Exhibit 99.2
Management’s Discussion and 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 and related notes for the three months ended June 30, 2011 and March 31, 2011, as well as the audited consolidated financial statements and MD&A for the year ended December 31, 2010. Readers should also read the “Forward-Looking Statements” legal advisory contained at the end of this document. Disclosure regarding use of BOE Equivalents is contained in the “Advisories” section located at the end of this document.
The unaudited interim consolidated financial statements and comparative information has been prepared in accordance with International Financial Reporting Standard 1, “First-time Adoption of International Financial Reporting Standards”, and with International Accounting Standard 34, “Interim Financial Reporting”, as issued by the International Accounting Standards Board. Previously, the Corporation prepared its interim and audited annual consolidated financial statements in accordance with Canadian Generally Accepted Accounting Principles (“Previous GAAP”).
Included in this document are measures that do not have any standardized meaning as prescribed under IFRS or Previous GAAP and are considered to be non-GAAP Financial Measures, defined fully in the “Advisories” section located at the end of this document.
Further information regarding Compton, including the Annual Information Form for the year ended December 31, 2010 can be accessed under the Corporation’s public filings found on SEDAR at www.sedar.com, EDGAR at www.sec.gov, and on the Corporation’s website at www.comptonpetroleum.com.
Amounts presented in this MD&A are stated in thousands (000’s) of dollars except per share and boe amounts, unless otherwise stated. This document is dated as at August 11, 2011.
I. Compton’s Business
Compton Petroleum Corporation is a public Corporation 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 majority of 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 pursues four deep basin natural gas plays: the Rock Creek sands at Niton in central Alberta and in southern Alberta the Basal Quartz sands at High River, the shallower Southern Plains Belly River sands, and an exploratory play in the Foothills. Being in the Deep Basin, all areas have multi-zone potential, providing future development and exploration opportunity. Compton is also focused on developing its emerging oil potential in the Southern Plains area and in Montana. Natural gas represents approximately 83% of production and 85% of proved reserves.
II. Results from Corporate Strategy
Management’s strategy throughout the first half of the year was to focus on value creation through improvements in capital efficiency and operating expenses. This approach has increased Compton’s efficiencies and served to partially offset the impact of lower natural gas prices on cash flows generated by operating activities over the past two years. Results for second quarter of 2011 include:
| | • | Average daily production of 12,748 boe/d, notwithstanding the impact of a major plant turnaround during the period; |
| Management’s Discussion and Analysis | - 1 - | Compton Petroleum – Q2 2011 |
| | • | Reduced cost structure by a combined $10.4 million from the second quarter of 2010: |
| | • | Operating costs decreased by $4.4 million or 26% as a result of reduced production levels and the Corporation’s continued focus on efficiency; |
| | • | Administrative costs decreased by 28% or $1.6 million due to restructuring completed at the end of 2010; and |
| | • | Interest and finance charges decreased by 32% or $4.4 million as a result of lower debt levels in 2011 compared to 2010. |
| | • | Participated in three non-operated wells, focusing on higher economic returns from high return, liquids rich natural gas; |
| | • | Began the development of other formations in Niton with the drilling of a Wilrich (Spirit River) horizontal well; early results are encouraging and reinforce the strategy to pursue this information once capital is available. |
| | • | Announced a proposed recapitalization plan of arrangement (the “Recapitalization”) to make Compton’s capital structure more competitive with industry peers and substantially improve its financial strength. The Recapitalization consisted of the following elements: |
| | • | Conversion of US$193.5 million of Compton Finance 10% Senior Notes due 2017 and US$46.8 million of Compton Finance 10% Mandatory Convertible Notes due September 2011 into equity; |
| | • | Addition of approximately $50.0 million of new equity raised by way of a backstopped Rights Offering, which will be applied to further reduce debt; |
| | • | Consolidation of existing common shares on a 200 to 1 basis; and |
| | • | Reduction of total pro forma debt to $145.3 million from $419.6 million at March 31, 2011, resulting in a decrease of annual cash interest and financing expenses by approximately $25.5 million. |
| | • | Subsequent to the quarter, the Recapitalization was approved by noteholders and shareholders. |
With the completion of the Recapitalization Management will be better positioned to focus on drilling and exploration efforts for the remainder of 2011 and beyond, providing the opportunity for accretive growth over a multi-year horizon.
III. Results of Operations
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2011 | | | 2010(2) | | | 2011 | | | 2010(2) | |
| ($000’s, except per share amounts) | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Average production (boe/d) | | | 12,748 | | | | 19,748 | | | | 13,622 | | | | 19,446 | |
| | | | | | | | | | | | | | | | | |
Capital investment(3) | | $ | 8,494 | | | $ | 15,259 | | | $ | 15,368 | | | $ | 26,002 | |
| | | | | | | | | | | | | | | | | |
Cash flow(1) | | $ | 7,144 | | | $ | 10,072 | | | $ | 14,770 | | | $ | 30,958 | |
Per share: basic | | $ | 0.03 | | | $ | 0.04 | | | $ | 0.06 | | | $ | 0.12 | |
diluted | | $ | 0.01 | | | $ | 0.04 | | | $ | 0.02 | | | $ | 0.12 | |
| | | | | | | | | | | | | | | | | |
Operating loss(1) | | $ | (9,397 | ) | | $ | (68,815 | ) | | $ | (5,932 | ) | | $ | (66,116 | ) |
| | | | | | | | | | | | | | | | | |
| Net loss | | $ | (7,677 | ) | | $ | (90,011 | ) | | $ | (4,217 | ) | | $ | (64,549 | ) |
Per share: basic | | $ | (0.03 | ) | | $ | (0.34 | ) | | $ | (0.02 | ) | | $ | (0.24 | ) |
diluted | | $ | (0.03 | ) | | $ | (0.34 | ) | | $ | (0.02 | ) | | $ | (0.24 | ) |
| | | | | | | | | | | | | | | | | |
| Revenue | | $ | 34,684 | | | $ | 48,886 | | | $ | 70,333 | | | $ | 109,672 | |
| | | | | | | | | | | | | | | | | |
Field netback (per boe)(1) | | $ | 19.11 | | | $ | 17.12 | | | $ | 17.93 | | | $ | 19.91 | |
| (1) | Cash flow, operating loss and field netback are non-GAAP measures that are defined in this document |
| (2) | Prior period amounts have been revised to conform to current period presentation |
| (3) | Capital investment is before asset acquisitions and divestitures |
| Management’s Discussion and Analysis | - 2 - | Compton Petroleum – Q2 2011 |
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 IFRS, 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.
