Exhibit 99.1
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 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. 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 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 annual consolidated financial statements in accordance with Canadian Generally Accepted Accounting Principles (“GAAP”).
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 June 3, 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 the Montana lands. Natural gas represents approximately 83% of production and 85% of proved reserves.
II. Results from Corporate Strategy
Management’s strategy is 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 first quarter of 2011 include:
| | • | Generated average daily production of 14,507 boe/d, which was relatively flat compared to 2010 exit volumes, notwithstanding reduced drilling; |
| | • | Reduced cost structure by a combined $7.8 million from the first quarter of 2010: |
| | • | Operating costs decreased by $2.2 million, a 16% decline as a result of reduced production levels and the Corporation’s continued focus on efficiency; |
| | • | Administrative costs decreased by 13% or $0.8 million due to restructuring completed at the end of 2010; and |
| | • | Interest and finance charges decreased by 34% or $4.8 million as a result of lower debt levels in 2011 compared to 2010. |
| | • | Drilled and participated in three wells, focusing on higher economic returns from high return, liquids rich natural gas in Niton; |
| | • | Successfully completed and tied in two Rock Creek wells at Niton that resulted in combined initial production rates of approximately 4.1 MMcf/d and 285 bbl/d of liquids; and |
| | • | Completed the sale of developed and undeveloped properties for gross proceeds of $26.2 million. |
Throughout 2010, Compton strengthened its balance sheet and improved the Corporation’s capital structure, reducing overall financial risk. In the first quarter of 2011, Management continued to evaluate opportunities for additional debt reduction and to make further, incremental improvements to the cost structure.
| Management’s Discussion and Analysis | - 1 - | Compton Petroleum – Q1 2011 |
III. Results of Operations
| Three months ended March 31, | | 2011 | | | 2010 | |
| ($000’s, except per share amounts) | | | | | | |
| | | | | | | |
| Average production (boe/d) | | | 14,507 | | | | 19,411 | |
| | | | | | | | | |
Capital expenditures(2) | | $ | 6,874 | | | $ | 10,743 | |
| | | | | | | | | |
Cash flow(1)(2) | | $ | 7,626 | | | $ | 20,886 | |
| Per share: basic | | $ | 0.03 | | | $ | 0.08 | |
diluted | | $ | 0.02 | | | $ | 0.08 | |
| | | | | | | | | |
Operating earnings(1)(2) | | $ | 2,443 | | | $ | 2,457 | |
| | | | | | | | | |
| Net earnings | | $ | 2,478 | | | $ | 25,220 | |
| Per share: basic | | $ | 0.01 | | | $ | 0.10 | |
diluted | | $ | 0.01 | | | $ | 0.10 | |
| | | | | | | | | |
| Revenue | | $ | 35,649 | | | $ | 60,786 | |
| | | | | | | | | |
Field netback (per boe)(1)(2) | | $ | 5.89 | | | $ | 11.12 | |
| (1) | Cash flow, operating earnings 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 |
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 and Analysis | - 2 - | Compton Petroleum – Q1 2011 |
| Three months ended March 31, | | 2011 | | | 2010 | |
| | | | | | | |
| Cash flow from operating activities | | $ | (8,101 | ) | | $ | 17,013 | |
| Less: change in non-cash working capital | | | (15,727 | ) | | | (3,873 | ) |
Cash flow(1) | | $ | 7,626 | | | $ | 20,886 | |
| (1) | Cash flow is a non-GAAP measure that is defined in this document |
Cash flow for the first quarter of 2011 decreased by approximately $13.3 million or 64% compared to 2010 as a result of:
| | • | a 26% decline in natural gas production volumes to 72 mmcf/d from 97 mmcf/d in 2010, resulting from the impact of asset sales completed in 2010, normal production declines, and the reduced level of capital expenditures; |
| | • | a 24% decline in liquids production volumes to 2,455 bbls/d from 3,237 bbls/d in 2010, resulting from the impact of property sales completed in 2010, normal production declines, and the reduced level of capital expenditures; and |
| | • | lower average realized natural gas prices, excluding financial hedges, which decreased 29% to $4.01 per mcf in 2011 compared to $5.67 per mcf in 2010. |
These factors were partially offset by:
| | • | higher average realized liquids prices, which increased 2% to $69.11 per bbl compared to $67.59 per bbl in 2010; |
| | • | realized risk management gains of $3.4 million compared to $nil in 2010; |
| | • | a $4.8 million decrease in interest and finance charges resulting from reduced debt levels in 2011 compared to 2010; |
| | • | lower operating costs of $2.2 million resulting from reduced production levels, and the continued focus on efficiency; and |
| | • | lower administrative costs of $0.8 million resulting from the restructuring completed at the end of 2010. |
NET EARNINGS
Net earnings for the first three months of 2011 was $2.5 million, a decrease of $22.7 million when compared to the $25.2 million net earnings in the same period for 2010. In addition to the factors that impacted cash flow, first quarter 2011 net earnings were affected by:
| | • | unrealized risk management losses of $6.3 million compared to a gain of $15.0 million in 2010; and |
| | • | increased exploration and evaluation costs of $4.4 million compared to $0.1 million in 2010, relating to the expiry of undeveloped land rights. |
These factors were partially offset by:
| | • | lower depletion expense of $14.9 million compared to $22.5 million in 2010, following asset impairments recognized throughout 2010; |
| | • | higher unrealized foreign exchange and other gains of $21.8 million compared to $16.1 million in 2010; including a $14.7 million gain on the disposition of undeveloped lands in the Niton area; and |
| | • | a $1.3 million lower share based payment expense following the restructuring of staff completed early in 2011. |
| Management’s Discussion and Analysis | - 3 - | Compton Petroleum – Q1 2011 |
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 earnings.
