Exhbiti 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 and nine months ended September 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 (“IFRS”). 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 November 7, 2011.
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 majority of the Corporation’s operations are located in the Deep Basin fairway of the Western Canada Sedimentary Basin, providing multi-zone potential for future development and exploration opportunity.
With approximately 84% natural gas, Compton has shifted its strategy to focus on developing its high-return, liquids-rich natural gas areas at Niton and balancing its portfolio through emerging crude oil opportunities to offset continued low natural gas prices. The Corporation maximizes value by concentrating on properties that generate strong returns on capital investment, such as the Rock Creek Formation at Niton, and developing new horizons such as the Wilrich and Notikewin.
Compton’s emerging oil plays target the Bakken/Big Valley, Ellerslie and Glauconite Formations in the Southern Plains area as well as future exploratory potential through the joint venture on its Montana Bakken/Big Valley lands. The successful development of these areas is expected to provide growth in oil production and reserves, further augmenting the Corporation’s large natural gas reserves that can be capitalized on when natural gas markets recover.
Through further improving operating efficiencies, maximizing returns on capital invested and focusing on higher return assets, Compton will create value by providing appropriate investment returns for shareholders.
| II. | RESULTS FROM CORPORATE STRATEGY |
Management’s strategy throughout 2011 has been to strengthen its capital structure and position itself for growth through improving its operating efficiencies. Management has continued to deliver on commitments, improving the operational and financial performance of the Corporation by lowering debt, reducing its cost structure, improving capital efficiencies and generating positive cash flow within a low commodity price environment. Results for third quarter of 2011 include:
Management’s Discussion and Analysis Compton Petroleum – Q3 2011 | Page 1 |
| | • | Completed the Recapitalization plan of arrangement (the “Recapitalization”) to return Compton’s capital structure to levels more consistent with current natural gas producers (see “Liquidity and Capital Resources - Capital Structure”), substantially improving financial strength and comparability with industry peers; |
| | • | Reduced net debt by 68% to $144.8 million since December 31, 2010, and by 83% from $854.7 million as at September 30, 2009; |
| | • | Negotiated an industry standard borrowing base credit facility of $160.0 million with a new syndicate of lenders for a one year term, and one year maturity thereafter if not renewed; |
| | • | Continued to reduce key cost structures by a combined $7.8 million (or 46%) from the third quarter of 2010: |
| | • | Administrative costs decreased by 60% or $3.2 million due to restructuring completed at the end of 2010; and |
| | • | Interest and finance charges decreased by 40% or $4.6 million as a result of lower debt levels in 2011 compared to 2010; |
| | • | Generated average daily production of 13,429 boe/d, attaining a relatively flat production profile with limited capital spending in 2011; |
| | • | Participated in a non-operated Wilrich (Spirit River) horizontal well (33.3% working interest) in the Niton area. Located in the centre of the Corporation’s core lands, the well was tied-in and is currently on production at approximately 2.9 mmcf/d. Liquid rates are still being confirmed but are expected to be greater than 20 bbl/mmcf; and |
| | • | Signed a farmout and joint venture agreement on its Montana Bakken property subsequent to the quarter. At their cost, the joint venture partner has committed to completion of a survey program at a minimum cost of $2.0 million on or before July 31, 2012 and the drilling of a test well on or before December 31, 2012. |
With the completion of the Recapitalization in late September, 2011, Management is now positioned to focus on drilling and liquids exploration to develop its high-return, liquid-rich natural gas areas at Niton and emerging crude oil opportunities in the Southern Plans. These activities are expected to provide the opportunity for accretive growth over a multi-year horizon.
Management’s Discussion and Analysis Compton Petroleum – Q3 2011 | Page 2 |
| III. | RESULTS OF OPERATIONS |
| | | three months ended September 30, | | | nine months ended September 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Average production (boe/d) | | | 13,429 | | | | 15,931 | | | | 13,557 | | | | 18,261 | |
| | | | | | | | | | | | | | | | | |
Capital expenditures(2) | | $ | 7,805 | | | $ | 11,900 | | | $ | 23,173 | | | $ | 37,902 | |
| | | | | | | | | | | | | | | | | |
Cash flow (1)(2) | | $ | 15,308 | | | $ | 846 | | | $ | 30,078 | | | $ | 31,804 | |
| Per share - basic | | $ | 1.76 | | | $ | 0.64 | | | $ | 7.91 | | | $ | 24.13 | |
| - diluted | | $ | 1.28 | | | $ | 0.64 | | | $ | 3.52 | | | $ | 24.13 | |
| | | | | | | | | | | | | | | | | |
Operating earnings (loss)(1)(2) | | $ | (2,022 | ) | | $ | (16,291 | ) | | $ | (1,096 | ) | | $ | (29,932 | ) |
| | | | | | | | | | | | | | | | | |
| Net earnings (loss) | | $ | 28,307 | | | $ | (33,055 | ) | | $ | 24,090 | | | $ | (97,604 | ) |
| Per share - basic | | $ | 3.26 | | | $ | (25.08 | ) | | $ | 6.34 | | | $ | (74.05 | ) |
| - diluted | | $ | 2.43 | | | $ | (25.08 | ) | | $ | 3.03 | | | $ | (74.05 | ) |
| | | | | | | | | | | | | | | | | |
| Revenue | | $ | 38,971 | | | $ | 36,728 | | | $ | 109,304 | | | $ | 146,400 | |
| | | | | | | | | | | | | | | | | |
Field netback (per boe) (1)(2) | | $ | 20.97 | | | $ | 15.71 | | | $ | 18.96 | | | $ | 18.68 | |
| | (1) | Cash flow, operating loss and field netback are non-GAAP measures that are defined in this document |
| | (2) | Prior periods have been revised to conform to current period presentation |