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Cash flow from operating activities | | $ | 18,457 | | | $ | (1,181 | ) | | $ | 10,356 | | | $ | 15,750 | |
| Less: change in non-cash working capital | | | 11,313 | | | $ | (11,253 | ) | | $ | (4,414 | ) | | $ | (15,208 | ) |
Cash flow(1) | | $ | 7,144 | | | $ | 10,072 | | | $ | 14,770 | | | $ | 30,958 | |
| (1) | Cash flow is a non-GAAP measure that is defined in this document |
Cash flow for the second quarter of 2011 decreased by approximately $2.9 million or 29% compared to 2010 as a result of:
| | • | a 35% decline in natural gas production volumes to 65 mmcf/d from 100 mmcf/d in 2010, resulting from the impact of asset sales, normal production declines, and the reduced level of capital expenditures; |
| | • | a 40% decline in liquids production volumes to 1,083 bbls/d from 1,792 bbls/d in 2010, resulting from the impact of asset sales, normal production declines, and the reduced level of capital expenditures; and |
| | • | realized risk management gains of $3.7 million compared to $4.2 million in 2010. |
These factors were partially offset by:
| | • | higher average realized liquids prices, which increased 34% to $88.39 per bbl compared to $66.20 per bbl in 2010; |
| | • | a $4.4 million decrease in interest and finance charges resulting from reduced debt levels in 2011 compared to 2010; |
| | • | a decline in operating costs of $4.4 million resulting from reduced production levels and the continued focus on efficiency; and |
| | • | a decline in administrative costs of $1.6 million resulting from the restructuring completed at the end of 2010. |
On a year-to-date basis, cash flow decreased by approximately $16.2 million or 52% as a result of:
| | • | a 30% decline in natural gas production volumes to 69 mmcf/d from 98 mmcf/d in 2010, resulting from the impact of asset sales, normal production declines, and the reduced level of capital expenditures; |
| Management’s Discussion and Analysis | - 3 - | Compton Petroleum – Q2 2011 |
| | • | a 34% decline in liquids production volumes to 1,217 bbls/d from 1,830 bbls/d in 2010, resulting from the impact of asset sales, normal production declines, and the reduced level of capital expenditures; and |
| | • | lower average realized gas prices, which decreased 17% to $4.05 per mcf compared to $4.90 per mcf in 2010; |
These factors were partially offset by:
| | • | higher average realized liquids prices, which increased 16% to $77.69 per bbl compared to $66.81 per bbl in 2010; |
| | • | realized risk management gains of $7.1 million compared to $4.2 million in 2010; |
| | • | a $9.3 million decrease in interest and finance charges resulting from reduced debt levels in 2011 compared to 2010; |
| | • | a decline in operating costs of $6.6 million resulting from reduced production levels, and the continued focus on efficiency; and |
| | • | a decline in administrative costs of $2.3 million resulting from the restructuring completed at the end of 2010. |
NET LOSS
Net loss for the second quarter of 2011 was $7.7 million, an improvement of $82.3 million when compared to the $90.0 million net loss in the same period for 2010. In addition to the factors that impacted cash flow, second quarter 2011 net loss was favorably affected by:
| | • | unrealized risk management gains of $0.1 million compared to a loss of $5.3 million in 2010; |
| | • | a decline in depletion and depreciation expense to $13.9 million from $22.9 million in 2010, following asset impairments recognized during 2010; |
| | • | unrealized foreign exchange and other gains of $2.0 million compared to loss of $20.3 million in 2010; |
| | • | a $1.0 million decline in share based payment expense following the restructuring of staff completed early in 2011; |
| | • | a loss on asset disposition of $1.4 million compared to $2.5 million in 2010; and |
| | • | an impairment expense of $72.8 million in 2010. |
These factors were partially offset by:
| | • | increased exploration and evaluation costs of $5.1 million compared to $0.1 million in 2010, relating to the expiry of undeveloped land; and |
| | • | deferred tax recovery of $3.2 million compared to $24.5 million in 2010. |
On a year-to-date basis, net loss was $4.2 million, an improvement of $60.3 million when compared to the $64.5 million net loss in the same period for 2010. In addition to the factors that impacted cash flow, year-to-date net loss was favorably affected by:
| | • | a decline in depletion and depreciation expense to $28.8 million from $45.3 million in 2010, following asset impairments recognized during 2010; |
| | • | unrealized foreign exchange and other gains of $7.4 million compared to loss of $6.3 million in 2010; |
| | • | a $2.2 million decline in share based payment expense following the restructuring of staff completed early in 2011; |
| Management’s Discussion and Analysis | - 4 - | Compton Petroleum – Q2 2011 |
| | • | a gain on asset disposition of $16.3 million compared to loss of $2.5 million in 2010; and |
| | • | an impairment expense of $72.8 million in 2010. |
These factors were partially offset by:
| | • | increased exploration and evaluation costs of $9.6 million compared to $0.1 million in 2010, relating to the expiry of undeveloped land; |
| | • | deferred tax recovery of $4.2 million compared to $24.5 million in 2010; and |
| | • | unrealized risk management loss of $6.3 million compared to a gain of $9.7 million in 2010. |
OPERATING EARNINGS (LOSS)
Operating earnings 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 should not be considered more meaningful than or an alternative to net earnings as determined in accordance with IFRS. The following provides the calculation of operating loss for period end.
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Net loss, as reported | | $ | (7,677 | ) | | $ | (90,011 | ) | | $ | (4,217 | ) | | $ | (64,549 | ) |
| Non-operational items | | | | | | | | | | | | | | | | |
Unrealized foreign exchange and other (gains) losses | | | (1,961 | ) | | | 20,250 | | | | (7,367 | ) | | | 6,300 | |
Unrealized mark-to-market hedging (gains) losses | | | (46 | ) | | | 5,251 | | | | 6,287 | | | | (9,725 | ) |
Other expenses | | | - | | | | - | | | | - | | | | 23 | |
| | | | | | | | | | | | | | | | | |
Tax effect | | | 287 | | | | (4,305 | ) | | | (635 | ) | | | 1,835 | |
Operating loss(1) | | $ | (9,397 | ) | | $ | (68,815 | ) | | $ | (5,932 | ) | | $ | (66,116 | ) |
Per share - basic | | $ | (0.04 | ) | | $ | (0.26 | ) | | $ | (0.02 | ) | | $ | (0.25 | ) |
- diluted | | $ | (0.04 | ) | | $ | (0.26 | ) | | $ | (0.02 | ) | | $ | (0.25 | ) |
| (1) | Prior periods have been revised to conform to current period presentation |
CAPITAL EXPENDITURES
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Exploration & evaluation | | | | | | | | | | | | |
| Land | | $ | 771 | | | $ | 1,082 | | | $ | 957 | | | $ | 1,973 | |
| Drilling and completions | | | 111 | | | | (251 | ) | | | 515 | | | | 204 | |
| | | | | | | | | | | | | | | | | |
| Development & production | | | | | | | | | | | | | | | | |
| Drilling and completions | | | 2,993 | | | | 9,919 | | | | 8,026 | | | | 17,907 | |
| Alberta Drilling Credits | | | - | | | | (2,741 | ) | | | - | | | | (4,721 | ) |
| Production facilities and equipment | | | 4,540 | | | | 6,907 | | | | 5,760 | | | | 10,258 | |
| Corporate and other | | | 79 | | | | 343 | | | | 110 | | | | 381 | |
| Total capital investment | | | 8,494 | | | | 15,259 | | | | 15,368 | | | | 26,002 | |
| | | | | | | | | | | | | | | | | |
| Divestitures | | | | | | | | | | | | | | | | |
Property | | | - | | | | (117,351 | ) | | | (8,066 | ) | | | (117,407 | ) |
Production facilities and equipment | | | - | | | | - | | | | (405 | ) | | | - | |
Overriding Royalty | | | - | | | | (14,289 | ) | | | - | | | | (23,469 | ) |
Land | | | (200 | ) | | | - | | | | (2,126 | ) | | | - | |
| Acquisitions (divestitures), net | | | (200 | ) | | | (131,640 | ) | | | (10,597 | ) | | | (140,876 | ) |
| | | | | | | | | | | | | | | | | |
| Total capital expenditures | | $ | 8,294 | | | $ | (116,381 | ) | | $ | 4,771 | | | $ | (114,874 | ) |
| Management’s Discussion and Analysis | - 5 - | Compton Petroleum – Q2 2011 |
The current level of natural gas prices has limited internally generated cash flow available to invest in drilling activities. As a result, capital spending, before acquisitions, divestments and corporate expenses decreased by 44% in the second quarter and 41% on a year-to-date basis in 2011 compared to 2010. In order to maximize return on capital in 2011, Management has focused its expenditures towards higher return, liquids rich natural gas in Niton and emerging oil properties. Compton drilled or participated in a total of two wells (one operated well and one non-operated well), or 0.7 net wells, during the second quarter of 2011 as compared to a total of 7 wells (6.6 net wells) drilled during 2010. Capital expenditures in 2010 were partially offset by the implementation of the Alberta drilling credit program. No credits have been recognized in 2011 as the amount available is tied to the amount of crown royalties paid which has been insufficient to qualify the Corporation under the program for credits to offset the 2011 drilling program.
In the Niton area, a Rock Creek horizontal well (19.2% working interest) initially tested at 2.3 mmcf/d and 150 bbl/d condensate. The well is currently tied in and on production. Also in the Niton area, a Wilrich (Spirit River) horizontal well (33.3% working interest) was drilled and is in the process of being completed. The Spirit River Formation was identified through the Niton area evaluation as providing significant upside potential for the Corporation. Results to date have been extremely encouraging, reinforcing Compton’s decision to pursue this play with increased capital budgets. The third well participated in (6% working interest) also targeted the Spirit River Formation on lands outside of Niton and is in the process of being completed.
Evaluation of the Ellerslie oil well drilled in the Southern plains continued in the second quarter. Currently the well is producing approximately 1 mmcf/d of natural gas and 60 bbl/d of oil. The results are very encouraging, despite challenges in the completion that resulted in eight out of the 12 stages being successfully fractured. Future optimization of completion methods is expected to yield improved production levels. As a result, Compton will continue drilling in the Ellerslie formation to further evaluate the oil potential of this play.
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 2011 free cash flow deficit was $1.4 million, an improvement from the second quarter of 2010 due to lower capital expenditures in 2011 and the focused cost reduction initiatives since the strategic review and restructuring completed in 2010. On a year-to-date basis, free cash flow declined $5.6 million from 2010 due to a significant decline in production volumes, natural gas prices, and sales revenue.
