Analysis | - 11 - | Compton Petroleum - Q2 2010 |
The Corporation monitors its capital structure and financing requirements using non-GAAP measures consisting of total net debt to capitalization and total net debt to “Adjusted EBITDA”. Adjusted EBITDA is a non-GAAP measure defined as net earnings (loss) before interest and finance charges, income taxes, depletion and depreciation, accretion of asset retirement obligation, goodwill written-off, unrealized foreign exchange and other gains (losses), and unrealized risk management gains (losses). Capitalization is a non-GAAP measure defined as working capital, long-term debt including current portion, MPP term financing, and shareholders' equity. Debt to capitalization and debt to adjusted EBITDA are two ratios that Management uses to steward the Corporation’s overall debt position as measures of C ompton’s overall financial strength.
| | | As at June 30, 2010 | | | As at December 31, 2009 | |
| | | | | | | |
Working capital (surplus) deficit(1) | | $ | (18,346 | ) | | $ | 7,294 | |
Senior credit facility(2) | | | - | | | | 107,183 | |
MPP term financing(3) | | | 48,796 | | | | 51,408 | |
Senior term notes(4) | | | 469,061 | | | | 461,741 | |
| Total net debt | | | 499,511 | | | | 627,626 | |
| Shareholders’ equity | | | 958,170 | | | | 992,237 | |
| Total capitalization | | $ | 1,457,681 | | | $ | 1,619,863 | |
| | | | | | | | | |
Total net debt to adjusted EBITDA(5) | | | 4.3 | x | | | 5.9 | x |
| Total net debt to total capitalization | | | 34 | % | | | 39 | % |
| (1) | Adjusted working capital excludes risk management, future income taxes, current MPP term financing and the Facility |
| (2) | Includes unamortized transaction costs of $nil (2009 - $1,279) |
| (3) | Includes unamortized financing fees of $600 (2009 - $679) |
| (4) | Includes unamortized discounts and related transaction costs of $8,209 (2009 - $9,229) |
| (5) | Based on trailing 12 month adjusted EBITDA |
Of total net debt, 94% is comprised of Notes that mature on December 1, 2013 and 10% relates to the MPP term financing, $27.2 million of which matures on April 30, 2014.
WORKING CAPITAL
Excluding the impact of current hedging assets and liabilities, Compton had a working capital surplus of $18.3 million at June 30, 2010, as compared to a deficit of $7.3 million as at December 31, 2009. The main source of the working capital surplus relates to cash received from the asset sale completed at June 30, 2010. Typically in the oil and gas industry, there is not a direct correlation between amounts receivable from the sale of production and trade payables, which results from operating activities that vary seasonally and also with activity levels. This will result in fluctuations in working capital and often result in a working capital deficit. Management anticipates that the Corporation will continue to meet the payment terms of suppliers.
SENIOR CREDIT FACILITY
At June 30, 2010 the Facility was renewed for a period of 366 days until July 1, 2011. The renewed Facility, reflecting the full 5.0% sale of an overriding royalty, and the asset dispositions announced in June 2010 has a limit of $150 million, comprised of $120 million in a revolving term facility, and $30 revolving term working capital facility. The Facility is subject to re-determination of the borrowing base twice a year at December 31 and May 31. The borrowing base of the facilities is determined based on, among other things, the Corporation’s current reserve report, results of operations, the lenders view of the current and forecasted commodity prices and the current economic environment. The Corporation had $nil drawn on its Facility at June 30, 2010.