| | (3) | Total shares outstanding changed from 263.6 million to 26.4 million on August 10, 2011 in accordance with the Recapitalization |
CASH FLOW
Cash flow is considered a non-GAAP measure and 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 September 30, | | | nine months ended September 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Cash flow from operating activities | | $ | 5,654 | | | $ | 5,979 | | | $ | 16,010 | | | $ | 21,729 | |
Add: Recapitalization cost(2) | | | 661 | | | | - | | | | 661 | | | | - | |
| Less: change in non-cash working capital | | | (8,993 | ) | | | 5,133 | | | | (13,407 | ) | | | (10,075 | ) |
Cash Flow (1) | | $ | 15,308 | | | $ | 846 | | | $ | 30,078 | | | $ | 31,804 | |
| | (1) | Cash flow is a non-GAAP measure that is defined in this document |
| | (2) | On August 23, 2011 the USD Senior Term Notes were converted to equity and fully extinguished |
Cash flow for the third quarter of 2011 was $15.3 million, an increase of approximately $14.5 million compared to 2010. The increase in cash flow during the quarter was a result of:
| | • | higher average realized natural gas prices, excluding financial hedges, which increased 4% to $4.01 per mcf compared to $3.84 per mcf in 2010; |
Management’s Discussion and Analysis Compton Petroleum – Q3 2011 | Page 3 |
| | • | higher average realized liquids prices, which increased 32% to $78.10 per bbl compared to $59.39 per bbl in 2010; |
| | • | a decline in interest and finance charges of $4.6 million in 2011, resulting from reduced debt levels compared to 2010; and |
| | • | a decline in administrative costs of $3.2 million in 2011, resulting from the restructuring completed at the end of 2010. |
These factors were partially offset by:
| | • | a 17% decline in natural gas production volumes to 67 mmcf/d from 81 mmcf/d in 2010, resulting from the impact of asset sales, normal production declines, and the reduced level of capital expenditures; |
| | • | a 9% decline in liquids production volumes to 2,240 bbls/d from 2,452 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 $3.1 million compared to 3.7 million in 2010. |
On a year-to-date basis, cash flow decreased by approximately $1.7 million or 5% when compared to 2010 as a result of:
| | • | a 26% decline in natural gas production volumes to 68 mmcf/d from 92 mmcf/d in 2010, resulting from the impact of asset sales, normal production declines, and the reduced level of capital expenditures; |
| | • | a 24% decline in liquids production volumes to 2,213 bbls/d from 2,919 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 12% to $4.04 per mcf compared to $4.59 per mcf in 2010. |
These factors were partially offset by:
| | • | higher average realized liquids prices, which increased 20% to $77.83 per bbl compared to $64.71 per bbl in 2010; |
| | • | realized risk management gains of $10.2 million compared to $7.9 million in 2010; |
| | • | a decline in interest and finance charges of $13.9 million in 2011, resulting from reduced debt levels compared to 2010; |
| | • | a decline in operating costs of $6.6 million in 2011, resulting from reduced production levels, and the continued focus on efficiency; and |
| | • | a decline in administrative costs of $5.5 million in 2011, resulting from the restructuring completed at the end of 2010. |
NET EARNINGS (LOSS)
Net earnings for the third quarter of 2011 were $28.3 million, an increase of $61.4 million when compared to the $33.1 million net loss in the same period for 2010. In addition to the factors that impacted cash flow, third quarter 2011 net earnings was affected by:
| | • | an impairment expense of $44.9 million in 2010; |
| | • | a gain on extinguishment of the senior term notes of $56.0 million; and |
| | • | lower depletion and depreciation expense of $15.3 million compared to $18.0 million in 2010, following asset impairments recognized on transition to IFRS throughout 2010. |
Management’s Discussion and Analysis Compton Petroleum – Q3 2011 | Page 4 |
These factors were partially offset by:
| | • | an increase in exploration and evaluation expense to $11.4 million compared to $0.5 million in 2010, relating to costs associated with exploratory wells, and the expiry of undeveloped land; |
| | • | an increase in the deferred tax expense to $14.3 million, compared to a recovery of $9.9 million in 2010; |
| | • | a decline in unrealized risk management gains of $3.3 million compared to a gain of $5.6 million in 2010; and |
| | • | a decline in unrealized foreign exchange and other losses of $5.8 million compared to gain of $13.9 million 2010. |
On a year-to-date basis, net earnings were $24.1million, an improvement of $121.7 million when compared to the $97.6 million net loss in the same period for 2010. In addition to the factors that impacted cash flow, year-to-date net earnings were favourably affected by:
| | • | a gain on extinguishment of the Senior Term Notes of $56.0 million; |
| | • | an impairment reversal of $0.4 million in 2011 compared to a $117.7 million impairment expense in 2010; |
| | • | a decline in depletion and depreciation expense to $44.3 million compared to $63.4 million in 2010, following asset impairments recognized on transition to IFRS throughout 2010; and |
| | • | a decline in share based compensation expense to $0.1 million compared to $3.0 million in 2010, following the restructuring of staff completed in early 2011. |
These factors were partially offset by:
| | • | an increase in exploration and evaluation expense to $21.0 million compared to $0.7 million in 2010, relating to costs associated with exploratory wells, and the expiry of undeveloped land; |
| | • | an increase in the deferred tax expense to $10.1 million, compared to a recovery of $34.3 million in 2010; |
| | • | a decline in unrealized risk management losses to $2.9 million compared to a gain of $15.3 million in 2010; and |
| | • | a decline in unrealized foreign exchange and other gains to $1.5 million compared to gain of $7.6 million 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.