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Cash flow | | $ | 7,144 | | | $ | 10,072 | | | $ | 14,770 | | | $ | 30,958 | |
| Less: capital investment | | | (8,494 | ) | | | (15,259 | ) | | | (15,368 | ) | | | (26,002 | ) |
| Free cash flow | | $ | (1,350 | ) | | $ | (5,187 | ) | | $ | (598 | ) | | $ | 4,956 | |
| PRODUCTION VOLUMES AND REVENUES | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Average production | | | | | | | | | | | | | | | | |
Natural gas (mmcf/d) | | | 65 | | | | 100 | | | | 69 | | | | 98 | |
Liquids (bbls/d) | | | 1,947 | | | | 3,066 | | | | 2,199 | | | | 3,156 | |
Total (boe/d) | | | 12,748 | | | | 19,748 | | | | 13,622 | | | | 19,446 | |
| | | | | | | | | | | | | | | | | |
| Benchmark prices | | | | | | | | | | | | | | | | |
AECO ($/GJ) | | | | | | | | | | | | | | | | |
| Monthly index | | $ | 3.54 | | | $ | 3.66 | | | $ | 3.56 | | | $ | 4.37 | |
| Daily index | | $ | 3.67 | | | $ | 3.69 | | | $ | 3.62 | | | $ | 4.19 | |
WTI (US$/bbl) | | $ | 102.56 | | | $ | 78.03 | | | $ | 98.30 | | | $ | 78.37 | |
Edmonton sweet light ($/bbl) | | $ | 103.09 | | | $ | 75.21 | | | $ | 95.54 | | | $ | 77.66 | |
| | | | | | | | | | | | | | | | | |
| Realized prices | | | | | | | | | | | | | | | | |
Natural gas ($/mcf) | | $ | 4.10 | | | $ | 4.09 | | | $ | 4.05 | | | $ | 4.90 | |
Liquids ($/bbl) | | $ | 88.39 | | | $ | 66.20 | | | $ | 77.69 | | | $ | 66.81 | |
Total ($/boe) | | $ | 34.35 | | | $ | 30.98 | | | $ | 32.94 | | | $ | 35.48 | |
| | | | | | | | | | | | | | | | | |
Sales Revenue(1)(2) | | | | | | | | | | | | | | | | |
| Natural gas | | $ | 24,188 | | | $ | 37,210 | | | $ | 50,283 | | | $ | 86,734 | |
| Liquids | | | 17,504 | | | | 20,200 | | | | 34,111 | | | | 41,944 | |
| Total | | $ | 41,692 | | | $ | 57,410 | | | $ | 84,394 | | | $ | 128,678 | |
| (1) | Gross sales revenues are before crown and freehold royalties |
| (2) | Prior periods have been revised to conform to current period presentation |
| Management’s Discussion and Analysis | - 6 - | Compton Petroleum – Q2 2011 |
Production volumes for the second quarter of 2011 were 35% lower than in 2010 primarily due to natural declines, a reduced asset base following property dispositions throughout 2010, and limited new production additions in 2011.
Revenue decreased by 27% for the second quarter of 2011 compared to 2010 due to lower realized natural gas prices and reduced sales 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 2011 was a favorable $0.63 per mcf compared to a favorable $0.46 impact per mcf in 2010.
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 $/boe basis. Funds flow netback equals field netback less administrative and interest costs. Field netback and funds flow netback should not be considered more meaningful than or an alternative to net earnings as determined in accordance with IFRS. The following provides the calculation of field netback and funds flow netback.
| Management’s Discussion and Analysis | - 7 - | Compton Petroleum – Q2 2011 |
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| ($/boe) | | | | | | | | | | | | |
Realized price(1) | | $ | 34.35 | | | $ | 30.98 | | | $ | 32.94 | | | $ | 35.48 | |
| Processing revenue | | | 1.59 | | | | 0.96 | | | | 1.29 | | | | 1.07 | |
| Realized commodity hedge gain | | | 3.18 | | | | 2.34 | | | | 2.88 | | | | 1.20 | |
| Royalties | | | (8.16 | ) | | | (6.84 | ) | | | (8.34 | ) | | | (8.20 | ) |
| Operating expenses | | | (10.55 | ) | | | (9.27 | ) | | | (9.69 | ) | | | (8.68 | ) |
| Transportation | | | (1.30 | ) | | | (1.05 | ) | | | (1.15 | ) | | | (0.96 | ) |
| Field netback | | $ | 19.11 | | | $ | 17.12 | | | $ | 17.93 | | | $ | 19.91 | |
| | | | | | | | | | | | | | | | | |
| Administrative | | $ | (3.54 | ) | | $ | (3.17 | ) | | $ | (3.61 | ) | | $ | (3.19 | ) |
| Interest | | | (8.02 | ) | | | (7.66 | ) | | | (7.65 | ) | | | (7.99 | ) |
| Funds flow netback | | $ | 7.55 | | | $ | 6.29 | | | $ | 6.67 | | | $ | 8.73 | |
(1) Prior periods have been revised to conform to current period presentation
ROYALTIES
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Crown royalties | | $ | 5,249 | | | $ | 6,349 | | | $ | 10,211 | | | $ | 14,185 | |
| Freehold royalties | | | 1,760 | | | | 2,176 | | | | 3,850 | | | | 4,821 | |
| Royalties included in revenue | | | 7,009 | | | | 8,525 | | | | 14,061 | | | | 19,006 | |
| | | | | | | | | | | | | | | | | |
Overriding royalty(2) | | | 1,926 | | | | 2,783 | | | | 3,781 | | | | 5,488 | |
| Other royalties | | | 497 | | | | 881 | | | | 1,009 | | | | 2,043 | |
| Freehold mineral taxes | | | 30 | | | | 102 | | | | 1,714 | | | | 2,319 | |
| Other royalty obligations expense | | | 2,453 | | | | 3,766 | | | | 6,504 | | | | 9,850 | |
| | | | | | | | | | | | | | | | | |
| Total royalties | | $ | 9,462 | | | $ | 12,291 | | | $ | 20,565 | | | $ | 28,856 | |
| | | | | | | | | | | | | | | | | |
| Percentage of sales revenue | | | 22.7 | % | | | 21.4 | % | | | 24.4 | % | | | 22.4 | % |
(1) Gas cost allowance received on crown volumes are presented as a reduction of Operating Expenses.
| (2) | The overriding royalty obligation represents a 5% commitment of the Corporation’s future gross production revenue, less certain transportation costs and marketing fees, on the existing land base at September 26, 2009. |
Total royalties decreased by 23% for the second of 2011 compared to 2010, largely due to the reduction in produced volumes. A higher proportion of fixed rate freehold royalties resulted in a 1.3% increase in royalties as a percentage of sales revenue. On a year-to-date basis, total royalties decreased by 29% due to lower natural gas prices and the reduction in produced volumes. A higher proportion of fixed rate freehold royalties resulted in a 2.0% increase in royalties as a percentage of sales revenue during the first half of 2011.
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 effective January 2011. The rate reductions are focused on lowering the progressive royalty rates applicable in a commodity price environment higher than that being experienced by the Corporation under current economic conditions. As a result, this change is not anticipated to have a near term impact on the Corporation given the Corporation’s current production profile and Management’s outlook for gas prices remaining in the low end of the gas price cycle range. (See “Forward Looking Statements” in the “Advisory” section of this MD&A.)
| Management’s Discussion and Analysis | - 8 - | Compton Petroleum – Q2 2011 |
OPERATING EXPENSES
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
Operating expenses ($000’s) | | $ | 12,246 | | | $ | 16,655 | | | $ | 23,890 | | | $ | 30,534 | |
Operating expenses ($/boe) | | $ | 10.55 | | | $ | 9.27 | | | $ | 9.69 | | | $ | 8.68 | |
Operating expenses decreased by 26% in the second quarter of 2011, while per boe costs increased by 14% from 2010. On a year-to-date basis, operating expense decreased by 22% while per boe costs increased by 12%. The decrease on a total dollar basis was a result of continued cost control initiatives identified and implemented by the Corporation, as well as a reduced asset base. The increase in per boe costs reflects the fixed cost component of certain operating costs, spread over reduced production levels quarter-over-quarter.
TRANSPORTATION
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Transportation costs | | $ | 1,510 | | | $ | 1,893 | | | $ | 2,827 | | | $ | 3,392 | |
Transportation costs ($/boe) | | $ | 1.30 | | | $ | 1.05 | | | $ | 1.15 | | | $ | 0.96 | |
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 toll rates approved by the government. Compton incurs charges for the transportation of its production from the wellhead to the point of sale.
Transportation expenses decreased by 20% in the second quarter of 2011 when compared to 2010, while per boe amounts increased by 24%. On a year-to-date basis, transportation expenses decreased by 17% when compared to 2010, while per boe amounts increased by 20%. The decrease in transportation costs is attributable to reduced production in 2011, partially offset by an increase in pipeline tariffs of approximately 25%. Increased per boe costs are a result of lower production volumes.