The Facility provides that advances may be made by way of prime loans, bankers’ acceptances, US base rate loans, LIBOR loans and letters of credit. Advances will bear interest at the applicable lending rate plus a margin based on Compton’s debt to trailing cash flow ratio. The Facility is secured by a fixed and floating charge debenture on the assets of the Corporation.
| Management’s Discussion & Analysis | - 12 - | Compton Petroleum - Q2 2010 |
Conditional on completion of the Recapitalization Plan, see Outlook, the Facility’s bank syndicate has agreed:
| | (a) | to increase the Facility to $225.0 million, comprised of a revolving term facility authorized at $210.0 million and a revolving working capital facility authorized at $15.0 million; |
| | (b) | reduce the interest margins by 0.50% from previous levels; and |
| | (c) | change the tenor of the Facility such that if not extended at lenders option in 2011 the undrawn portion of the Facility will be cancelled and the amount outstanding will convert to a 365 day non-revolving term facility. The amounts outstanding under the non-revolving term facility are required to be repaid at the end of the term facility being July 1, 2012. |
SENIOR TERM NOTES
Notes due in 2013 are payable in US dollars and are translated into Canadian dollars at the period end 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 June 30, 2010, the carrying value of the Notes increased by $6.3 million from December 31, 2009 as a result of the unrealized loss on translation at June 30, 2010.
The indenture governing the Notes limits the extent to which Compton can incur incremental debt and requires the Corporation to meet a fixed charge coverage ratio test (“Ratio”) and ACNTA test if the Ratio test is not met. At each quarter end, the Ratio must exceed a trailing four quarters 2.5 to 1 threshold. If the Ratio is less than 2.5 to 1 the amount of debt that the Corporation may incur in addition to the Notes is limited to the value calculated under the ACNTA test. At June 30, 2010, the Ratio was 1.78 to 1, falling below the minimum requirement. The Corporation may incur up to $266.4 million of debt, plus certain other permitted debt until the time when the ratio exceeds 2.5 to 1. Management does not anticipate these restrictions to have any limiting or adverse effect on the operations of the Corporation (see “risks - liquidity risk”).
Subsequent to June 30, 2010, the Corporation announced a proposed Recapitalization Plan affecting the Notes; see Outlook.
MPP TERM FINANCING
On April 30, 2009, Compton completed the renegotiation of the MPP processing and other related agreements for a further term of five years, expiring on April 30, 2014. In connection with the renewal, the Corporation has reclassified a portion of the non-controlling interest associated with MPP as MPP term financing. MPP term financing in the aggregate amount of $49.4 million is included as a liability in the interim unaudited consolidated financial statements. The fixed base fee payments under the MPP term financing includes a principal and interest component. The effective rate of interest is 10.24% per annum. The principal amount of the MPP term financing is equal to the purchase option price of the MPP partnership units at the end of the five-year term.
DEBT REPAYMENT AND LEASE OBLIGATIONS
As part of normal business operations, Compton has entered into arrangements and incurred obligations that will impact future operations and liquidity, some of which are reflected as liabilities in the unaudited interim consolidated financial statements. The following table summarizes all contractual obligations as at June 30, 2010.
| Management’s Discussion & Analysis | - 13 - | Compton Petroleum - Q2 2010 |
| | | 2010 | | | 2011 | | | 2012 | | | 2013 | | | 2014 | | | Thereafter | |
| | | | | | | | | | | | | | | | | | | |
| Senior term notes (US $450 mm) | | $ | - | | | $ | - | | | $ | - | | | $ | 477,270 | | | $ | - | | | $ | - | |
MPP term financing(1) | | | 4,951 | | | | 9,592 | | | | 9,592 | | | | 9,592 | | | | 30,397 | | | | - | |
| Accounts payable | | | 62,887 | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Operating leases | | | 2,675 | | | | 809 | | | | 1,009 | | | | - | | | | - | | | | - | |
| Office facilities | | | 1,895 | | | | 3,836 | | | | 3,937 | | | | 4,061 | | | | 4,112 | | | | 16,386 | |
Surplus office space(2) | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | $ | 72,408 | | | $ | 14,237 | | | $ | 14,538 | | | $ | 490,923 | | | $ | 34,509 | | | $ | 16,386 | |
| (1) | Represents monthly fixed base fee payments |
| (2) | Management has completed the surrender of certain surplus office space, and has fully recognized the associated costs at June 30, 2010 |
Subsequent to June 30, 2010, the Corporation announced a proposed Recapitalization Plan affecting the Notes. The Recapitalization Plan proposes to exchange all of the existing US$450.0 million Notes for a combination of:
| | a) | US$193.5 million 10% notes due 2017 (the “New Notes”); |
| | b) | US$184.5 million of cash; and |
| | c) | US$45.0 million 10% notes due September 2011 (the “Mandatory Convertible Notes”) |
The exchange of all of the Corporation’s Notes under the Recapitalization Plan is proposed to be completed pursuant to the Plan of Arrangement (the “Arrangement”) under the Canada Business Corporations Act which includes the calling a meeting of noteholders. The meeting date for noteholders to vote on the Arrangement has been set for September 14, 2010. The Arrangement will require the approval of two-thirds of the votes cast by noteholders present in person or by proxy at the Meeting and who are entitled to vote on the Arrangement resolution. Subject to receiving the required approvals and to other conditions, it is anticipated that the effective date of the Arrangement will be on or about September 15, 2010.