Management’s Discussion and Analysis Compton Petroleum – Q3 2011 | Page 5 |
| | | three months ended September 30, | | | nine months ended September 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Net earnings (loss), as reported | | $ | 28,307 | | | $ | (33,055 | ) | | $ | 24,090 | | | $ | (97,604 | ) |
| Non-operation items | | | | | | | | | | | | | | | | |
| Unrealized foreign exchange and other (gains) losses | | | 5,839 | | | | (13,860 | ) | | | (1,528 | ) | | | (7,560 | ) |
| Unrealized mark to market hedging (gains) losses | | | (3,344 | ) | | | (5,594 | ) | | | 2,943 | | | | (15,319 | ) |
| Exploratory land expiries | | | 11,358 | | | | 525 | | | | 20,975 | | | | 651 | |
| Impairment expense (reversals) | | | (148 | ) | | | 44,907 | | | | (435 | ) | | | 117,664 | |
| Gain on Senior Term Notes extinguishment | | | (55,962 | ) | | | - | | | | (55,962 | ) | | | - | |
| Other expenses | | | - | | | | - | | | | - | | | | 23 | |
| Tax effect | | | 11,928 | | | | (9,214 | ) | | | 8,821 | | | | (27,787 | ) |
Operating earnings (loss) (1) | | $ | (2,022 | ) | | $ | (16,291 | ) | | $ | (1,096 | ) | | $ | (29,932 | ) |
Per share basic (2) | | $ | (0.23 | ) | | $ | (12.36 | ) | | $ | (0.29 | ) | | $ | (22.71 | ) |
diluted (2) | | $ | (0.23 | ) | | $ | (12.36 | ) | | $ | (0.29 | ) | | $ | (22.71 | ) |
(1) Prior periods have been revised to conform to current period presentation
(2) Total shares outstanding changed from 263.6 million to 26.4 million on August 10, 2011 in accordance with the Recapitalization
Operating loss for the three and nine months ended September 30, 2011, has improved considerably over 2010 comparable periods, despite continuing low natural gas prices. Operating earnings are expected to increase going forward with the continued efficiencies from reductions in interest, administrative and operating costs. (See “Forward Looking Statements” in the “Advisory” section of the MD&A.)
CAPITAL EXPENDITURES
| | | three months ended September 30, | | | nine months ended September 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Exploration & evaluation | | | | | | | | | | | | |
| Land | | $ | 1,939 | | | $ | 1,078 | | | $ | 2,896 | | | $ | 3,051 | |
| Drilling and completions | | | 448 | | | | 1,188 | | | | 963 | | | | 1,392 | |
| | | | | | | | | | | | | | | | | |
| Development & production | | | | | | | | | | | | | | | | |
| Drilling and completions | | | 3,035 | | | | 6,963 | | | | 11,061 | | | | 24,870 | |
| Alberta Drilling Credits | | | - | | | | 394 | | | | - | | | | (4,327 | ) |
| Production facilities and equipment | | | 2,325 | | | | 2,188 | | | | 8,085 | | | | 12,446 | |
| Corporate and other | | | 58 | | | | 89 | | | | 168 | | | | 470 | |
| Total capital investment | | | 7,805 | | | | 11,900 | | | | 23,173 | | | | 37,902 | |
| | | | | | | | | | | | | | | | | |
| Divestitures | | | | | | | | | | | | | | | | |
| Property | | | 8 | | | | (36,077 | ) | | | (8,058 | ) | | | (153,484 | ) |
| Production facilities and equipment | | | - | | | | - | | | | (405 | ) | | | - | |
| Overriding royalty | | | - | | | | - | | | | - | | | | (23,469 | ) |
| Land | | | - | | | | - | | | | (2,126 | ) | | | - | |
| Acquisitions (divestitures), net | | | 8 | | | | (36,077 | ) | | | (10,589 | ) | | | (176,953 | ) |
| | | | | | | | | | | | | | | | | |
| Total capital expenditures | | $ | 7,813 | | | $ | (24,177 | ) | | $ | 12,584 | | | $ | (139,051 | ) |
Management’s Discussion and Analysis Compton Petroleum – Q3 2011 | Page 6 |
Current natural gas prices have limited internally generated cash flow available to invest in drilling activities. As a result, capital spending, before acquisitions and divestments decreased by 34% in the third quarter and 39% 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 in Southern Plains. Compton participated in one non-operated well (0.3 net well), during the third quarter of 2011 as compared to a total of 4 wells (2.7 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.