| Three months ended March 31, | | 2011 | | | 2010 | |
| | | | | | | |
| Net earnings, as reported | | $ | 2,478 | | | $ | 25,220 | |
| Non-operational items | | | | | | | | |
| Unrealized foreign exchange and other (gains) losses | | | (5,406 | ) | | | (13,950 | ) |
| Unrealized mark-to-market hedging (gains) losses | | | 6,333 | | | | (14,976 | ) |
| Other expenses | | | - | | | | 23 | |
| | | | | | | | | |
| Tax effect | | | (962 | ) | | | 6,140 | |
Operating earnings(1) | | $ | 2,443 | | | $ | 2,457 | |
| Per share - basic | | $ | 0.01 | | | $ | 0.01 | |
- diluted | | $ | 0.01 | | | $ | 0.01 | |
| (1) | Prior periods have been revised to conform to current period presentation |
CAPITAL EXPENDITURES
| Three months ended March 31, | | 2011 | | | 2010 | |
| | | | | | | |
| Exploration and evaluation | | | | | | |
| Land | | $ | 186 | | | $ | 891 | |
| Drilling and completions | | | 404 | | | | 455 | |
| | | | | | | | | |
| Development & production | | | | | | | | |
| Drilling and completions | | | 5,033 | | | | 7,988 | |
| Alberta Drilling Credits | | | - | | | | (1,980 | ) |
| Production facilities and equipment | | | 1,220 | | | | 3,351 | |
| Corporate and other | | | 31 | | | | 38 | |
| Total capital investment | | | 6,874 | | | | 10,743 | |
| | | | | | | | | |
| Divestitures | | | | | | | | |
| Property | | | (8,066 | ) | | | (56 | ) |
| Production facilities and equipment | | | (405 | ) | | | - | |
| Overriding Royalty | | | - | | | | (9,180 | ) |
| Land | | | (1,926 | ) | | | - | |
| Acquisitions (divestitures), net | | | (10,397 | ) | | | (9,236 | ) |
| | | | | | | | | |
| Total capital expenditures | | $ | (3,523 | ) | | $ | 1,507 | |
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 36% in the first quarter of 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 three wells (two operated wells and one non-operated wells), or 2.4 net wells, during 2011 as compared to a total of 13 wells (three operated wells and 10 non-operated wells), or 5.3 net wells, drilled during 2010. Capital expenditures in 2010 were partially offset by the implementation of the Alberta drilling credit program. The cap in place on available Alberta drilling credits did not permit recognition of any credits in 2011.
| Management’s Discussion and Analysis | - 4 - | Compton Petroleum – Q1 2011 |
Looking forward, Management plans to execute a capital program that is funded through available cash flows and funds from other sources. The majority of 2011 capital expenditures are scheduled in the second half of the year, but the program remains flexible should commodity price levels increase and additional funds become available.
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 first quarter 2011 free cash flow of $0.9 million is lower as compared to the first quarter of 2010 due to the significant decline in commodity prices, and Management’s focused approach to capital investment.
| Three months ended March 31, | | 2011 | | | 2010 | |
| | | | | | | |
| Cash flow | | $ | 7,626 | | | $ | 20,886 | |
| Less: capital investment | | | 6,874 | | | | 10,743 | |
| Free cash flow | | $ | 752 | | | $ | 10,143 | |
PRODUCTION VOLUMES AND REVENUES
| Three months ended March 31, | 2011 | | | 2010 | |
| | | | | | |
| Average production | | | | | | |
Natural gas (mmcf/d) | | | 72 | | | | 97 | |
Liquids (bbls/d) | | | 2,455 | | | | 3,237 | |
Total (boe/d) | | | 14,507 | | | | 19,411 | |
| | | | | | | | | |
| Benchmark prices | | | | | | | | |
AECO ($/GJ) | | | | | | | | |
| Monthly index | | $ | 3.58 | | | $ | 5.08 | |
| Daily index | | $ | 3.56 | | | $ | 4.69 | |
WTI (US$/bbl) | | $ | 94.03 | | | $ | 78.71 | |
Edmonton sweet light ($/bbl) | | $ | 88.00 | | | $ | 80.11 | |
| | | | | | | | | |
| Realized prices | | | | | | | | |
Natural gas ($/mcf) | | $ | 4.01 | | | $ | 5.67 | |
Liquids ($/bbl) | | $ | 69.11 | | | $ | 67.59 | |
Total ($/boe) | | $ | 31.68 | | | $ | 39.62 | |
| | | | | | | | | |
Sales Revenue(1)(2) | | | | | | | | |
| Natural gas | | $ | 26,095 | | | $ | 49,524 | |
| Liquids | | | 16,607 | | | | 21,743 | |
| Total | | $ | 42,702 | | | $ | 71,267 | |
| (1) | Gross sales revenues are before crown and freehold royalties |
| (2) | Prior periods have been revised to conform to current period presentation |
Production volumes for the first three months of 2011 were 25% lower than in 2010 primarily due to natural declines, the reduced asset base following property dispositions throughout 2010, and limited new production additions in 2011.