Management and the Board of Directors believe that the Recapitalization Plan will provide the following key benefits to the Corporation:
| • | Additional improvement in financial strength through debt reduction of approximately $217.4 million from approximately $599.0 million to $381.6 million, significantly reducing debt service obligations; |
| • | Compton’s banking syndicate has indicated its support for the Recapitalization by agreeing, conditional upon the completion of the Arrangement, to an increase in the Facility to $225.0 million (from $150.0 million previously), to extend the term of the Facility, and reduce the interest margin by 0.5% from previous levels through the addition of two new members to the syndicate; and |
| • | The Corporation will be able to turn its full attention to its asset base, targeting production and cash flow growth through the internal development of its asset base and accretive acquisition opportunities. |
The Recapitalization is the final step in the repositioning of Compton’s capital structure, providing manageable debt levels going forward. Management will now focus on its strategic growth plan, maximizing the value of its asset base.
The current unfavourable outlook for natural gas in North America is expected to continue to impact the Corporation’s cash flows levels. This is expected to be somewhat offset by better than anticipated volumes and initial production rates as well as reduced costs.
| Management’s Discussion & Analysis | - 14 - | Compton Petroleum - Q2 2010 |
Management remains committed to maintaining its financial prudence and improving its capital efficiencies, focusing on proving the value of other key areas and horizons in Compton’s asset base. Management will apply the knowledge gained at Niton to the drilling of horizontal multiple-stage fracture wells at High River over the second half of 2010, as well as to target undeveloped formations to identify new growth opportunities in Niton and the Southern Plains. The results of these activities are expected to prove the underlying value and development potential of Compton’s large asset base, and provide solid returns in a conservative natural gas price environment to its shareholders.
Compton’s guidance for 2010 anticipated natural gas prices of $4.70/GJ (AECO). As a result, the following is Compton’s guidance for 2010:
| | | Current Expectation | | |
| Average daily production (boe/d) | | High end of range(1) | | 16,000 - 16,500 |
| Administrative expenses ($ millions) | | Low end of range(1) | | $25 - $27 |
| Operating costs ($ millions) | | Low end of range(1) | | $80 - $85 |
Cash flow (2) ($ millions) | | High end of range(1) | | $40 - $50 |
Capital expenditures(3) ($ millions) | | | | $60 - $70 |
| (1) | While maintaining guidance in the interim, Management expects further improvements in increasing production and reducing costs |
| (2) | A $0.25 change in the AECO natural gas price is expected to result in a $7.0 million change in cash flow |
| (3) | Includes development and corporate capital requirements |
Compton's 2010 guidance is based on forecast prices of $4.70/GJ of natural gas (AECO), $78.39 per barrel of crude oil (Edmonton Sweet Light), and a foreign exchange rate of $0.99. A $0.25 change in the AECO natural gas price is expected to result in a $6.3 million change in cash flow.
INTERNAL AUDIT FUNCTION
Reporting directly to the Audit Finance and Risk committee, the Manager of Internal Audit is responsible for oversight of the Corporations control environment and provides quarterly updates regarding the degree of compliance and any changes in the internal controls over financial reporting.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
There were no changes to internal control over financial reporting during the period beginning on April 1, 2010 and ending on June 30, 2010 that materially affected or are reasonably likely to materially affect Compton’s internal control over financial reporting.