During the third quarter, Compton participated in a non-operated Wilrich (Spirit River) horizontal well (33.3% working interest) in the Niton area. Located in the centre of the Corporation’s core lands, the well was tied-in and is currently on production at approximately 2.9 mmcf/d. Liquids rates are being confirmed but are expected to be greater than 20 bbl/mmcf. Compton also completed the acquisition of 25 sections of land in the Southern Plains area, prospective for the Big Valley/Bakken Formation. The Corporation has secured all prospective land holdings for developing the new play and with initial success, the play has the potential to expand into approximately 90 locations.
Compton’s winter drilling program commenced at the beginning of October with two rigs operating at present. Two vertical oil wells were drilled to target the Basal Quartz and Ellerslie Formations in the Southern Plains, and a Rock Creek horizontal well is currently being drilled in Niton. A third rig is expected in Niton for mid-November to drill the first Wilrich well. With the drilling program ramping up, it’s anticipated that five to seven wells will be drilled prior to year-end in Niton and the Southern Plains.
Subsequent to the quarter end, the Corporation announced the signing of a farmout and joint venture agreement related its 79,000 net acres of undeveloped land holdings in northern Montana. The farmout joint venture grants the joint venture partner with the ability to earn a 50% interest in this area by incurring capital expenditures on the exploration and development of the property. Compton will retain a 50% working interest in the area without incurring any capital expenditure commitments. At their cost, the joint venture partner has committed to completion of a survey program at a minimum cost of $2.0 million on or before July 31, 2012 and the drilling of a test well targeting the Bakken Formation on or before December 31, 2012.
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 third quarter 2011 free cash flow of $7.5 million is higher compared to the deficit in the third quarter of 2010 due to lower capital expenditures in 2011 and the focused cost reduction initiatives implemented during the strategic review and restructuring process completed in 2010. On a year-to-date basis, free cash flow is $13.0 million higher as compared to 2010 for the same reasons.
Management’s Discussion and Analysis Compton Petroleum – Q3 2011 | Page 7 |
| | | three months ended September 30, | | | nine months ended September 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Cash flow | | $ | 15,308 | | | $ | 846 | | | $ | 30,078 | | | $ | 31,804 | |
| Less: capital investment | | | (7,805 | ) | | | (11,900 | ) | | | (23,173 | ) | | | (37,902 | ) |
| Free cash flow | | $ | 7,503 | | | $ | (11,054 | ) | | $ | 6,905 | | | $ | (6,098 | ) |
| | | | | | | | | | | | | | | | | |
| Production volumes and revenues | | | | | | | | | | | | | | | | |
| Average production | | | | | | | | | | | | | | | | |
| Natural gas (mmcf/d) | | | 67 | | | | 81 | | | | 68 | | | | 92 | |
| Liquids (bbls/d) | | | 2,240 | | | | 2,452 | | | | 2,213 | | | | 2,919 | |
| Total (boe/d) | | | 13,429 | | | | 15,931 | | | | 13,557 | | | | 18,261 | |
| | | | | | | | | | | | | | | | | |
| Benchmark prices | | | | | | | | | | | | | | | | |
| AECO ($/GJ) | | | | | | | | | | | | | | | | |
| Monthly index | | $ | 3.53 | | | $ | 3.52 | | | $ | 3.93 | | | $ | 4.09 | |
| Daily index | | $ | 3.47 | | | $ | 3.36 | | | $ | 3.57 | | | $ | 3.91 | |
| WTI (US$/bbl) | | $ | 89.76 | | | $ | 76.23 | | | $ | 95.45 | | | $ | 77.66 | |
| Edmonton sweet light ($/bbl) | | $ | 91.78 | | | $ | 74.44 | | | $ | 94.29 | | | $ | 76.59 | |
| | | | | | | | | | | | | | | | | |
| Realized prices | | | | | | | | | | | | | | | | |
| Natural gas ($/mcf) | | $ | 4.01 | | | $ | 3.84 | | | $ | 4.04 | | | $ | 4.59 | |
| Liquids ($/bbl) | | $ | 78.10 | | | $ | 59.39 | | | $ | 77.83 | | | $ | 64.71 | |
| Total ($/boe) | | $ | 33.06 | | | $ | 28.61 | | | $ | 32.98 | | | $ | 33.46 | |
| | | | | | | | | | | | | | | | | |
Sales Revenue(1)(2) | | | | | | | | | | | | | | | | |
| Natural gas | | $ | 24,745 | | | $ | 28,534 | | | $ | 75,028 | | | $ | 115,268 | |
| Liquids | | | 18,648 | | | | 14,939 | | | | 52,759 | | | | 56,883 | |
| Total | | $ | 43,393 | | | $ | 43,473 | | | $ | 127,787 | | | $ | 172,151 | |
| | (1) | Sales revenues are before crown and freehold royalties |
| | (2) | Prior periods have been revised to conform to current period presentation |
Production volumes for the third quarter of 2011 were 16% 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.