Revenue decreased by 40% for the first 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 first quarter of 2011 was a favorable $0.44 per mcf, compared to a $nil impact per mcf in 2010.
| Management’s Discussion and Analysis | - 5 - | Compton Petroleum – Q1 2011 |
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 $/boe basis. Funds flow netback equals field netback less administrative and interest costs. Field netback and funds flow netback should not be considered more meaningful than or an alternative to net earnings as determined in accordance with GAAP. The following provides the calculation of field netback and funds flow netback.
| Three months ended March 31, | | 2011 | | | 2010 | |
| ($/boe) | | | | | | |
Realized price(1) | | $ | 31.68 | | | $ | 39.62 | |
| Processing revenue | | | 1.03 | | | | 1.18 | |
| Realized commodity hedge gain (loss) | | | 2.61 | | | | - | |
| Royalties | | | (8.50 | ) | | | (9.48 | ) |
| Operating expenses | | | (8.92 | ) | | | (7.94 | ) |
| Transportation | | | (1.01 | ) | | | (0.86 | ) |
| Field netback | | $ | 16.89 | | | $ | 22.52 | |
| | | | | | | | | |
| Administrative | | $ | (3.68 | ) | | $ | (3.18 | ) |
| Interest | | | (7.32 | ) | | | (8.22 | ) |
| Funds flow netback | | $ | 5.89 | | | $ | 11.12 | |
(1) Prior periods have been revised to conform to current period presentation
ROYALTIES
| Three months ended March 31, | | 2011 | | | 2010 | |
| | | | | | | |
| Crown royalties | | $ | 4,962 | | | $ | 7,836 | |
| Freehold royalties | | | 2,090 | | | | 2,645 | |
| Royalties included in revenue | | | 7,052 | | | | 10,481 | |
| | | | | | | | | |
Overriding royalty(2) | | | 1,855 | | | | 2,705 | |
| Other royalties | | | 512 | | | | 1,162 | |
| Freehold mineral taxes | | | 1,684 | | | | 2,217 | |
| Other royalty obligations expense | | | 4,051 | | | | 6,084 | |
| | | | | | | | | |
| Total royalties | | $ | 11,103 | | | $ | 16,565 | |
| | | | | | | | | |
| Percentage of sales revenue | | | 26.0 | % | | | 23.2 | % |
(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 33% for the first three months of 2011 compared to 2010, largely due to lower natural gas prices and the reduction in produced volumes. A higher proportion of fixed rate freehold royalties resulted in a 2.8% increase in royalties as a percentage of sales revenue.
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.
| Management’s Discussion and Analysis | - 6 - | Compton Petroleum – Q1 2011 |
OPERATING EXPENSES
| Three months ended March 31, | | 2011 | | | 2010 | |
| | | | | | | |
| Operating expenses | | $ | 11,644 | | | $ | 13,879 | |
Operating expenses ($/boe) | | $ | 8.92 | | | $ | 7.94 | |
Operating expenses decreased by 16% in the first quarter of 2011, while per boe costs increased by 12% from 2010. The decrease on a total dollar basis was a result of continued cost control initiatives identified and implemented by the Corporation. The increase in per boe costs reflects the fixed cost component of certain operating costs, spread over the reduced production quarter over quarter.
TRANSPORTATION
| Three months ended March 31, | | 2011 | | | 2010 | |
| | | | | | | |
| Transportation costs | | $ | 1,317 | | | $ | 1,499 | |
Transportation costs ($/boe) | | $ | 1.01 | | | $ | 0.86 | |
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 decreased by 12% in the first quarter of 2011 when compared to 2010, while per boe amounts increased by 17%. 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 March 31, | | 2011 | | | 2010 | |
| | | | | | | |
| Gross administrative expenses | | $ | 6,545 | | | $ | 8,709 | |
| Capitalized administrative expenses | | | (781 | ) | | | (1,547 | ) |
| Operator recoveries | | | (964 | ) | | | (1,612 | ) |
| Administrative expenses | | $ | 4,800 | | | $ | 5,550 | |
Administrative expenses ($/boe) | | $ | 3.68 | | | $ | 3.18 | |
Administrative expenses per boe increased 16% in the first quarter of 2011 compared to 2010, despite total administrative cost reductions of 25% on gross expenditures, and 14% net of capitalized costs and operator recoveries. 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.
STOCK-BASED COMPENSATION
| Three months ended March 31, | | 2011 | | | 2010 | |
| | | | | | | |
| Stock option plan | | $ | (442 | ) | | $ | 709 | |
| Employee share purchase plan | | | 183 | | | | 284 | |
| | | | | | | | | |
| Stock-based compensation | | $ | (259 | ) | | $ | 993 | |
Following the restructuring of staff completed in 2010, a recovery of previously expensed share based compensation was recorded in the first quarter 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.
| Management’s Discussion and Analysis | - 7 - | Compton Petroleum – Q1 2011 |
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 quarter of 2011, or the comparative period for 2010.