The following is a list of key risks that Compton faces in its normal course of business. If any of these risks actually occur, Compton’s business, financial condition, results of operations, cash flows and prospects could be harmed.
Such risks and uncertainties are not the only ones the Corporation faces. Additional risks and uncertainties, including those of which Management is currently unaware or that are deemed immaterial, may also adversely affect Compton’s business, financial condition, results of operations, cash flows and prospects. For a more detailed discussion of risks refer to our annual MD&A document for the year ended December 31, 2009.
| Management’s Discussion & Analysis | - 15 - | Compton Petroleum - Q2 2010 |
GLOBAL FINANCIAL CONDITION
Operations are affected by local, national and worldwide economic conditions and the condition of the oil and gas industry. Recent disruptions in the credit markets and concerns about the global economy have had an adverse impact on global financial markets. These and other factors may affect Compton’s ability to obtain equity or debt financing in the future on favourable terms. Additionally, these factors, as well as other related factors, may cause decreases in the Corporation’s asset values that may be other than temporary, which may result in impairment losses. If such increased levels of volatility and market turmoil continue, or if more extensive disruptions of the global financial markets occur, operations could be adversely impacted and the trading price of Compton’s common sh ares may be adversely affected.
ADDITIONAL FUNDING REQUIREMENTS
Compton’s ongoing activities may not generate sufficient cash flow from operations to fund future exploration, development, or acquisition programs. The Corporation may require additional funding and there can be no assurance that debt or equity financing will be available or sufficient to meet these requirements or that it will be on acceptable terms. Continued uncertainty in domestic and international credit markets compounds the risk of obtaining debt financing. Failure to obtain such financing on a timely basis could cause Compton to forfeit interests in certain properties, miss certain acquisition opportunities, and reduce or terminate operations. This may result in the Corporation not being able to replace its reserves or maintain production, which will have an adverse effect on its financi al position. Failure to obtain additional funding may also result in the Corporation failing to meet financial obligations as they come due or may result in the acceleration of the Corporation’s debt.
LIQUIDITY RISK
Liquidity risk is the risk that the Corporation is not able to meet its financial obligations as they fall due. Compton’s $150 million Facility was renewed on June 30, 2010 and will come due July 1, 2011. The lenders under the Facility will reassess the borrowing base semi-annually on May 31 and December 31, which review may change the amount that the Corporation may borrow under its Facility. As at June 30, 2010, Compton had $nil outstanding under its Facility.
In addition, both the Facility and the note indenture governing the US$450 million of 7.625% Notes due in 2013 limit the extent to which the Corporation can incur other debt and require it to meet a fixed charge coverage ratio test and the ACNTA test. At each quarter end, the fixed charge coverage ratio must exceed a 2.5 to 1 threshold and the value calculated under the ACNTA test must exceed borrowings under the Facility. Failure to meet the fixed charge coverage ratio restricts Compton from incurring new debt. The value determined under the ACNTA test limits borrowings under the Facility to the ACNTA calculated value. At June 30, 2010, the fixed charge coverage test resulted in a ratio of 1.78 to 1 (2.01 to 1 at December 31, 2009). The June 30, 2010 ratio calculation falls below the minimu m requirement and thereby restricts the amount of incremental borrowings the Corporation may incur. The Corporation may incur up to $266.4 million under the Facility and certain other permitted debt until the time when the ratio exceeds 2.5 to 1. Management does not anticipate these restrictions to have any limiting or adverse affect on the operations of the Corporation.
The calculation of the ACNTA was $266.4 million at June 30, 2010 ($263.4 million at December 31, 2009), which was higher than the Facility authorized limits. Any reduction in Compton’s ability to access credit under the Facility, or requirement to pay amounts outstanding under the Note Indenture before its stated maturity date may result in the Corporation not being able to meet its financial obligations as they come due.