Compared to 2010, sales revenue remained consistent for the third quarter of 2011. The lower production volumes in 2011 were offset by increased realized natural gas and liquids prices. Realized prices and revenues are before any hedging gains or losses. The impact from hedging on realized natural gas prices in the third quarter of 2011 was a $0.51 per mcf compared to $1.05 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 $/boe basis. Funds flow netback equals field netback less administrative and interest costs. Field netback and funds flow netback should not be considered more meaningful than or an alternative to net earnings as determined in accordance with IFRS.
Field netback and funds flow netback has increased for both the third quarter and year-to-date 2011 compared to 2010 despite reduced volumes and higher percentages of fixed operating costs. The following provides the calculation of field netback and funds flow netback.
Management’s Discussion and Analysis Compton Petroleum – Q3 2011 | Page 8 |
| | | three months ended September 30, | | | nine months ended September 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| ($/boe) | | | | | | | | | | | | |
Realized price (1) | | $ | 33.06 | | | $ | 28.61 | | | $ | 32.98 | | | $ | 33.46 | |
| Processing revenue | | | 2.07 | | | | 1.05 | | | | 1.55 | | | | 1.07 | |
| Realized commodity hedge gain | | | 2.55 | | | | 2.49 | | | | 2.77 | | | | 1.58 | |
| Royalties | | | (5.48 | ) | | | (6.48 | ) | | | (7.38 | ) | | | (7.69 | ) |
| Operating Expenses | | | (9.89 | ) | | | (8.31 | ) | | | (9.75 | ) | | | (8.57 | ) |
| Transportation | | | (1.34 | ) | | | (1.65 | ) | | | (1.21 | ) | | | (1.17 | ) |
| Field netback | | $ | 20.97 | | | $ | 15.71 | | | $ | 18.96 | | | $ | 18.68 | |
| | | | | | | | | | | | | | | | | |
| Administrative | | $ | (1.76 | ) | | $ | (3.68 | ) | | $ | (2.99 | ) | | $ | (3.34 | ) |
| Interest | | | (5.53 | ) | | | (7.80 | ) | | | (6.94 | ) | | | (7.94 | ) |
| Funds flow netback | | $ | 13.68 | | | $ | 4.23 | | | $ | 9.03 | | | $ | 7.40 | |
| | (1) | Prior periods have been revised to conform to current period presentation |
ROYALTIES
| | | three months ended September 30, | | | nine months ended September 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
Crown Royalties (3) | | $ | 2,597 | | | $ | 4,861 | | | $ | 12,808 | | | $ | 19,046 | |
| Freehold royalties | | | 1,825 | | | | 1,884 | | | | 5,675 | | | | 6,705 | |
| Royalties included in revenue | | | 4,422 | | | | 6,745 | | | | 18,483 | | | | 25,751 | |
| | | | | | | | | | | | | | | | | |
Overriding Royalty (2) | | | 1,947 | | | | 1,957 | | | | 5,728 | | | | 7,445 | |
| Other royalties | | | 508 | | | | 790 | | | | 1,517 | | | | 2,833 | |
| Freehold mineral taxes | | | (110 | ) | | | 2 | | | | 1,604 | | | | 2,321 | |
| Other royalty obligations expense | | | 2,345 | | | | 2,749 | | | | 8,849 | | | | 12,599 | |
| | | | | | | | | | | | | | | | | |
| Total royalties | | $ | 6,767 | | | $ | 9,494 | | | $ | 27,332 | | | $ | 38,350 | |
| | | | | | | | | | | | | | | | | |
| Percentage of sales revenue | | | 15.6 | % | | | 21.8 | % | | | 21.4 | % | | | 22.2 | % |
| | (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 |
| | (3) | September 30, 2011 includes $1.9 million for a one-time adjustment of deep gas royalty credits relating to prior periods |
Total royalties decreased by 29% for the third quarter of 2011 compared to 2010, largely due to deep gas royalty credit received during the third quarter of 2011, and the reduction in produced volumes. The decrease was offset by a higher proportion of fixed rate freehold royalties, resulting in a 6.2% net decrease 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, deep gas royalty credit received during the third quarter of 2011 and the reduction in produced volumes, offset by a higher proportion of fixed rate freehold royalties resulted in a 0.8% net decrease in royalties as a percentage of sales revenue during the first three quarters of 2011.
Management’s Discussion and Analysis Compton Petroleum – Q3 2011 | Page 9 |
OPERATING EXPENSES
| | | three months ended September 30, | | | nine months ended September 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Operating expenses | | $ | 12,213 | | | $ | 12,173 | | | $ | 36,103 | | | $ | 42,707 | |
| Operating expenses ($/boe) | | $ | 9.89 | | | $ | 8.31 | | | $ | 9.75 | | | $ | 8.57 | |
There was no significant change in operating expense in the third quarter of 2011, while per boe costs increased by 19% from 2010. On a year-to-date basis, operating expense decreased by 15% while per boe costs increased by 14%. The decrease on a total dollar basis was a result of continued cost control initiatives identified and implemented by the Corporation, partially offset by rising electricity and power costs. The increase in per boe costs reflects the higher percentage of fixed cost component of certain operating costs, spread over reduced production levels quarter-over-quarter.
TRANSPORTATION
| | | three months ended September 30, | | | nine months ended September 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Transportation costs | | $ | 1,650 | | | $ | 2,424 | | | $ | 4,477 | | | $ | 5,816 | |
| Transportation costs ($/boe) | | $ | 1.34 | | | $ | 1.65 | | | $ | 1.21 | | | $ | 1.17 | |
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 32% and per boe amounts decreased by 19% in the third quarter of 2011. On a year-to-date basis, transportation expenses decreased by 23% while per boe amounts increased by 3%. 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 and higher tariffs.