EXPLORATION AND EVALUATION
| Three months ended March 31, | | 2011 | | | 2010 | |
| | | | | | | |
| Exploration and evaluation | | $ | 4,498 | | | $ | 102 | |
Total costs ($/boe) | | $ | 3.45 | | | $ | 0.06 | |
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.
INTEREST AND FINANCE CHARGES
| Three months ended March 31, | | 2011 | | | 2010 | |
| | | | | | | |
| Interest on bank debt, net | | $ | 5,743 | | | $ | 9,377 | |
| Interest on senior notes | | | 2,137 | | | | 1,352 | |
| Interest on finance leases | | | 27 | | | | 283 | |
| Interest expense | | | 7,907 | | | | 11,012 | |
| Finance charges and amortization of transaction cost | | | 1,650 | | | | 3,370 | |
| Total interest and finance charges | | $ | 9,557 | | | $ | 14,382 | |
Total interest and finance charges ($/boe) | | $ | 7.32 | | | $ | 8.22 | |
Interest expense for the first quarter of 2011 decreased by 28% compared to the same period 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 first quarter of 2011 decreased by $1.7 million or 51% compared to the same period in 2010, as a result of lower fees for unutilized credit.
Interest and finance charges decreased on a per boe basis due to lower overall borrowing costs, despite reduced production volumes.
| Management’s Discussion and Analysis | - 8 - | Compton Petroleum – Q1 2011 |
Effective interest rates on a weighted average debt basis are presented below.
| Three months ended March 31, | | 2011 | | | 2010 | |
| | | | | | | |
| Credit Facility | | $ | 144,700 | | | $ | 93,222 | |
| Effective interest rate | | | 5.91 | % | | | 5.8 | % |
| | | | | | | | | |
| 2013 Senior term notes (US$) | | $ | - | | | $ | 450,000 | |
| Coupon Rate (US$) | | | - | | | | 7.625 | % |
| Effective interest rate (Cdn$) | | | - | | | | 8.150 | % |
| | | | | | | | | |
| 2011 Mandatory convertible senior term notes (US$) | | $ | 45,000 | | | $ | - | |
| Coupon Rate (US$) | | | 10.00 | % | | | - | |
| Effective interest rate (Cdn$) | | | 9.72 | % | | | | |
| | | | | | | | | |
| 2017 Senior term notes (US$) | | $ | 193,500 | | | $ | - | |
| Coupon Rate (US$) | | | 10.00 | % | | | - | |
| Effective interest rate (Cdn$) | | | 9.72 | % | | | | |
RISK MANAGEMENT
| Three months ended March 31, | | 2011 | | | 2010 | |
| | | | | | | |
| Commodity contracts | | | | | | |
| Realized (gain) loss | | $ | (3,404 | ) | | $ | (7 | ) |
| Unrealized (gain) loss | | | 6,129 | | | | (14,988 | ) |
| Foreign currency contracts | | | | | | | | |
| Unrealized (gain) loss | | | 204 | | | | 12 | |
| Total risk management (gain) loss | | $ | 2,929 | | | $ | (14,983 | ) |
| | | | | | | | | |
| Realized (gain) loss | | $ | (3,404 | ) | | $ | (7 | ) |
| Unrealized (gain) loss | | | 6,333 | | | | (14,976 | ) |
| Total risk management (gain) loss | | $ | 2,929 | | | $ | (14,983 | ) |
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 March 31, 2011, expressed in Canadian dollars unless otherwise noted, are as follows:
| Management’s Discussion and Analysis | - 9 - | Compton Petroleum – Q1 2011 |
| Type | Term | Volume | Average Price | Index |
| Commodity | | | | |
| Natural gas | | | | |
| Collars | July 2009 - June 2011 | 30,250 GJ/d | $4.52 - $7.02/GJ | AECO |
| Collars | July 2009 - Oct. 2011 | 10,000 GJ/d | $4.50 - $7.00/GJ | AECO |
| US Swap | April 2011 - Oct. 2011 | 15,000 MMBtu/d | $4.64/MMBtu | NYMEX |
| US Basis | April 2011 - Oct. 2011 | 15,000 MMBtu/d | $(0.64)/MMBtu | NYMEX |
| US Swap | July 2011 - Dec. 2012 | 10,000 MMBtu/d | $4.65/MMBtu | NYMEX |
| Oil | | | | |
| US Option | Jan. 2012 - Dec. 2012 | 1,000 Bbl/d | USD $100.00/Bbl | WTI |
| Electricity | | | | |
| Swap | Jan. 2010 - Dec. 2011 | 84 MWh/d | $50.74/MWh | AESO |
| | | | | |
| Currency | | | | |
| US Dollar Swap | September 15, 2011 | $9.7 million | $1.00 | N/A |
DEPLETION AND DEPRECIATION
| Three months ended March 31, | | 2011 | | | 2010 | |
| | | | | | | |
| Total depletion and depreciation | | $ | 14,912 | | | $ | 22,464 | |
Depletion and depreciation ($/boe) | | $ | 11.42 | | | $ | 12.86 | |
Total depletion and depreciation expense decreased 34% during the first three months 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 in 2011 decreased by 11% over the same period in 2010.