The trust indenture for the Notes requires that prior to completing an asset sale in excess of $3.0 million Compton deliver an officer’s certificate to the trustee setting forth the fair market value (as defined in the trust indenture) of the assets sold, accompanied, for asset sales in excess of $15.0 million, by a resolution of Compton's board of directors determining that the consideration received is at least equal to fair market value of the assets sold. While Compton has provided annual certifications to the trustee setting forth the fair market value received by Compton in connection with asset sales, such certifications were not delivered prior to consummation of such asset sales and were not accompanied by resolutions of Compton's board of directors.
| Management’s Discussion & Analysis | - 16 - | Compton Petroleum - Q2 2010 |
Compton received consideration at least equal to the fair market value of the assets sold in each of the prior asset sales conducted by Compton and all proceeds of such asset sales were applied appropriately in accordance with the covenant in the trust indenture relating to asset sales. Nevertheless, failure to comply with the requirement to deliver an officer's certificate and board resolutions prior to the time of an asset sale may constitute an event of default that is continuing under the trust indenture for the Notes.
Compton believes it has defences it can raise in this regard. Compton sought and received from the Court a stay of proceedings in respect of any action or proceeding relating to Compton’s failure to deliver to the indenture trustee an officer’s certificate and resolution of the board of directors setting forth fair market value of the assets sold for the asset sales consummated by Compton prior to the date hereof, pending the outcome of the Meeting to consider the proposed Arrangement which is part of the Recapitalization Plan. Provided that noteholders holding not less than a simple majority of the aggregate principal amount of the outstanding Notes vote in favour of the Arrangement resolution, the noteholders will have waived any action or proceeding relating thereto. If the Arrangement is completed , all rights and obligations under the Note indenture will be extinguished by order of the Court in connection with the approval of the Arrangement. Compton has obtained from the banks under the Facility a waiver of any cross-default in the Facility created by any event of default under the Note indenture prior to the date hereof.
VOLATILITY OF PRICES, MARKETS, AND MARKETING PRODUCTION
Oil and gas prices have historically been extremely volatile. Factors which contribute to oil and gas price fluctuations include global demand, domestic and foreign supplies of oil and gas, the price of foreign oil and gas imports, decisions of the Organization of Petroleum Exporting Countries relating to export quotas, domestic and foreign governmental regulations, political conditions in producing regions, global and domestic economic conditions, the price and availability of alternative fuels, including liquefied natural gas, and weather conditions.
The Corporation’s financial condition is substantially dependent on, and highly sensitive to, oil and gas commodity prices. Any material decline in prices could result in a material reduction of Compton’s operating results, revenue, reserves, and overall value. Lower commodity prices could change the economics of production from some wells. As a result, the Corporation could elect not to drill, develop, or produce from certain wells. In addition, Compton is impacted by the differential between prices paid by refiners for light quality oil and the grades of oil produced by the Corporation.
Current market conditions are particularly challenging with the global recession negatively impacting commodity prices as well as access to credit and capital markets. These conditions impact Compton’s customers and suppliers and may alter Compton’s spending and operating plans. There may be unexpected business impacts from this market uncertainty.
Under Canadian GAAP, oil and gas assets are reviewed quarterly to determine if the carrying value of the assets exceeds their expected future cash flows. A sustained period of low commodity prices may reduce expected future cash flows and require a write down to the fair value of the Corporation’s oil and gas properties, thereby adversely affecting operating results.
Any future and sustained period of weakness in oil and gas prices would also have an adverse effect on Compton’s capacity to borrow funds. The Corporation’s secured Facilities are based upon the lenders’ estimate of the value of the Corporation’s proved reserves, which determines the borrowing amount. A reduction in the quantity or value of reserves may also obligate Compton to make additional payments under the processing agreement with MPP.