ADMINISTRATIVE EXPENSES
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Gross administrative expenses | | $ | 5,204 | | | $ | 7,174 | | | $ | 11,749 | | | $ | 15,883 | |
| Capitalized administrative expenses | | | (327 | ) | | | (1,016 | ) | | | (1,108 | ) | | | (2,563 | ) |
| Operator recoveries | | | (774 | ) | | | (469 | ) | | | (1,738 | ) | | | (2,081 | ) |
| Administrative expenses | | $ | 4,103 | | | $ | 5,689 | | | $ | 8,903 | | | $ | 11,239 | |
Administrative expenses ($/boe) | | $ | 3.54 | | | $ | 3.17 | | | $ | 3.61 | | | $ | 3.19 | |
Administrative expenses were reduced by 27% on gross expenditures and 28% net of capitalized costs and operator recoveries in the second quarter of 2011 compared to 2010, however per boe amounts increased 12% over the same period. On a year-to-date basis, administrative expenses were reduced by 26% on gross expenditures and 21% net of capitalized costs and operator recoveries in 2011 compared to 2010, while per boe amounts increased 13%. The decrease in total dollars was a result of continued cost control initiatives as well as reduced staff levels following the 2010 restructuring. Increased per boe costs are a result of certain fixed administrative costs and a decline in production volumes.
| Management’s Discussion and Analysis | - 9 - | Compton Petroleum – Q2 2011 |
STOCK-BASED COMPENSATION
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Stock option plan | | $ | (979 | ) | | $ | 804 | | | $ | (1,421 | ) | | $ | 1,513 | |
| Employee long term incentive | | | 331 | | | | - | | | | 331 | | | | - | |
| Deferred share unit plan | | | 215 | | | | - | | | | 215 | | | | - | |
| Retention share plan | | | 266 | | | | - | | | | 266 | | | | - | |
| Share purchase plan | | | 235 | | | | 267 | | | | 418 | | | | 551 | |
| | | | | | | | | | | | | | | | | |
| Stock-based compensation | | $ | 68 | | | $ | 1,071 | | | $ | (191 | ) | | $ | 2,064 | |
Following the restructuring of staff completed in 2010, a recovery of previously expensed share based compensation was recorded in the first half of 2011. In addition, the estimated forfeiture rate of outstanding options has increased based on historical data, which should reduce the recognition of share based compensation expense in future periods.
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 share based compensation arrangements are presented in Note 12 to the unaudited consolidated interim financial statements.
IMPAIRMENTS
Management has assessed both internal and external economic factors to determine if any indicators of asset impairment exist at the quarter end. When indicators exist, an impairment test is completed, at the cash generating unit (“CGU”) level, to determine if any asset impairment exists. Each identified CGU has largely independent cash flows and is geographically integrated.
There were no impairments of the Corporation’s assets based on Management assessment of economic and internal indicators for the first half of 2011. In 2010, following the sale of a significant portion of Niton properties, an impairment of $72.8 million was recognized on development and production assets.
EXPLORATION AND EVALUATION
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Exploration and evaluation | | $ | 5,119 | | | $ | 24 | | | $ | 9,617 | | | $ | 126 | |
Total costs ($/boe) | | $ | 4.41 | | | $ | 0.01 | | | $ | 3.90 | | | $ | 0.04 | |
Exploration and evaluation expense relate entirely to the expiry of mineral land rights in 2010 and 2011. The expiries relate to capitalized costs of undeveloped lands for which no drilling was ever completed by the Corporation.
Management anticipates additional land expiries during the remainder of 2011, but will continue with drilling requirements in those areas of future focus. (See “Forward Looking Statements” in the “Advisory” section of this MD&A.)
| Management’s Discussion and Analysis | - 10 - | Compton Petroleum – Q2 2011 |
INTEREST AND FINANCE CHARGES
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Interest on bank debt, net | | $ | 2,074 | | | $ | 1,326 | | | $ | 4,211 | | | $ | 2,678 | |
| Interest on senior notes | | | 5,770 | | | | 9,267 | | | | 11,513 | | | | 18,644 | |
| Interest on finance leases | | | 20 | | | | 865 | | | | 47 | | | | 1,148 | |
| Interest expense | | | 7,864 | | | | 11,458 | | | | 15,771 | | | | 22,470 | |
| Finance charges and amortization of transaction cost | | | 1,445 | | | | 2,285 | | | | 3,095 | | | | 5,655 | |
| Total interest and finance charges | | $ | 9,309 | | | $ | 13,743 | | | $ | 18,866 | | | $ | 28,125 | |
Total interest and finance charges ($/boe) | | $ | 8.02 | | | $ | 7.66 | | | $ | 7.65 | | | $ | 7.99 | |
Interest expense for the second quarter of 2011 decreased by 32% and 33% on a year-to-date basis compared to the same periods in 2010. Although interest rates have increased, part of the overall decrease was a result of reduced borrowings on the revolving credit facility. Interest paid on the Senior Term Notes was reduced in part through the October 2010 restructuring and reduction of the amount outstanding. In addition, the strengthening of the Canadian dollar in relation to the US dollar has reduced the Canadian dollar equivalent amount paid. The expiry of certain finance leases in 2010 also reduced the interest component of lease obligations recognized.
Finance charges and amortization of transaction costs for the second quarter of 2011 decreased by $0.8 million or 37% compared to the same period in 2010, as a result of lower fees for unutilized credit. On a year-to-date basis, finance charges and amortization of transaction costs decreased by $2.6 million or 45% compared to the same period in 2010 due to the same reason.
Interest and finance charges decreased on a per boe basis due to lower overall borrowing costs, despite reduced production volumes.
The Corporations’ capital structure following the Recapitalization will significantly reduce interest and finance charges and related rates. (See “Forward Looking Statements” in the “Advisory” section of this MD&A.)
Effective interest rates on a weighted average debt basis are presented below.
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Credit Facility | | $ | 137,109 | | | $ | 108,945 | | | $ | 140,883 | | | $ | 99,138 | |
| Effective interest rate | | | 6.05 | % | | | 4.87 | % | | | 5.98 | % | | | 5.40 | % |
| | | | | | | | | | | | | | | | | |
| 2013 Senior term notes (US$) | | $ | - | | | $ | 450,000 | | | $ | - | | | $ | 450,000 | |
| Coupon Rate (US$) | | | - | | | | 7.625 | % | | | - | | | | 7.625 | % |
| Effective interest rate (Cdn$) | | | - | | | | 8.150 | % | | | - | | | | 8.150 | % |
| | | | | | | | | | | | | | | | | |
| 2011 Mandatory convertible senior term notes (US$) | | $ | 45,000 | | | $ | - | | | $ | 45,000 | | | $ | - | |
| Coupon Rate (US$) | | | 10 | % | | | - | | | | 10 | % | | | - | |
| Effective interest rate (Cdn$) | | | 9.68 | % | | | - | | | | 9.77 | % | | | - | |
| | | | | | | | | | | | | | | | | |
| 2017 Senior term notes (US$) | | $ | 193,500 | | | $ | - | | | $ | 193,500 | | | $ | - | |
| Coupon Rate (US$) | | | 10 | % | | | - | | | | 10 | % | | | - | |
| Effective interest rate (Cdn$) | | | 9.68 | % | | | - | | | | 9.77 | % | | | - | |
| Management’s Discussion and Analysis | - 11 - | Compton Petroleum – Q2 2011 |
RISK MANAGEMENT
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Commodity contracts | | | | | | | | | | | | |
| Realized (gain) loss | | $ | (3,690 | ) | | $ | (4,213 | ) | | $ | (7,094 | ) | | $ | (4,220 | ) |
| Unrealized (gain) loss | | | (148 | ) | | | 5,263 | | | | 5,981 | | | | (9,725 | ) |
| Foreign currency contracts | | | | | | | | | | | | | | | | |
| Unrealized (gain) loss | | | 102 | | | | (12 | ) | | | 306 | | | | - | |
| Total risk management (gain) loss | | $ | (3,736 | ) | | $ | 1,038 | | | $ | (807 | ) | | $ | (13,945 | ) |
| | | | | | | | | | | | | | | | | |
| Realized (gain) loss | | $ | (3,690 | ) | | $ | (4,213 | ) | | $ | (7,094 | ) | | $ | (4,220 | ) |
| Unrealized (gain) loss | | | (46 | ) | | | 5,251 | | | | 6,287 | | | | (9,725 | ) |
| Total risk management (gain) loss | | $ | (3,736 | ) | | $ | 1,038 | | | $ | (807 | ) | | $ | (13,945 | ) |
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.
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.