FOREIGN EXCHANGE AND OTHER (GAINS) AND LOSSES
| Three months ended March 31, | | 2011 | | | 2010 | |
| | | | | | | |
| Foreign exchange translation of US$ debt | | $ | (5,406 | ) | | $ | (13,950 | ) |
| Disposition of assets | | | (16,368 | ) | | | - | |
| Other | | | 26 | | | | (2,120 | ) |
| Total foreign exchange and other (gains) and losses | | $ | (21,748 | ) | | $ | (16,070 | ) |
The foreign exchange and other gains recognized in first quarter of 2011 resulted primarily from the translation of the US dollar denominated Notes into Canadian dollars and from gains 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 income as gains or losses for the period.
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.
| Management’s Discussion and Analysis | - 10 - | Compton Petroleum – Q1 2011 |
A deferred income tax recovery of $0.9 million was recognized in the first quarter of 2011 as compared to $0.1 million expense for the comparable 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 have been adjusted for in deferred tax balances at March 31, 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 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 before interest and finance charges, income taxes, depletion and depreciation, accretion of asset retirement obligation, 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 March 31, 2011 | | | As at December 31, 2010 | |
| | | | | | | |
Working capital deficit(1) | | $ | 7,403 | | | $ | 23,428 | |
Credit facility(2) | | | 137,206 | | | | 145,584 | |
MPP term financing(3) | | | 43,218 | | | | 45,620 | |
Senior term notes(4) | | | 231,774 | | | | 237,212 | |
| Total net debt | | | 419,601 | | | | 451,844 | |
| Shareholders’ equity | | | 190,216 | | | | 187,198 | |
| Total capitalization | | $ | 609,817 | | | $ | 639,042 | |
| | | | | | | | | |
Total net debt to adjusted EBITDA(5) | | | 4.4 | x | | | 4.0 | x |
| Total net debt to total capitalization | | | 68.8 | % | | | 70.7 | % |
(1) | Adjusted working capital excludes risk management, current MPP term financing and Facility. |
| (2) | Includes unamortized transaction costs of $275 (December 31, 2010 - $1,692; January 1, 2010 - $1,279) |
| (3) | Includes unamortized financing fees of $480 (December 31, 2010 - $520; January 1, 2010 - $679) |
| (4) | Includes unamortized original issue discount and related transaction costs of $nil (December 31, 2010 - $nil; January 1, 2010 - $9,229) |
| (5) | Based on trailing 12 month adjusted EBITDA |
| Management’s Discussion and Analysis | - 11 - | Compton Petroleum – Q1 2011 |
At March 31, 2011, the Corporation exceeded the targeted net debt to capitalization ratio. Shareholder equity was reduced as part of the transition to IFRS and the resulting adjustments recorded during 2010 negatively impacted earnings and retained earnings. These adjustments are disclosed in detail in Note 19 - “Transition to IFRS”, of the consolidated financial statements. Management continues to evaluate alternatives to further reduce the Corporation’s debt levels and improve alignment with the established targets.
Of total net debt, 55% is comprised of Notes, of which $43.7 million matures September 15, 2011, and $188.0 million that mature on September 15 2017. The $25.4 million purchase option component of the MPP term financing matures on April 30, 2014, and represents 6% of total net debt.
WORKING CAPITAL
Compton had a working capital deficiency of $7.4 million at March 31, 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.
CREDIT FACILITY
The Corporation’s outstanding bank debt at March 31, 2010, net of cash on hand of $7.2 million, of $137.2 million was drawn on a revolving term facility authorized at $145 million and a revolving working capital facility authorized at $15 million (for a total of $160 million). The credit facilities were renewed on June 30, 2010 for a period of 366 days until July 1, 2011. 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 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.
The amount that may be drawn on the 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 March 31, 2011, the ACNTA test capped the borrowings under the credit facilities to $269.0 million.
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 March 31, 2011, the carrying value of the Notes decreased by $5.4 million from December 31, 2010. The decrease was as a result of the unrealized foreign exchange gain on translation at March 31, 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.
| Management’s Discussion and Analysis | - 12 - | Compton Petroleum – Q1 2011 |
The 2011 Mandatory Convertible Notes are redeemable, in whole or in part, prior to maturity at face value. Redemption is required at maturity, or in the event any share issuance proceeds are received prior to the maturity date. 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. Management anticipates redemption of the 2011 Mandatory Convertible Notes in 2011 prior to maturity.
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 March 31, 2011, the Ratio was 1.88 to 1, which was below the minimum requirement and thereby restricts the amount of incremental borrowings the Corporation may incur. Based on the ACNTA calculation, Compton may incur up to $269.0 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 effect on the operations of the Corporation (see “risks - liquidity risk”).