Any decline in the Corporation’s ability to market production could have a material adverse effect on production levels or on the sale price received for production. Compton’s ability to market the oil and gas from the Corporation’s wells depends on numerous factors beyond the Corporation’s control, including the availability and capacity of gas gathering systems, pipelines and processing facilities, and their proximity to the wells. The Corporation will be impacted by Canadian federal and provincial, as well as US federal and state, energy policies, taxes, regulation of oil and gas production, processing, and transportation, as well as Canadian federal regulation of oil and gas sold or transported outside of the province of Alberta.
| Management’s Discussion & Analysis | - 17 - | Compton Petroleum - Q2 2010 |
| VII. | Forthcoming and Newly Adopted Accounting Policies |
INTERNATIONAL FINANCIAL REPORTING STANDARDS
On February 13, 2008, the Canadian Accounting Standards Board (“AcSB”) confirmed the mandatory changeover date to International Financial Reporting Standards (“IFRS”) for Canadian profit-oriented publicly accountable entities (“PAEs”) such as Compton.
The AcSB requires that IFRS compliant financial statements be prepared for annual and interim financial statements commencing on or after January 1, 2011. For PAEs with a December 31 year-end, the first unaudited interim financial statements under IFRS will be for the quarter ending March 31, 2011, with comparative financial information for the quarter ending March 31, 2010. The first audited annual financial statements will be for the year ending December 31, 2011, with comparative financial information for the year ending December 31, 2010. This also means that all opening balance sheet adjustments relating to the adoption of IFRS must be reflected in the January 1, 2010 opening balance sheet which will be issued as part of the comparative financial information in the March 31, 2011 unaudited interim financial statements.
Compton will adopt these requirements as set out by the AcSB and other regulatory bodies. The Corporation has developed and commenced implementing its plan for the changeover to IFRS to ensure that Compton addresses matters such as accounting policies, information technology systems, internal controls, disclosure controls and procedures, staffing requirements, and business activities impacted by accounting processes and measures.
The plan is comprised of three stages. The first stage is to obtain an understanding of the impact that the conversion to IFRS will have on the elements described above. The second stage is to develop and test solutions for the issues identified in stage one. The third and final stage is to implement the solutions developed in stage two.
At June 30, 2010, Compton has substantially completed phases one and two of its project plan to transition the Corporation to IFRS under the required timelines. The Corporation is currently in the third stage, working to implement its accounting policy selections and implement transition solutions for the systems and process changes necessary to support the Corporation’s reporting under IFRS.
Project activities continue to be focused on the areas identified as having the most significant impact to Compton, which are consistent with those specific to others in the oil and gas industry. These include cost recognition for property and equipment, asset componentization and depreciation, the identification of cash generating units and valuation. Management continues to work with an external consultant to support project resourcing and the execution of the project plan.
During this process we continue to focus on maintaining a robust internal control environment while also considering the impact of identified changes in processes and information system requirements on existing internal controls.
The following milestones and timelines have been identified under the project plan, and focus Management’s key transition initiatives. As outlined below, Management believes it is on target to successfully transition to IFRS.
| Management’s Discussion & Analysis | - 18 - | Compton Petroleum - Q2 2010 |
Financial Statements | Target Completion | Status at March 31, 2010 |
• Identification of significant differences between Canadian GAAP and IFRS. Identification of key conversation issues | Q3 2009 | Completed |
• Development of position papers for identified GAAP differences, and selection of accounting policy alternatives | Q2 2010 | Substantially complete |
• Selection of IFRS 1 exemptions and accounting policy choices | Q2 2010 | Substantially complete |
• Preparation of the opening balance sheet reconciliation under IFRS | Q3 2010 | In progress |
• Determination of new financial statement note disclosure requirements | Q3 2010 | In progress |
• Restatement of 2010 Quarterly information for comparative presentation purposes | Q1 2011 | To commence in Q3 2010 |
| | | |
| Information Technology | | |
• Assess systems impact for accounting policy selections and required note disclosure information | Q2 2010 | Commenced in Q1 2010 |
| | | |
| Control Environment | | |
• For all accounting policy changes, assess impact on internal controls over financial reporting and disclosure controls. Implement appropriate changes | Q4 2010 | To commence in Q3 2010 |
While at this time the impact of adopting IFRS cannot be reasonably quantified, Management expects an assessment to be available for the Corporation’s Q3 2010 report. Management anticipates that the most significant impact of transition will be the revised financial disclosure under IFRS, which is generally viewed to be more detailed and comprehensive than that of Canadian GAAP.