ADMINISTRATIVE EXPENSES
| | | three months ended September 30, | | | nine months ended September 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Gross administrative expenses | | $ | 3,350 | | | $ | 7,142 | | | $ | 15,099 | | | $ | 23,025 | |
| Capitalized administrative expenses | | | (295 | ) | | | (741 | ) | | | (1,403 | ) | | | (3,304 | ) |
| Operator recoveries | | | (876 | ) | | | (1,010 | ) | | | (2,614 | ) | | | (3,091 | ) |
| Administrative expenses | | $ | 2,179 | | | $ | 5,391 | | | $ | 11,082 | | | $ | 16,630 | |
| Administrative expenses ($/boe) | | $ | 1.76 | | | $ | 3.68 | | | $ | 2.99 | | | $ | 3.34 | |
Administrative expenses per boe decreased 52% in the third quarter of 2011 compared to 2010 due to total administrative cost reductions of 53% on gross expenditures as well as a reduction in capitalized costs and operator recoveries. On a year-to-date basis, administrative expenses per boe decreased 10% in 2011 compared to 2010 due to total administrative cost reduction of 34% on gross expenditures as well as reductions in capitalized costs and operator recoveries. The decreases were a result of continued cost control initiatives as well as reduced staff levels following the 2010 restructuring.
Management’s Discussion and Analysis Compton Petroleum – Q3 2011 | Page 10 |
SHARE BASED COMPENSATION
| | | three months ended September 30, | | | nine months ended September 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Stock option plan | | $ | (22 | ) | | $ | 753 | | | $ | (1,443 | ) | | $ | 2,266 | |
| Employee long term incentive | | | 66 | | | | - | | | | 397 | | | | - | |
| Deferred share unit plan | | | - | | | | - | | | | 215 | | | | - | |
| Retention share plan | | | 59 | | | | - | | | | 325 | | | | - | |
| Share purchase plan | | | 128 | | | | 222 | | | | 546 | | | | 773 | |
| | | | | | | | | | | | | | | | | |
| Share based compensation | | $ | 231 | | | $ | 975 | | | $ | 40 | | | $ | 3,039 | |
At June 30, 2011, substantially all of the outstanding stock options were voluntarily forfeited by employees leading to the significant recovery of the expense for the three and nine month periods in 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. Management and the Board of Directors are currently reviewing the share based compensation plans following the Recapitalization.
IMPAIRMENTS
Management has assessed both internal and external economic factors to determine if any indicators of asset impairment exist at the quarter end. When indictors 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.
As part of the Recapitalization, the Corporation elected to have the fair value of the underlying transactions become the deemed costs of its assets and liabilities. The optional IFRS 1 election, made effective September 30, 2011, is only available in the year of transition to IFRS and with the presence of a market event, such as the Recapitalization, that gives rise to an externally derived fair value.
Under the election, the Corporation recognized a write-down of $107.1 million to development and production assets, and $4.0 million of exploration and evaluation assets. Following the revaluation, the deemed cost of development and production assets totalled $590.6 million, and exploration and evaluation assets totalled $41.7 million. This election has established the cost basis of assets and eliminated any potential reversal of impairments previously recognized under IFRS since transition on January 1, 2010.
Excluding the IFRS 1 election described above, there were no impairments of the Corporation’s assets based on Management assessment of economic and internal indicators for the first three quarters of 2011. In 2010, following the sale of a significant portion of Niton and Gilby properties, an impairment of $117.7 million was recognized on development and production assets.
EXPLORATION AND EVALUATION
| | | three months ended September 30, | | | nine months ended September 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Exploration and evaluation | | $ | 11,358 | | | $ | 525 | | | $ | 20,975 | | | $ | 651 | |
| Total costs ($/boe) | | $ | 9.20 | | | $ | 0.36 | | | $ | 5.67 | | | $ | 0.13 | |
Exploration and evaluation expense relate to uneconomic exploratory wells and the expiry of mineral land rights, prospecting costs and geophysical work prior to the acquisition of mineral land rights. During the quarter, based on current price forecasts for natural gas and the Corporation’s development strategy, it was determined that the value of certain natural gas exploratory drilling costs and mineral land leases would not be recovered in the near term and were written off.
Management’s Discussion and Analysis Compton Petroleum – Q3 2011 | Page 11 |
INTEREST AND FINANCE CHARGES
| | | three months ended September 30, | | | nine months ended September 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Interest on Senior Term Notes | | $ | 3,397 | | | $ | 9,379 | | | $ | 14,910 | | | $ | 28,023 | |
| Interest on credit facility | | | 2,202 | | | | 14 | | | | 6,413 | | | | 2,692 | |
| Interest on finance leases | | | 23 | | | | 39 | | | | 70 | | | | 1,187 | |
| Interest expense | | $ | 5,622 | | | $ | 9,432 | | | $ | 21,393 | | | $ | 31,902 | |
| Finance Charges and amortization of transaction costs | | | 1,207 | | | | 2,004 | | | | 4,302 | | | | 7,659 | |
| Total Interest and finance charges | | $ | 6,829 | | | $ | 11,436 | | | $ | 25,695 | | | $ | 39,561 | |
| Total interest and finance charges ($/boe) | | $ | 5.53 | | | $ | 7.80 | | | $ | 6.94 | | | $ | 7.94 | |
Interest expense decreased by 40% for the third quarter of 2011 and 35% 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 and August 2011 restructuring and the related 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 obligation recognized.