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 $43.2 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 11.42% 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 March 31, 2011, the threshold throughput volume was reduced to 57.50 mmcf/d. The cumulative prepayments of the purchase option are $2.4 million (2011 - $1.2 million; 2010 - $1.2 million; 2009 - $nil), reducing the amount of the MPP term financing liability. Subsequent to quarter end, an additional payment of $1.6 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 is due prior to June 30, 2011. The reserve test fee will reduce the outstanding purchase option upon payment.
| Management’s Discussion and Analysis | - 13 - | Compton Petroleum – Q1 2011 |
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 | |
| | | | | | | | | | | | | | | | | | | |
| Bank debt | | $ | 144,700 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
| Senior term notes | | | 43,731 | | | | - | | | | - | | | | - | | | | - | | | | 188,043 | |
MPP term financing(1) | | | 14,283 | | | | 9,592 | | | | 9,592 | | | | 21,513 | | | | - | | | | - | |
| Accounts payable | | | 35,310 | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Finance leases | | | 336 | | | | 1,232 | | | | 224 | | | | 224 | | | | - | | | | - | |
| Office facilities | | | 1,420 | | | | 1,938 | | | | 2,001 | | | | 2,001 | | | | 2,046 | | | | 5,449 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | $ | 239,780 | | | $ | 12,762 | | | $ | 11,817 | | | $ | 23,738 | | | $ | 2,046 | | | $ | 193,492 | |
| (1) | Represents monthly fixed base fee payments; The 2011 amount includes purchase option repayments of $7.1 million |
Compton intends to renew its Facility. Therefore the repayment is not expected to occur, although it has been included in the schedule of commitments consistent with its current term.
The 2011 Mandatory Convertible Notes have been reflected above should they be repaid in cash. If not redeemed for cash, at September 15, 2011, these notes will mature and convert to equity with no impact on cash.
V. Outlook
The current outlook for natural gas in North America is expected to continue into 2011 and constrain the Corporation’s cash flows levels. As a result, Compton continues to focus on those areas of its asset base that provide the highest economic return and on areas that will help identify additional future development opportunities for the Corporation. In 2011, Compton will focus on the liquids-rich, high return Niton area as well as its emerging oil opportunities in the Southern Plains area , providing significant upside potential through its multiple zone development opportunities and contiguous land blocks.
Compton has demonstrated a disciplined approach to capital investment and a prudent approach to the financial management of its capital structure. Management remains committed to this philosophy and will continue to explore ways to further improve corporate value and reduce the amount of debt outstanding. Compton’s asset base provides solid growth potential through a focused land position, multi-zone opportunities and positive impact from horizontal multi-stage fracture technology. The Corporation has shown its ability to be a strong operator through its solid improvements in drilling and operations. Compton continues to take a selective approach to its business, identifying and evaluating various opportunities to capture unrealized value for the Corporation and maximize future shareholder benefit.
Compton’s current debt level continues to be a concern. While the debt reductions over the past two years were significant, they did not result in the targeted adjustment in debt ratios due to the continued decline in natural gas prices. As a result, with continued low natural gas prices, the Corporation needs to further revise its capital structure to normalize its debt to a level more comparable to its industry peers. In addition, Management is mindful of key dates related to the US$45 million Mandatory Convertible Notes (“MCN”) and the credit facility review. Normalizing the capital structure will allow Compton to have an appropriate debt level, sufficient cash flow to adequately invest in and develop its asset base, and provide accretive growth over a multi-year horizon.
| Management’s Discussion and Analysis | - 14 - | Compton Petroleum – Q1 2011 |
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 March 31, 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, 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.
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.
| Management’s Discussion and Analysis | - 15 - | Compton Petroleum – Q1 2011 |
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.
VIII. Forthcoming and Newly Adopted Accounting Policies
INTERNATIONAL FINANCIAL REPORTING STANDARDS
The Corporation has prepared its March 31, 2011 interim consolidated financial statements in accordance with IFRS 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 it’s interim and annual consolidated financial statements in accordance with Canadian Generally Accepted Accounting Principles (“GAAP”). The adoption of IFRS has not had a material impact on strategic direction, operations, cash flows or capital development.
The Corporation’s significant accounting policies are disclosed in Note 2 - “Significant Accounting Policies”, to the interim consolidated financial statements. A complete reconciliation of adjustments from previously reported financial results under GAAP are also presented in Note 19 - “Transition to IFRS”. The reconciliations include consolidated balance sheets as at January 1, 2010, March 31, 2010 and December 31, 2010, as well as consolidated statements of earnings and comprehensive income, changes in shareholders’ equity and cash flows for the three months ended March 31, 2010 and for the twelve months ended December 31, 2010.
The following discussions outline the impacted areas of transition, elections made under IFRS, key accounting policy selections and significant financial reporting changes.
The Corporation has taken the following optional exemptions upon transition to IFRS:
Deemed cost election for petroleum and natural gas assets
The Corporation has property plant, plant and equipment (“PP&E”) 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 Canadian GAAP. Assets subject to the allocation include exploration and development costs and production equipment and processing facilities, excluding undeveloped properties and land, and the Mazeppa facility previously consolidated under AcG 15 “Consolidation of Variable Interest Entities”.
As a result of electing this optional exemption, petroleum and natural gas assets were allocated to appropriate components within each cash generating unit (“CGU”) based on a proration factor using discounted cash flows from total proved plus probable reserves at January 1, 2010. Additionally, assets were tested for impairment on January 1, 2010, in accordance with IAS 36 “Impairment of Assets”. The result of the impairment test was a write-down of the Corporation’s petroleum and natural gas assets of $263.9 million.
| Management’s Discussion and Analysis | - 16 - | Compton Petroleum – Q1 2011 |
Exploration and evaluation costs, representing undeveloped land and exploratory well costs, were recognized on transition at January 1, 2010, based on previously recognized costs.