CHANGES IN ACCOUNTING POLICIES
Recent Accounting Pronouncements
There were no new accounting pronouncements issued under GAAP in the first and second quarter of 2010 affecting the Corporation.
| VIII. | Quarterly Information |
The following table sets forth certain quarterly financial information of the Corporation for the eight most recent quarters.
| Management’s Discussion & Analysis | - 19 - | Compton Petroleum - Q2 2010 |
| | | 2010 | | | 2009 | | | 2008 | |
| ($millions, except where noted) | | | Q2 | | | | Q1 | | | | Q4 | | | | Q3 | | | | Q2 | | | | Q1 | | | | Q4 | | | | Q3 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total revenue(1) | | $ | 57 | | | | 71 | | | $ | 58 | | | $ | 47 | | | $ | 54 | | | $ | 69 | | | | 105 | | | $ | 158 | |
Cash flow(1) | | $ | 11 | | | | 20 | | | $ | 6 | | | $ | 7 | | | $ | 10 | | | $ | 22 | | | | 29 | | | $ | 87 | |
Per share - basic | | $ | 0.04 | | | | 0.08 | | | $ | 0.03 | | | $ | 0.06 | | | $ | 0.08 | | | $ | 0.18 | | | | 0.18 | | | $ | 0.67 | |
- diluted | | $ | 0.04 | | | | 0.08 | | | $ | 0.03 | | | $ | 0.06 | | | $ | 0.08 | | | $ | 0.18 | | | | 0.18 | | | $ | 0.66 | |
| Net earnings (loss) | | $ | (52 | ) | | | 17 | | | $ | (24 | ) | | $ | 13 | | | $ | 20 | | | $ | (17 | ) | | | (96 | ) | | $ | 60 | |
Per share -basic | | $ | (0.20 | ) | | | 0.06 | | | $ | (0.09 | ) | | $ | 0.10 | | | $ | 0.16 | | | $ | (0.14 | ) | | | (0.74 | ) | | $ | 0.46 | |
- diluted | | $ | (0.20 | ) | | | 0.06 | | | $ | (0.09 | ) | | $ | 0.10 | | | $ | 0.16 | | | $ | (0.14 | ) | | | (0.74 | ) | | $ | 0.46 | |
Operating earnings(1) | | $ | (21 | ) | | | (5 | ) | | $ | (25 | ) | | $ | (19 | ) | | $ | (16 | ) | | $ | (3 | ) | | | (19 | ) | | $ | 46 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Production | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural gas (mmcf/d) | | | 98 | | | | 97 | | | | 98 | | | | 99 | | | | 108 | | | | 117 | | | | 125 | | | | 130 | |
| Liquids (bbls/d) | | | 3,076 | | | | 3,237 | | | | 3,055 | | | | 3,208 | | | | 3,428 | | | | 3,655 | | | | 4,113 | | | | 4,323 | |
| Total (boe/d) | | | 19,481 | | | | 19,411 | | | | 19,351 | | | | 19,760 | | | | 21,440 | | | | 23,194 | | | | 24,868 | | | | 26,006 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Average price | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural gas ($/mcf) | | $ | 4.15 | | | | 5.67 | | | $ | 4.38 | | | $ | 3.14 | | | $ | 3.80 | | | $ | 5.18 | | | | 6.99 | | | $ | 8.75 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Liquids ($/bbl) | | $ | 66.00 | | | | 67.59 | | | $ | 57.10 | | | $ | 55.42 | | | $ | 49.94 | | | $ | 38.35 | | | | 60.60 | | | $ | 124.05 | |
| Total ($/boe) | | $ | 31.41 | | | | 39.62 | | | $ | 31.16 | | | $ | 24.78 | | | $ | 27.15 | | | $ | 32.20 | | | | 45.01 | | | $ | 64.41 | |
| (1) | Prior periods have been revised to conform to current period presentation |
Fluctuations in quarterly results are due to a number of factors, some of which are not within the Corporation’s control such as seasonality and exchange rates. Depressed commodity prices and lower production volumes due to asset sales and natural declines contributed to decreased revenues starting in the third quarter of 2008. The production base has stabilized to a consistent level in the final quarter of 2009 with a resulting increase in total revenues.