Finance charges and amortization of transaction costs for the third quarter of 2011 decreased by $0.8 million or 40% 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 $3.4 million or 44% compared to the same period in 2010 for the same reason.
Interest and finance charges decreased on a per boe basis due to lower overall borrowing costs, despite reduced production volumes.
The Corporation’s 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 September 30, | | | nine months ended September 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Credit facility | | $ | 133,717 | | | $ | 1,717 | | | $ | 138,468 | | | $ | 66,018 | |
| Effective interest rate | | | 6.59 | % | | | 6.81 | % | | | 6.17 | % | | | 5.44 | % |
| | | | | | | | | | | | | | | | | |
| 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$) | | $ | 26,413 | | | $ | - | | | $ | 38,736 | | | $ | - | |
| Coupon Rate (US$) | | | 10.00 | % | | | - | | | | 10.00 | % | | | - | |
| Effective interest rate (Cdn$) | | | 9.71 | % | | | - | | | | 9.68 | % | | | - | |
| 2017 Senior Term Notes (US$) | | $ | 113,576 | | | $ | - | | | $ | 166,566 | | | $ | - | |
| Coupon Rate (US$) | | | 10.00 | % | | | - | | | | 10.00 | % | | | - | |
| Effective interest rate (Cdn$) | | | 9.71 | % | | | - | | | | 9.68 | % | | | - | |
Management’s Discussion and Analysis Compton Petroleum – Q3 2011 | Page 12 |
RISK MANAGEMENT
| | | three months ended September 30, | | | nine months ended September 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Commodity contracts | | | | | | | | | | | | |
| Realized (gain) loss | | $ | (3,154 | ) | | $ | (3,652 | ) | | $ | (10,248 | ) | | $ | (7,872 | ) |
| Unrealized (gain) loss | | | (2,985 | ) | | | (4,322 | ) | | | 2,996 | | | | (14,047 | ) |
| Foreign currency contracts | | | | | | | | | | | | | | | | |
| Unrealized (gain) loss | | | (359 | ) | | | (1,272 | ) | | | (53 | ) | | | (1,272 | ) |
| Total risk management (gain) loss | | $ | (6,498 | ) | | $ | (9,246 | ) | | $ | (7,305 | ) | | $ | (23,191 | ) |
| | | | | | | | | | | | | | | | | |
| Realized (gain) loss | | $ | (3,154 | ) | | $ | (3,652 | ) | | $ | (10,248 | ) | | $ | (7,872 | ) |
| Unrealized (gain) loss | | | (3,344 | ) | | | (5,594 | ) | | | 2,943 | | | | (15,319 | ) |
| Total risk management (gain) loss | | $ | (6,498 | ) | | $ | (9,246 | ) | | $ | (7,305 | ) | | $ | (23,191 | ) |
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 in megawatt hours (“MWH”) to stabilize fluctuations in commodity pricing. Compton’s outstanding hedging instruments at September 30, 2011, are as follows, expressed in Canadian dollars unless otherwise noted:
| Commodity | Term | Volume | Average Price | Index |
| Natural Gas | | | | |
| Collars | July 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 | Jul 2011 - Dec 2011 | 1,000 Bbl/d | $101.60/Bbl | WTI |
| Electricity | | | | |
| Swap | Jan 2010 - Dec 2011 | 84 MWh/d | $50.74/MWh | AESO |
Management’s Discussion and Analysis Compton Petroleum – Q3 2011 | Page 13 |
DEPLETION AND DEPRECIATION
| | | three months ended September 30, | | | nine months ended September 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Total depletion and depreciation | | $ | 15,284 | | | $ | 18,028 | | | $ | 44,330 | | | $ | 63,373 | |
| Depletion and depreciation (S/boe) | | $ | 12.38 | | | $ | 12.30 | | | $ | 11.98 | | | $ | 12.71 | |
Total depletion and depreciation expense decreased 15% during the third quarter and 30% on a year-to-date basis 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 third quarter of 2011 increased by 1% and decreased by 6% on a year-to-date basis over the same period in 2010.
FOREIGN EXCHANGE AND OTHER (GAINS) AND LOSSES
| | | three months ended September 30, | | | nine months ended September 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Foreign exchange on translation of US$ debt | | $ | 5,841 | | | $ | (13,860 | ) | | $ | (1,528 | ) | | $ | (7,560 | ) |
| Gain on extinguishment, USD Notes | | | (55,962 | ) | | | - | | | | (55,962 | ) | | | - | |
| (Gain)/loss on disposition of assets | | | (83 | ) | | | 3,148 | | | | (15,117 | ) | | | 5,688 | |
| Other | | | 21 | | | | (116 | ) | | | 177 | | | | (2,039 | ) |
| | | | | | | | | | | | | | | | | |
| Foreign exchange and other (gains) losses | | $ | (50,183 | ) | | $ | (10,828 | ) | | $ | (72,430 | ) | | $ | (3,911 | ) |
Foreign exchange and other gains and losses recognized year to date relate primarily to the Recapitalization including the conversion of the senior term notes to equity. Previously recognized valuation allowances were reversed and a $56.0 million gain on extinguishment was realized. Comparative periods were most significantly impacted by translation gains recognized on the US denominated senior term notes and losses recorded in association with property dispositions.