Corporate assets were allocated to individual CGUs in each of the Corporation’s South and Central operations. On the transition date, Compton has elected to use the historical cost basis for their corporate assets, therefore the amounts allocated will be based on historical cost under GAAP.
Decommissioning liabilities included in the cost of development and production
Under 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 is discounted at a risk free rate, which resulted in an $83.2 million increase to the discounted obligation recognized on the balance sheet. By using the deemed cost election discussed above, the Corporation was able to measure its decommissioning liability as at the date of transition in accordance with IAS 37 “Provisions, Contingent Liabilities and Contingent Assets”, and recognize in retained earnings the difference between the re-measured amount and the carrying amount of the liability at the date of transition to IFRS determined under GAAP.
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 GAAP will remain the same with no change in the recognition of assets and liabilities, excluding goodwill. There was no goodwill outstanding at January 1, 2010 on transition to IFRS.
Share based payment transactions
IFRS 2 “Share-based Payments” encourages application of its provisions to equity instruments granted on or before November 7, 2002, but permits, by exemption under IFRS 1, the application only to equity instruments granted after November 7, 2002 that had not vested by the transition date. The Corporation has both equity and cash settled share based payment transactions and has elected to take this exemption. For equity settled instruments that were granted and fully vested by January 1, 2010, IFRS 2 does not need to be applied retrospectively or for cash settled transactions that were settled before January 1, 2010.
Recognition of all cumulative actuarial gains and losses for defined benefit pension plans
This exemption allows the Corporation to recognize all cumulative actuarial gains and losses for all defined benefit plans at January 1, 2010 thus resetting any corridor amount recognized under GAAP to zero. This exemption applies to unamortized actuarial gains and losses only. The Corporation, through its consolidation of the Mazeppa Processing Partnership, has an applicable defined benefit plan to which the exemption relates. The result of the adjustment was a reduction of the Corporation’s other assets of $0.2 million.
Determining whether an arrangement contains a lease
This exemption permits the Corporation to avoid retrospective application of IFRIC 4 "Determining whether an arrangement contains a lease". This exemption allows a first-time adopter to determine whether an arrangement existing at the date of transition to IFRSs contains a lease on the basis of facts and circumstances existing at that date, rather than at the inception of the arrangement. Therefore any change in the determination of whether an arrangement contains a lease can be applied prospectively.
| Management’s Discussion and Analysis | - 17 - | Compton Petroleum – Q1 2011 |
Capitalization of borrowing costs
The Corporation, by taking this election, can limit capitalization of borrowing costs relating to qualifying assets for which the commencement date for capitalization is on or after January 1, 2009 (effective date) or the date of transition, whichever is later. As the Corporation did not capitalize borrowing costs under GAAP, this exemption enabled Compton to generate a specific policy to apply prospectively.
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 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 rate of reversal, which approximates 25%. At January 1, 2010 the impact to deferred taxes was a decrease in the deferred tax liability of $91.5 million. For the year ended December 31, 2010, the cumulative impact on the deferred tax liability was $160.7 million. For the three months ended March 31, 2010, the cumulative impact on the deferred tax liability was a decrease of $88.0 million. See the reconciliation of equity for adjustments that required a tax effect.
(b) Development and production
Under 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. On transition under IFRS 1, 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. 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.
For the three months ended March 31, 2010 no impairment was recognized on the Corporation’s assets. For the year ended December 31, 2010, an impairment write-down of $695.4 million was recognized across all CGUs. The impairments reflect the historically low natural gas pricing environment and outlook. Under GAAP a $367.0 million ceiling test impairment was recognized on petroleum and natural gas assets at December 31, 2010.
The restated IFRS balances also reflect gains and losses on the de-recognition of assets disposed of during 2010 at Niton and Gilby. The combined net losses of $5.3 million have been included in the foreign exchange and other gains and losses presentation in net earnings. Previously under 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.
| Management’s Discussion and Analysis | - 18 - | Compton Petroleum – Q1 2011 |
For the year ended December 31, 2010, the expiry of undeveloped mineral rights resulted in the de-recognition of $2.1 million of exploration and evaluation assets, and have been presented as exploration expense in net earnings.
For the three months ended March 31, 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 March 31, 2010 and December 31, 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 previously under GAAP this was measured using a credit risk adjusted rate. The adjustment to the discounted decommissioning liability recognized at January 1, 2010 was $83.2 million. Under an IFRS 1 election, this adjustment has been reflected directly to equity on transition. The adjustment to the discounted decommissioning liability recognized at March 31, 2010 and December 31, 2010 were $84.5 million and $123.9 million, respectively.
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.
At December 31, 2010, the revision of decommissioning liability cost estimates increased the provisional liability by $59.0 million. The revisions related primarily to well abandonment costs based on the historical costs of the corporation. These assumptions were adjusted downward in 2011 to better align with inflation adjusted regulatory guidance and updated information. See Note 9 - “Provisions”.
(f) Non-controlling interest
The presentation of non-controlling interest has been changed on transition from GAAP to IFRS. Under IFRS, non-controlling interest is considered a component of equity and presentation reclassification was made. Minor adjustments on transition relating to the recognition and depletion of MPP facility assets, pension and decommissioning liabilities were also made.
For the three months ended March 31, 2010 the cumulative impact of transitional IFRS adjustments was $0.3 million.