Cash flow and operating earnings were negatively affected in the fourth quarter of 2008 by one-time non-recurring strategic review costs and quarterly during 2009 for related restructuring costs. Increases in the US dollar against the Canadian dollar had the effect of decreasing net earnings during the fourth quarter of 2008 and the first quarter of 2009. Cash flow for the first quarter of 2010 increased as a result of higher realized prices and cost control initiatives following the restructuring process, however, this was more than offset by one-time costs relating to the surrender of surplus leased office space in the second quarter.
NON-GAAP FINANCIAL MEASURES
Included in this document are references to terms used in the oil and gas industry such as, cash flow, operating earnings (loss), free cash flow, funds flow per share, adjusted EBITDA, field netback, cash flow netback, debt and capitalization. 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. These measures have been described and presented in this document in order to provide shareholders and potential investors with additional information regarding the Corporation’s liquidity and its ability to generate funds to finance its operations.
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 uses the 6:1 boe measure which is the approximate energy equivalency of the two commodities at the burner tip. However, boes do not represent a value equivalency at the well head and therefore may be a misleading measure if used in isolation.
| Management’s Discussion & Analysis | - 20 - | Compton Petroleum - Q2 2010 |
FORWARD-LOOKING STATEMENTS
Certain information regarding the Corporation 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 and the United States Securities and Exchange Act of 1934, as amended.
Forward-looking information and statements involve risks, uncertainties and other factors that could cause actual results to differ materially from those expressed or implied by them. Forward-looking statements include estimates, plans, expectations, opinions, forecasts, projections, guidance, or other statements that are not statements of fact, including statements regarding (i) cash flow and capital and operating expenditures, (ii) exploration, drilling, completion, and production matters, (iii) results of operations, (iv) financial position, and (v) other risks and uncertainties described from time to time in the reports and filings made by Compton with securities regulatory authorities. Although Compton believes that the assumptions underlying, and expectations reflected in, such forward-looking stat ements are reasonable, it can give no assurance that such assumptions and expectations will prove to have been correct. There are many factors that could cause forward-looking statements not to be correct, including risks and uncertainties inherent in the Corporation’s business. These risks include, but are not limited to: crude oil and natural gas price volatility, exchange rate fluctuations, availability of services and supplies, operating hazards, access difficulties and mechanical failures, weather related issues, uncertainties in the estimates of reserves and in projection of future rates of production and timing of development expenditures, general economic conditions, and the actions or inactions of third-party operators, and other risks and uncertainties described from time to time in the reports and filings made with securities regulatory authorities by Compton. Statements relating to “reserves” and “resources” are deemed to be forward-l ooking statements, as they involve the implied assessment, based on estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future.
The forward-looking statements contained herein are made as of the date of this document solely for the purpose of generally disclosing Compton’s views of its prospective activities. Compton may, as considered necessary in the circumstances, update or revise the forward-looking statements, whether as a result of new information, future events, or otherwise, but Compton does not undertake to update this information at any particular time, except as required by law. Compton cautions readers that the forward-looking statements may not be appropriate for purposes other than their intended purposes and that undue reliance should not be placed on any forward-looking statement. The Corporation’s forward-looking statements are expressly qualified in their entirety by this cautionary statem ent.
Additional Information
Further information regarding Compton can be accessed under the Corporation’s public filings found on the Canadian Securities Administrators’ SEDAR website at www.sedar.com, the EDGAR section of the U.S. Securities and Exchange Commission website at www.sec.gov, on the Corporation’s website at www.comptonpetroleum.com, or on request by sending an email to investorinfo@comptonpetroleum.com.
| Management’s Discussion & Analysis | - 21 - | Compton Petroleum - Q2 2010 |