The Corporation uses hedges for natural gas denominated in giga joules (“GJ”) and million British thermal units (“MMBtu”), oil denominated in barrels and electricity denominated megawatt hours (“MWh”) to stabilize fluctuations in commodity pricing. Currency hedges are applied to reduce exposure to payments due in foreign currencies. The Corporation’s outstanding hedging instruments at June 30, 2011, expressed in Canadian dollars unless otherwise noted, are as follows:
| Management’s Discussion and Analysis | - 12 - | Compton Petroleum – Q2 2011 |
Type | Term | Volume | Average Price | Index |
| | | | | |
| Commodity | | | | |
| | | | | |
| Natural gas | | | | |
| Collars | Jul 2009 - Oct 2011 | 10,000 GJ/d | $4.50 - $7.00/GJ | AECO |
| US$ Swap | Apr 2011 - Oct 2011 | 15,000 MMBtu/d | $4.64/MMBtu | NYMEX |
| US$ Basis | Apr 2011 - Oct 2011 | 15,000 MMBtu/d | $(0.64)/MMBtu | NYMEX |
| US$ Swap | Jul 2011 - Dec 2012 | 10,000 MMBtu/d | $4.65/MMBtu | AECO |
| Swap | Jul 2011 - Dec 2011 | 10,000 GJ/d | $5.00/GJ | AECO |
| | | | | |
| Oil | | | | |
| US$ Option | Jan 2012 - Dec 2012 | 1,000 Bbl/d | $100.00/Bbl | WTI |
| US$ Option | July 2011 - Dec 2011 | 1,000 Bbl/d | $101.60/Bbl | WTI |
| | | | | |
| Electricity | | | | |
| Swap | Jan. 2010 - Dec. 2011 | 84 MWh/d | $50.74/MWh | AESO |
| | | | | |
| Currency | | | | |
| US$ Swap | September 15, 2011 | $9.7 million | $1.00 | N/A |
DEPLETION AND DEPRECIATION
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Total depletion and depreciation | | $ | 13,847 | | | $ | 22,881 | | | $ | 28,759 | | | $ | 45,345 | |
Depletion and depreciation ($/boe) | | $ | 11.93 | | | $ | 12.73 | | | $ | 11.66 | | | $ | 12.88 | |
Total depletion and depreciation expense decreased 39% during the second quarter and 37% on a year-to-date basis of 2011 as compared to 2010, largely due to a decrease in the asset base following impairments recognized under IFRS, and the reduction in overall production volumes. Depletion and depreciation expense per boe during the second quarter of 2011 decreased by 6% and by 9% on a year-to-date basis over the same period in 2010.
FOREIGN EXCHANGE AND OTHER (GAINS) AND LOSSES
| | | three months ended June 30, | | | six months ended June 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Foreign exchange on translation of US$ debt | | $ | (1,963 | ) | | $ | 20,250 | | | $ | (7,369 | ) | | $ | 6,300 | |
| (Gain)/loss on disposition of assets | | | 1,334 | | | | 2,540 | | | | (15,034 | ) | | | 2,540 | |
| Other | | | 130 | | | | 197 | | | | 156 | | | | (1,923 | ) |
| | | | | | | | | | | | | | | | | |
| Foreign exchange and other (gains) losses | | $ | (499 | ) | | $ | 22,987 | | | $ | (22,247 | ) | | $ | 6,917 | |
The foreign exchange and other gains recognized in second quarter of 2011 resulted primarily from the translation of the US dollar denominated Notes into Canadian dollars and from losses recognized on the disposition of petroleum and natural gas assets. 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. Proceeds from property dispositions are allocated first to the carrying value of the asset and any remaining proceeds are recognized through net earnings as gains or losses for the period.
| Management’s Discussion and Analysis | - 13 - | Compton Petroleum – Q2 2011 |
INCOME TAXES
Income taxes are recorded using the liability method of accounting. Deferred income taxes are calculated based on the temporary difference between the accounting and income tax basis of an asset or liability. Deferred income tax assets and liabilities are considered long term in nature under IFRS reporting.
A deferred income tax recovery of $3.2 million was recognized in the first quarter of 2011 as compared to $24.5 million expense for the comparable period in 2010. On a year-to-date basis, income tax recovery of $4.2 million was recognized in 2011 as compared to $24.5 million for the same period in 2010. Recoveries arise as a result of the change in timing for settlement of deferred tax assets and liabilities, and the change in tax rates applied. The impact of restatements and temporary differences related to IFRS has been adjusted for in deferred tax balances at June 30, 2011.
IV. Liquidity and Capital Resources
CAPITAL STRUCTURE
The Corporation’s capital structure is comprised of senior term notes, bank debt, 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 size and 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.
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” to steward the Corporation’s debt position as measures of Compton’s overall financial strength.
Adjusted EBITDA is a non-GAAP measure defined as net earnings (loss) before interest and finance charges, income taxes, depletion and depreciation, accretion of decommissioning liabilities, unrealized foreign exchange and other gains (losses), and unrealized risk management gains (losses). The Corporation targets a total net debt to Adjusted EBITDA of 2.5 to 3.0 times.
Capitalization is a non-GAAP measure defined as working capital, long-term debt including current portion, MPP term financing, and shareholders' equity. The Corporation targets a total net debt to Capitalization ratio of between 40% and 50%.
| | | As at June 30, 2011 | | | As at December 31, 2010 | |
| | | | | | | |
Working capital deficit(1) | | $ | 18,541 | | | $ | 23,428 | |
Credit facility(2) | | | 129,490 | | | | 145,584 | |
MPP term financing(3) | | | 40,366 | | | | 45,620 | |
Senior term notes(4) | | | 229,986 | | | | 237,212 | |
| Total net debt | | | 418,383 | | | | 451,844 | |
| Shareholders’ equity | | | 182,275 | | | | 187,198 | |
| Total capitalization | | $ | 600,658 | | | $ | 639,072 | |
| | | | | | | | | |
Total net debt to adjusted EBITDA(5) | | | 4.6 | x | | | 4.0 | x |
| Total net debt to total capitalization | | | 69.7 | % | | | 70.7 | % |
| (1) | Adjusted working capital excludes risk management, current MPP term financing and the credit facility. |
| (2) | Includes unamortized transaction costs of $nil (December 31, 2010 - $1,692) |
| (3) | Includes unamortized financing fees of $440 (December 31, 2010 - $520) |
| (4) | Includes unamortized original issue discount and related transaction costs of $nil (December 31, 2010 - $nil) |
| (5) | Based on trailing 12 month adjusted EBITDA |
| Management’s Discussion and Analysis | - 14 - | Compton Petroleum – Q2 2011 |
At June 30, 2011, the Corporation exceeded the targeted net debt to capitalization ratio as well as the net debt to adjusted EBITDA target. Shareholder equity was reduced as part of the transition to IFRS and the resulting adjustments recorded during 2010 negatively impacted earnings (loss) and retained earnings (deficit). These adjustments, at June 30, 2011, are disclosed in detail in Note 20 - “Transition to IFRS”, of the consolidated financial statements. Net proceeds from property sales in the first quarter of 2011 and a reduced capital expenditure program in the second quarter of 2011 combined to reduce the credit facility by $16.1 million in the first half of 2011. Unrealized gains on the translation of the US$ denominated senior term notes make up the balance of the debt reduction from that at December 31, 2010.
In June, Compton announced the Recapitalization, which is composed of the following key elements:
| | • | Conversion of US$193.5 million of Compton Finance 10% Senior Notes due 2017 and US$46.8 million of Compton Finance 10% Mandatory Convertible Notes due September 2011 into equity; and |
| | • | Addition of approximately $50.0 million of new equity raised by way of a backstopped Rights Offering (the “Rights Offering”), which will be applied to further reduce debt. |
The Recapitalization is expected to substantially improve financial strength and reduce financial risk for the Corporation. The conversion of Notes to equity retires approximately $274.3 million of debt, including the Mandatory Convertible Notes due in September 2011 and the Senior Notes due in 2017. In addition, the Rights Offering reduces the drawings on Compton’s Credit Facility by the amount of the net proceeds, after deducting costs incurred in completing the Recapitalization. Overall, this will improve the Corporation’s financial liquidity. Post Recapitalization, the Corporation’s net debt will be composed of the working capital, the Credit Facility and the MPP term financing.
WORKING CAPITAL
Compton had a working capital deficiency of $18.5 million at June 30, 2011, as compared to a deficiency of $23.4 million as at December 31, 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. (See “Forward Looking Statements” in the “Advisory” section of this MD&A.)
CREDIT FACILITY
The Corporation’s outstanding bank debt at June 30, 2011, net of cash on hand of $0.4 million, was $129.5 million. Effective June 15, 2011, Compton reached an agreement with the lenders under the Credit Facility to extend the term and maturity to September 22 and 23, 2011, respectively. The net borrowing base was set at $130.0 million, composed of both the working capital and production components of the Credit Facility. In addition, the lenders agreed to provide a $20.0 million supplemental facility (priced 300 basis points higher than the pricing under the working capital and production components of the Credit Facility), for total credit capacity under the credit facility of $150 million.
Upon completion of the Recapitalization, the net borrowing base of the credit facility will be increased to $160.0 million, the supplemental facility will be rolled into the production component of the Senior Bank Facility and the term and maturity under the credit facility will be extended to December 29 and 30, 2011, respectively. The Facility is subject to re-determination of the borrowing base at this time. 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.
| Management’s Discussion and Analysis | - 15 - | Compton Petroleum – Q2 2011 |
The Credit 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 Credit Facility is secured by a fixed and floating charge debenture on the assets of the Corporation.