For the year ended December 31, 2010 the cumulative impact of transitional IFRS adjustments was $0.3 million.
| Management’s Discussion and Analysis | - 19 - | Compton Petroleum – Q1 2011 |
The presentation of royalties under IFRS has changed from previous disclosures under 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 allowance has 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 accounts payable for financial statement purposes as they are not individually material. As a result of the reclassification, development and production was increased by $9.9 million (net), capital lease obligations increased $8.9 million, and the cumulative impact of interest and depreciation expense of $1.0 million related to the assets, was offset to equity at January 1, 2010.
At March 31, 2010, development and production was increased by $9.2 million (net), capital lease obligations increased $8.3 million, and the cumulative impact of interest and depreciation expense of $0.3 million and $0.1 million respectively, was recorded through net earnings.
At December 31, 2010, development and production increased by $2.1 million (net), capital lease obligations increased $2.2 million, and the cumulative impact of interest and depreciation expense of $1.6 million and $0.6 million respectively, was recorded through net earnings.
(i) Share based payments
Under Canadian 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. At January 1, 2010, this change in valuation resulted in a $0.9 million increase in “Other reserves”, and was offset directly to equity.
For the year ended December 31, 2010, an increase in share based compensation expense of $0.4 million resulted from the revised valuation methodology. For the three months ended March 31, 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 GAAP was a unit of production over proved reserves in a single pool. There was no impact on adoption of IFRS at January 1, 2010, as provided by the IFRS 1 deemed cost allocation election.
For the year ended December 31, 2010, a decrease in depletion of $52.8 million resulted from the reduction of the Corporation’s petroleum and natural gas asset base and the revised depletion methodology.
For the three months ended March 31, 2010, depletion expense was reduced by $11.7 million. Ceiling test impairments recognized under GAAP were previously disclosed in depletion and depreciation.
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Under GAAP, the aggregate tax effect of all flow-through share renouncements in excess of the premium liability associated with flow-through share issuances were recognized as a reduction of share capital. No specific guidance is provided regarding this issue under IFRS; however, it has been interpreted that guidance applied under US GAAP is acceptable under IFRS. Under US GAAP, issuance proceeds were disaggregated between the fair market value of the shares issued and the premium paid for the renounced expenditures. A deferred tax liability was accrued upon effective date of the renouncement and the deferred tax expense was charged to net earnings rather than to share capital. On transition to IFRS at January 1, 2010, deferred tax expense of $30.0 million was re-classed from share capital to retained earnings.
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. 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.
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IX. Quarterly Information
The following table sets forth certain quarterly financial information of the Corporation for the five most recent quarters.
| | | | | | | | 2011 | | | | | | | | | 2010 | | | | |
($millions, except where noted) | | | Q1 | | | | Q4 | | | | Q3 | | | | Q2 | | | | Q1 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total revenue | | | | $ | 36 | | | $ | 40 | | | $ | 36 | | | $ | 49 | | | $ | 61 | |
| Cash flow | | | | | | | $ | 8 | | | $ | 10 | | | $ | 1 | | | $ | 10 | | | $ | 21 | |
| Per share - | basic | | $ | 0.03 | | | $ | 0.04 | | | $ | 0.00 | | | $ | 0.04 | | | $ | 0.08 | |
| | - | | | diluted | | $ | 0.02 | | | $ | 0.03 | | | $ | 0.00 | | | $ | 0.04 | | | $ | 0.08 | |
| Net earnings (loss) | | $ | 2 | | | $ | (444 | ) | | $ | (35 | ) | | $ | (86 | ) | | $ | 25 | |
| Per share - | basic | | $ | 0.01 | | | $ | (1.68 | ) | | $ | (0.13 | ) | | $ | (0.33 | ) | | $ | 0.10 | |
| | - | | | diluted | | $ | 0.01 | | | $ | (1.68 | ) | | $ | (0.13 | ) | | $ | (0.33 | ) | | $ | 0.10 | |
| Operating earnings | | $ | 2 | | | $ | 55 | | | $ | (51 | ) | | $ | (65 | ) | | $ | 2 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Production | | | | | | | | | | | | | | | | | | | | | | | | | | |
Natural gas (mmcf/d) | | | 72 | | | | 75 | | | | 81 | | | | 98 | | | | 97 | |
Liquids (bbls/d) | | | 2,455 | | | | 2,411 | | | | 2,452 | | | | 3,076 | | | | 3,237 | |
Total (boe/d) | | | | | 14,507 | | | | 14,852 | | | | 15,931 | | | | 19,481 | | | | 19,411 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Average price | | | | | | | | | | | | | | | | | | | | | | |
Natural gas ($/mcf) | | $ | 4.01 | | | $ | 3.87 | | | $ | 3.84 | | | $ | 4.15 | | | $ | 5.67 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Liquids ($/bbl) | | $ | 69.11 | | | $ | 69.30 | | | $ | 59.39 | | | $ | 66.00 | | | $ | 67.59 | |
Total ($/boe) | | | | $ | 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 production base stabilized in the final quarter of 2010. Seasonality of winter operating conditions results in production increases that are typically higher in the third and fourth quarters.
Net earnings 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 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 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.
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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 | - 23 - | Compton Petroleum – Q1 2011 |