The amount that may be drawn on the Credit Facility is limited, in certain circumstances, by a provision contained in the note indenture governing the Notes (the adjusted consolidated net tangible assets (“ACNTA”) test, detailed in “senior term notes” and “risks” herein). At June 30, 2011, the incremental borrowings were not capped under the ACNTA.
SENIOR TERM NOTES
Notes 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, 2011, the carrying value of the Notes decreased by $7.2 million from December 31, 2010. The decrease was as a result of the unrealized foreign exchange gain on translation at June 30, 2011.
On October 18, 2010, the Arrangement was completed resulting in the replacement of all the existing US$450.0 million 2013 Notes for a combination of:
| | (a) | US$193.5 million 10% notes due September 15, 2017 (the “2017 Notes”); |
| | (b) | US$45.0 million 10% notes due September 15, 2011 (the “2011 Mandatory Convertible Notes”); and |
| | (c) | US$184.5 million of cash, in part funded by a draw of $145.0 million from the Facility. |
The extinguishment of the 2013 Notes resulted in the recognition of a realized settlement gain of $9.0 million.
The 2011 Mandatory Convertible Notes are redeemable, in whole or in part, prior to maturity at face value. Based on the terms and specified conversion features of the 2011 Mandatory Convertible Notes the entire value has been presented as a financial liability in the consolidated financial statements.
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 fixed charge coverage ratio must exceed a trailing four quarters 2.5 to 1 threshold and if the Ratio is less than 2.5 to 1, the value calculated under the ACNTA test must exceed borrowings under the credit facilities. The Ratio restricts Compton’s ability to incur incremental debt, and the value determined under the ACNTA test restricts the borrowings under the credit facilities to the ACNTA calculated value.
At June 30, 2011, the Ratio was 2.53 to 1, exceeding the minimum ratio requirement. As a result, the amount of incremental borrowings the Corporation may incur were not limited. The Corporation may incur up to $260.5 million under the facility and certain other permitted debt.
Upon completion of the Recapitalization, both the Senior Term Notes and the 2011 Mandatory Convertible Notes will have been converted into equity, thus decreasing Compton’s total debt. Detailed information pertaining to the conversion can be found as described in the joint management proxy circular of Compton and Compton Petroleum Finance Corporation dated June 24, 2011.
| Management’s Discussion and Analysis | - 16 - | Compton Petroleum – Q2 2011 |
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 $40.4 million is included as a liability in the 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 11.64% 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, plus the principal portion of monthly base fee payments.
The purchase option represents the pre-determined price at which Compton may, at its discretion, purchase the MPP partnership on April 30, 2014. If Compton does not exercise this purchase option it may renew the MPP agreements with terms and conditions to be negotiated at that time, or enter into an arrangement with the owners of the MPP facilities to process natural gas for Compton at a fee to be determined at that time.
The MPP Agreements prescribe minimum throughput volumes and dedicated reserves which, if not exceeded, may require a buy-down of the purchase option. The minimum throughput volume is an average of the throughput volume of the preceding two consecutive calendar quarters. The prepayment amount is $400,000 per 1.0 mmcf/d of shortfall. Each prepayment of the purchase option will cause the minimum throughput volume to be adjusted downward to the average throughput volume of the preceding two consecutive calendar quarters for the balance of the contract period. In the event that the estimated dedicated reserves, as projected at April 30, 2014, are less than 200 BCF or have a discounted reserve value of less than $250 million using a 10% discount rate, the prepayment amount is the greater of $108,000 per $1 million of reserve value shortfall and $135,000 per 1.0 BCF of the reserves shortfall.
As of June 30, 2011, the threshold throughput volume was reduced to 56.0 mmcf/d. The cumulative prepayments of the purchase option are $4.0 million (2011 - $2.8 million; 2010 - $1.2 million; 2009 - $nil), reducing the amount of the MPP term financing liability. Subsequent to quarter end, an additional payment of $0.6 million was made. Dedicated reserves at December 31, 2010 did not exceed the minimum reserve test threshold as verified by a third party, resulting in a $5.5 million fee which was paid subsequent to quarter end. The reserve test fee will reduce the outstanding purchase option by an equal amount upon payment.
DEBT REPAYMENT AND LEASE OBLIGATIONS
As part of normal business, Compton has entered into arrangements and incurred obligations that will impact future operations and liquidity, some of which are reflected as liabilities in the consolidated financial statements. The following table summarizes all contractual obligations, with anticipated payment timing, as at December 31, 2010:
| | | 2011 | | | 2012 | | | 2013 | | | 2014 | | | 2015 | | | Thereafter | |
| | | | | | | | | | | | | | | | | | | |
| Credit facility | | $ | 130,000 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
| Senior term notes | | | 43,394 | | | | - | | | | - | | | | - | | | | - | | | | 186,592 | |
MPP term financing(1) | | | 10,896 | | | | 9,592 | | | | 9,592 | | | | 20,898 | | | | - | | | | - | |
| Accounts payable | | | 48,398 | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Finance leases | | | 179 | | | | 1,030 | | | | 224 | | | | 224 | | | | - | | | | - | |
| Office facilities | | | 947 | | | | 1,938 | | | | 2,001 | | | | 2,001 | | | | 2,046 | | | | 5,449 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | $ | 233,814 | | | $ | 12,560 | | | $ | 11,817 | | | $ | 23,123 | | | $ | 2,046 | | | $ | 192,041 | |
| (1) | Represents monthly fixed base fee payments; The 2011 amount includes purchase option repayments of $7.7 million |
| Management’s Discussion and Analysis | - 17 - | Compton Petroleum – Q2 2011 |
Following the current extension period expiring in September 2011, Compton intends to renew its credit facility. Therefore, repayment is not expected to occur, although has been included in the schedule of commitments consistent with its current term. Additional detail regarding the extension and renewal of the Facility is found in Note 5 - “Debt” and Note 19 - “Subsequent Event”.
The 2011 Mandatory Convertible Notes have been reflected above should they be repaid in cash. Upon completion of the Recapitalization, these notes will be converted to equity with no impact on cash.
V. Outlook
The current outlook for natural gas in North America remains weak throughout the remainder of 2011 and constrains the Corporation’s ability to generate cash flow for reinvestment. As a result, Management is focused on those areas of its asset base that provide the highest economic return and on areas that will help identify additional development opportunities for the Corporation. For the balance of 2011, Compton will focus on the liquids-rich, high return Niton area as well as its emerging oil opportunities in the Southern Plains area. These areas are expected to provide significant upside potential through their multiple zone development opportunities, contiguous land blocks and the impact of horizontal multi-stage fracture technology.
Compton is on track to achieve its 2011 guidance targets, including meeting the lower end of its production range, despite lower than anticipated capital expenditures to date. As a result of less capital spending in the first half of the year, Management is revising its 2011 capital expenditure guidance downward to between $45.0 and $50.0 million. The majority of the remaining capital will be utilized in the later months of the year with drilling commencing in late September. As a result, these activities will largely impact 2012 volumes. Compton is in the process of finalizing its future development plan and 2012 budget, which is expected to be released after the completion of the Recapitalization.
The Corporation has continued to take a prudent operational approach, reducing its cost structure, improving capital efficiencies and lowering debt while managing through a low commodity price environment. The Corporation has continued to meet or beat expectations in these areas. With the completion of the Recapitalization, Compton is positioned to put its full attention into the development of its asset base and position the Corporation for future growth.
VI. Internal Control Over Financial Reporting
The adoption of IFRS effected Compton’s presentation of financial results and the accompanying disclosures. The impact on processes, controls and financial reporting systems has been evaluated and modifications made to the control environment accordingly. There were no significant changes to internal control over financial reporting during the period beginning on January 1, 2011 and ending on June 30, 2011 that materially affected or are reasonably likely to materially affect Compton’s internal control over financial reporting.
Effective January 1, 2011 the Corporation engaged a third party service provider to support the development and testing of internal controls over financial reporting.
VII. Risks
The following discussion highlights key risks which could negatively impact Compton’s business, financial condition, and results of operations, cash flows and prospects.
Business Risks
Compton’s exploration and production activities are concentrated in the Western Canadian Sedimentary Basin, where activity is highly competitive and includes a variety of different sized companies ranging from smaller junior producers, intermediate and senior producers, to much larger integrated petroleum companies. Compton is subject to a number of risks that are also common to other organizations involved in the oil and gas industry. Such risks include: finding and developing oil and gas reserves at economic costs; estimating amounts of recoverable reserves; production of oil and gas in commercial quantities; marketability of oil and gas produced; fluctuations in commodity prices; financial and liquidity risks; and environmental and safety risks.
| Management’s Discussion and Analysis | - 18 - | Compton Petroleum – Q2 2011 |
In order to reduce exploration risk, Compton employs highly qualified and motivated professionals who have demonstrated the ability to generate high-quality proprietary geological and geophysical prospects. To maximize drilling success, Compton explores in areas that afford multi-zone prospect potential, targeting a range of shallower low to moderate risk prospects with some exposure to select deeper high-risk prospects that offer high-reward opportunities.
Compton engages an independent engineering consulting firm that assists the Corporation in evaluating recoverable amounts of oil and gas reserves. Values of recoverable reserves are based on a number of factors and assumptions such as commodity prices, projected production, future production costs and government regulation. Such estimates may vary from actual results.
The Corporation mitigates its risk related to producing hydrocarbons through the utilization of advanced technology and information systems. In addition, Compton operates the majority of its prospects, thereby maintaining operational control. The Corporation relies on its partners in jointly owned properties that Compton does not operate.
Compton is exposed to market risk to the extent that the demand for oil and gas produced by the Corporation exists within Canada and the United States. External factors beyond the Corporation’s control may affect the marketability of oil and gas. These factors include commodity prices and variations in the Canada-United States currency exchange rate, which in turn respond to economic and political circumstances throughout the world. Oil prices are affected by worldwide supply and demand fundamentals while natural gas prices are affected by North American supply and demand fundamentals. Compton may periodically use futures and options contracts to hedge its exposure against the potential adverse impact of commodity price volatility.
Exploration and production for oil and gas is very capital intensive. As a result, the Corporation relies on debt and equity markets as a source of capital. In addition, Compton utilizes bank financing to support on-going capital investment. Funds from operations also provide Compton with capital required to grow its business. Equity and debt capital is subject to market conditions and availability may increase or decrease from time to time. Funds from operations also fluctuate with changing commodity prices.
Safety and Environment
Oil and gas exploration and production can involve environmental risks such as pollution of the environment and destruction of natural habitat, as well as safety risks such as personal injury. The Corporation conducts its operations with high standards in order to protect the environment and the general public. Compton maintains current insurance coverage for comprehensive and general liability as well as limited pollution liability. The amount and terms of this insurance are reviewed on an ongoing basis and adjusted as necessary to reflect current corporate requirements, as well as industry standards and government regulations.
Additional Risk Factors
For a more detailed discussion of the business risk factors affecting the Corporation refer to Compton’s Annual Information Form for the year ended December 31, 2010, available on www.sedar.com.
| Management’s Discussion and Analysis | - 19 - | Compton Petroleum – Q2 2011 |
VIII. Forthcoming and Newly Adopted Accounting Policies
INTERNATIONAL FINANCIAL REPORTING STANDARDS
The Corporation’s consolidated interim financial statements for the six months ended June 30, 2011 are prepared in accordance with IAS 34 and IFRS 1.
IFRS 1 requires all first-time adopters to retrospectively apply all effective IFRS standards as of the transition date of January 1, 2010. However, it also provides certain optional exemptions and certain mandatory exceptions for first time IFRS adopters.
The Corporation has taken the following key optional exemptions upon transition to IFRS:
Deemed cost election for petroleum and natural gas assets
The Corporation has development and production recognized in the opening IFRS balance sheet. Under IFRS 1, the Corporation was allowed and elected to deem the value of its petroleum and natural gas assets, at the date of transition, based on the historical cost under Previous GAAP.
Decommissioning liabilities included in the cost of development and production
Under Previous GAAP, decommissioning liabilities were discounted at a credit adjusted risk free rate. Under IFRS the estimated cash flow to abandon and remediate the wells and fields has been risk adjusted; therefore the provision recognized on the balance sheet has been discounted at a risk free rate.
Business combinations
Compton has entered into business combinations before the date of transition of January 1, 2010. Compton has not elected to adopt IFRS 3 “Business Combinations” retrospectively. As a result, the classification of previous acquisitions under Previous GAAP will remain the same with no change in the recognition of assets and liabilities, excluding goodwill.
The impact of accounting policy selections under IFRS resulted in the following significant adjustments to the previously reported financial statement balances.
(a) Deferred taxes
Under Previous GAAP, the Corporation has recognized deferred tax assets and liabilities, primarily associated with its exploration and evaluation, development and production, and risk management activities. Under IFRS, current deferred tax balances have been re-classed for presentation entirely as long term assets/liabilities.
In addition, each of the balances adjusted through equity on transition to IFRS have been tax effected based on the Corporation’s estimated reversal rate of approximately 25%. For the six months ended June 30, 2010, the cumulative impact on the deferred tax liability was a decrease of $100.9 million. See the reconciliation of equity for adjustments that required a tax effect.
(b) Development and production
Under Previous GAAP, the Corporation followed full cost accounting for its petroleum and natural gas assets. This methodology enabled the capitalization of amounts exceeding those acceptable for IFRS. Under IFRS 1 on transition, the Corporation elected to allocate its full cost pool to its identified CGUs and then performed an impairment test.
Under the transitional election, an impairment test of the Corporation’s assets was required at a CGU level subsequent to the allocation. The Corporation recognized an impairment write-down of $263.9 million on its petroleum and natural gas assets at January 1, 2010. Write-downs were based on the recoverable amount of assets, representing value in use, under a 10% discounted cash flow. The write-downs were primarily recognized in two Southern Alberta CGUs with long reserve lives where the discount rates have the most impact on the value in use assessment.
| Management’s Discussion and Analysis | - 20 - | Compton Petroleum – Q2 2011 |
For the three and six months ended June 30, 2010 an impairment write-down of $72.8 million was recognized across certain CGUs. The impairments reflect the historically low natural gas pricing environment and outlook.
The restated IFRS balances also reflect gains and losses on the derecognition of assets disposed of during 2010 at Niton and Gilby. The combined net losses of $2.5 million have been included in the foreign exchange and other gains and losses presentation in net earnings (loss). Under Previous GAAP, proceeds on sales were deducted from the full cost pool without gain or loss recognition unless the disposition changed the depletion rate by more than 20%.
(c) Exploration and evaluation
IFRS 6 “Exploration and Evaluation of Mineral Resources” requires the separate recognition of exploration assets that have not yet established a determinable future value in the form of technically feasible and commercially viable reserves. The $72.4 million of exploration and evaluation costs recognized under IFRS on transition at January 1, 2010 represent the Corporation’s interest in undeveloped lands and mineral rights, and exploratory wells under evaluation.
For the three months ended June 30, 2010, the expiry of undeveloped mineral rights resulted in the derecognition of $24 thousand of exploration and evaluation assets, and have been presented as exploration expense in net earnings (loss).
For the six months ended June 30, 2010, land expiries charged to exploration and evaluation expense totaled $0.1 million.
(d) Other assets
Under a transitional election contained in IFRS 1, the Corporation eliminated unamortized actuarial gains of $0.2 million associated with the Mazeppa Processing Partnership defined benefit pension plan. In addition, vested past service costs of the pension plan totaling $0.6 million were also adjusted through equity on transition. The net result of both entries was a reduction in other assets of $0.4 million. There were no additional adjustments at June 30, 2010.
Also on transition, the Corporation adopted an accounting policy to recognize identifiable inventory items that are currently being marketed for sale or redeployment. Identifiable inventory of $2.2 million was initially recognized on transition at January 1, 2010 and is included for presentation purposes in other assets at the lower of cost and recoverable amounts. The recognition of inventory reduced development and production by $5.7 million, and a valuation allowance of $3.5 million was reflected in equity.
(e) Provisions
The estimated provision for decommissioning liabilities associated with the Corporation’s petroleum and natural gas assets has been adjusted on transition to IFRS. The adjustment reflects the application of a risk free rate for the discounting of the liability (based on the underlying assets), where under Previous GAAP this was measured using a credit risk adjusted rate. The adjustment to the discounted decommissioning liability recognized at June 30, 2010 was $91.6 million.
In addition, a provision of $13.9 million was recognized at January 1, 2010 for lease surrender costs payable, and a reduction of other corporate assets of $0.9 million in related leasehold improvements. The provision reflects the lower estimated cost of surrender for a portion of the corporate office space under lease, compared to the cost of fulfilling the contract. The undeveloped and unutilized space was determined by Management to be an onerous contract. The entire adjustment of $14.8 million was reflected in equity on transition.
| Management’s Discussion and Analysis | - 21 - | Compton Petroleum – Q2 2011 |
(f) Non-controlling interest
The presentation of non-controlling interest has been changed on transition from Previous GAAP to IFRS. Under IFRS, non-controlling interest is considered a component of equity and presentation reclassification was made. Minor adjustments in 2010 relating to the recognition and depletion of MPP facility assets, pension and decommissioning liabilities were also made.
For the three months ended June 30, 2010, the impact of transitional IFRS adjustments was $0.1 million.
For the six months ended June 30, 2010, the impact of transitional IFRS adjustments was $0.4 million.
(g) Royalties
The presentation of royalties under IFRS has changed from previous disclosures under Previous GAAP. Previously, royalties were aggregated in a single line and shown as a reduction of total revenue in net earnings. Under IFRS, crown and freehold royalties have been netted from revenues, all other royalties have been presented as “Other royalty obligations” in the expenses. In addition, gas cost allowances have been presented as a recovery of related processing fees included in operating expense.
(h) Leases
On transition to IFRS at January 1, 2010, the classification of certain leases were changed to be recognized as finance leases under IFRS. These leases have been included in trade and other accounts payable for financial statement purposes as they are not individually material. As a result of the reclassification, at June 30, 2011, development and production was increased by $7.1 million (net), capital lease obligations increased $6.4 million, and the impact of interest and depreciation expense of $1.1 million and $0.2 million respectively, was recorded through net earnings (loss).
(i) Share based payments
Under Previous GAAP, share based payments were recognized as an expense on a straight-line basis through the date of full vesting. Under IFRS, the expense is required to be recognized over the individual vesting periods for graded vesting awards.
For the three months ended June 30, 2010, an increase in share based compensation expense of $7 thousand from the revised valuation methodology. For the six months ended June 30, 2010, the increase was $0.3 million.
(j) Depletion
Upon transition to IFRS, the Corporation adopted a policy of depleting its petroleum and natural gas assets on a unit of production basis over proved plus probable reserves, by depletable component. The depletion policy under Previous GAAP was a unit of production over proved reserves in a single pool.
For the three months ended June 30, 2010, a decrease in depletion of $11.4 million resulted from the reduction of the Corporation’s petroleum and natural gas asset base and the revised depletion methodology. For the six months ended June 30, 2010, depletion expense was reduced by $23.0 million.
| Management’s Discussion and Analysis | - 22 - | Compton Petroleum – Q2 2011 |
CHANGES IN ACCOUNTING POLICIES
Recent Accounting Pronouncements
All accounting standards effective for periods on or after January 1, 2011 have been adopted as part of the transition to IFRS. The following new IFRS pronouncements have been issued but are not yet effective and may have an impact on the Corporation in the future:
The IASB issued IFRS 9, “Financial Instruments” as the initial phase of replacing IAS 39, “Financial Instruments: Recognition and Measurement”. The standard revises and limits the classification and measurement models available for financial assets and liabilities to amortized cost or fair value. Previously multiple models were available. This new standard is effective for annual periods beginning on or after January 1, 2013. The Corporation is currently assessing the impact of the new standard on its consolidated interim financial statements, but does not anticipate that the adoption of the standard will have a significant impact on the Corporation’s consolidated interim financial statements.
The IASB issued IFRS 10, “Consolidated Financial Statements” to supersede IAS 27 “Consolidated and Separate Financial Statements” and SIC 12 “Consolidation - Special Purpose Entities”. The standard builds on existing principles by identifying the concept of control as the determining factor in whether an entity should be included within the consolidated financial statements of the parent company. The standard provides additional guidance to assist in the determination of control where this is difficult to assess. This new standard is effective for annual periods beginning on or after January 1, 2013. The Corporation is currently assessing the impact of the new standard on its consolidated financial statements, but does not anticipate the standard having a significant impact on the Corporation’s consolidated financial statements.
The IASB issued IFRS 11, “Joint Arrangements” to supersede IAS 31 “Interests in Joint Ventures” and SIC 13 “Jointly Controlled Entities - Non-Monetary Contributions by Venturers”. The standard is intended to provide for a more realistic reflection of joint arrangements by focusing on the rights and obligations of the arrangement, rather than its legal form. This new standard is effective for annual periods beginning on or after January 1, 2013. The Corporation is currently assessing the impact of the new standard on its consolidated financial statements, but does not anticipate the standard having a significant impact on the Corporation’s consolidated financial statements.
The IASB issued IFRS 12, “Disclosure of Interests in Other Entities”. The standard specifies disclosure requirements for all forms of interests in other entities, including joint arrangements, associates, special purpose vehicles, and other off-balance-sheet vehicles. This new standard is effective for annual periods beginning on or after January 1, 2013. The Corporation is currently assessing the impact of the new standard on its consolidated financial statements, but does not anticipate the standard having a significant impact on the Corporation’s consolidated financial statements.
The IASB issued IFRS 13, “Fair Value Measurement”. The main provisions of the standard include defining fair value, setting out in a single standard a framework for measuring fair value, and specifying certain disclosure requirements about fair value measurements. This new standard is effective for annual periods beginning on or after January 1, 2013. The Corporation is currently assessing the impact of the new standard on its consolidated financial statements, but does not anticipate the standard having a significant impact on the Corporation’s consolidated financial statements.
The IASB issued IAS 19, “Post-Employment Benefits”. The provisions of the standard amend the recognition and measurement of defined pension expense, and expand disclosures for all employee benefit plans. This new standard is effective for annual periods beginning on or after January 1, 2013. The Corporation is currently assessing the impact of the new standard on its consolidated financial statements, but does not anticipate the standard having a significant impact on the Corporation’s consolidated financial statements.
| Management’s Discussion and Analysis | - 23 - | Compton Petroleum – Q2 2011 |
IX. Quarterly Information
The following table sets forth certain quarterly financial information of the Corporation for the five most recent quarters.
| ($millions, except where noted) | | | Q2 | | | | Q1 | | | | Q4 | | | | Q3 | | | | Q2 | | | | Q1 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total revenue | | $ | 70 | | | $ | 36 | | | $ | 40 | | | $ | 36 | | | $ | 49 | | | $ | 61 | |
| Cash flow | | $ | 7 | | | $ | 8 | | | $ | 10 | | | $ | 1 | | | $ | 10 | | | $ | 21 | |
Per share -basic | | $ | 0.03 | | | $ | 0.03 | | | $ | 0.04 | | | $ | 0.00 | | | $ | 0.04 | | | $ | 0.08 | |
- diluted | | $ | 0.01 | | | $ | 0.02 | | | $ | 0.03 | | | $ | 0.00 | | | $ | 0.04 | | | $ | 0.08 | |
| Net earnings (loss) | | $ | (8 | ) | | $ | 4 | | | $ | (444 | ) | | $ | (35 | ) | | $ | (86 | ) | | $ | 25 | |
Per share -basic | | $ | (0.03 | ) | | $ | 0.01 | | | $ | (1.68 | ) | | $ | (0.13 | ) | | $ | (0.33 | ) | | $ | 0.10 | |
- diluted | | $ | (0.03 | ) | | $ | 0.01 | | | $ | (1.68 | ) | | $ | (0.13 | ) | | $ | (0.33 | ) | | $ | 0.10 | |
| Operating earnings (loss) | | $ | (9 | ) | | $ | 3 | | | $ | 55 | | | $ | (51 | ) | | $ | (65 | ) | | $ | 2 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Production | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural gas (mmcf/d) | | | 65 | | | | 72 | | | | 75 | | | | 81 | | | | 98 | | | | 97 | |
| Liquids (bbls/d) | | | 1,947 | | | | 2,455 | | | | 2,411 | | | | 2,452 | | | | 3,076 | | | | 3,237 | |
| Total (boe/d) | | | 12,748 | | | | 14,507 | | | | 14,852 | | | | 15,931 | | | | 19,481 | | | | 19,411 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Average price | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural gas ($/mcf) | | $ | 4.10 | | | $ | 4.01 | | | $ | 3.87 | | | $ | 3.84 | | | $ | 4.15 | | | $ | 5.67 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Liquids ($/bbl) | | $ | 88.39 | | | $ | 69.11 | | | $ | 69.30 | | | $ | 59.39 | | | $ | 66.00 | | | $ | 67.59 | |
| Total ($/boe) | | $ | 34.35 | | | $ | 31.68 | | | $ | 30.70 | | | $ | 28.61 | | | $ | 31.41 | | | $ | 39.62 | |
| (1) | Prior periods have been revised to conform to current period presentation; Due to the transition to IFRS comparable information is only available from the date of transition, January 1, 2010. |
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. Continued depressed commodity prices and lower production volumes due to asset sales and natural declines contributed to decreased revenues throughout 2010 and 2011. The second quarter of 2011 also had reduced production levels resulting from a scheduled facility maintenance outage. Seasonality of winter operating conditions results in production increases that are typically higher in the third and fourth quarters.
Net earnings (loss) for each of last three quarters in 2010 include impairment adjustments for petroleum and natural gas assets following the transition to IFRS.
Cash flow and operating earnings (loss) are affected by changes in the US dollar against the Canadian dollar and realized hedging impacts over the periods presented.
X. Advisories
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 as prescribed by IFRS nor Previous GAAP 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.
| Management’s Discussion and Analysis | - 24 - | Compton Petroleum – Q2 2011 |
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.
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 statements are reasonable, it can give no assurance that such assumptions and expectations will prove to have been correct. There are many factors that could cause forward-looking statements not to be correct, including risks and uncertainties inherent in the 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-looking statements, as they involve the implied assessment, based on estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future.
The forward-looking statements contained herein are made as of the date of this 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 statement.
| Management’s Discussion and Analysis | - 25 - | Compton Petroleum – Q2 2011 |