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 expense of $14.3 million was recognized in the third quarter of 2011 as compared to a recovery of $9.9 million for the comparable period in 2010. On a year-to-date basis, income tax expense of $10.1 million was recognized in 2011 as compared to a recovery of $34.3 million for the same period in 2010.
At September 30, 2011, the Corporation had available future income tax assets of $10.7 million that were not recorded in the financial statements due to the uncertainties associated with historical earnings performance, and its ability to utilize these balances in the future. The benefit of these balances does not deteriorate over time and will be available to the Corporation in the future with the improvement of natural gas prices and the generation of taxable income.
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 September 30, 2011.
Management’s Discussion and Analysis Compton Petroleum – Q3 2011 | Page 14 |
| IV. | LIQUIDITY AND CAPITAL RESOURCES |
CAPITAL STRUCTURE
The Corporation’s capital structure is comprised of bank debt, working capital, MPP term financing and shareholders’ equity. Compton’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 its 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. Compton targets at total net debt to Capitalization ratio of between 40% and 50%.
| | | as at September 30, 2011 | | | as at December 31, 2010 | |
| | | | | | | |
Working capital deficit(1) | | $ | 8,676 | | | $ | 23,428 | |
Credit facility (2) | | | 103,130 | | | | 145,584 | |
MPP term financing (3) | | | 32,985 | | | | 45,620 | |
| Senior Term Notes | | | - | | | | 237,212 | |
| Total net debt | | | 144,791 | | | | 451,844 | |
| Shareholders’ equity | | | 331,882 | | | | 187,198 | |
| Total capitalization | | $ | 476,673 | | | $ | 639,042 | |
Total net debt to adjusted EBITDA (4) | | | 1.7 | x | | | 4.1 | x |
| Total net debt to total capitalization | | | 30.4 | % | | | 70.7 | % |
| | (1) | Adjusted working capital excludes risk management, current MPP term financing and facility |
| | (2) | Includes unamortized transaction costs of $870 (December 31, 2010 - $1,692) |
| | (3) | Includes unamortized financing fees of $400 (December 31, 2010 - $520) |
| | (4) | Based on trailing 12 month adjusted EBITDA |
Following the Recapitalization, the Corporation met the targeted net debt to capitalization ratio, as well as the net debt to adjusted EBITDA target at September 30, 2011. Previously, both metrics fell outside of Management’s target ranges.
In the first quarter of 2011, property sales for gross proceeds of $26.2 million were used to repay a portion of the facility with the balance applied to working capital. In the third quarter of 2011, the extinguishment of the Senior Term Notes, and gross share issuance proceeds of $50.0 million significantly reduced total net debt.
Shareholder equity was reduced as part of the transition to IFRS and the resulting adjustments recorded during 2010 negatively impacted net loss and deficit. These adjustments are disclosed in more detail in Note 20 - “Transition to IFRS”.
Management’s Discussion and Analysis Compton Petroleum – Q3 2011 | Page 15 |
WORKING CAPITAL
Compton had a working capital deficiency of $8.7 million at September 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 September 30, 2011 was $103.1 million.
Effective September 27, 2011, Compton reached an agreement with a new syndicate of lenders for a credit facility of $160.0 million, including a working capital facility of $15.0 million and a syndicated facility of $145.0 million. The facility term ends September 26, 2012, with a maturity one year thereafter unless renewed. The facility is subject to re-determination of the borrowing base semi-annually at September 30 and May 31. The borrowing base 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 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 Adjusted EBITDA ratio. The Credit facility is secured by a fixed and floating charge debenture on the assets of the Corporation.
As a result of the improvement in the Corporation’s capital structure and under the terms of the new credit facility, margins have been reduced by 50 bps across all ranges.
SENIOR TERM NOTES
The USD $238.5 million senior term notes were fully extinguished on August 23, 2011 as part of the approved Recapitalization plan. The notes were converted entirely to equity with the issuance of common shares, cashless warrants, and share purchase rights. The recognition of key transactional items, in chronological order, is itemized as follows:
| | • | August 10, 2011 - Common shares are consolidated on a 200:1 basis (see Note 10 - “Share Capital” and Note 11 - “Per Share Amounts”); |
| | • | August 23, 2011 - Senior term notes are extinguished for common shares, rights, and cashless warrants. These instruments were valued based on individually available market prices. A net gain of $56.0 million was recognized in current period earnings on extinguishment (see Note 14 - “Foreign Exchange and Other (Gains) Losses”. Of the $56.0 million gain on debt extinguishment, $56.6 million was considered non-cash and has been excluded from operating cash flow; |
| | • | September 27, 2011 - The $37.0 million (gross proceed of $50.0 million, net of issuance costs of $13.0 million) rights offering closes, completing the Recapitalization plan (see Note 10(b) - “Share Capital”); |
| | • | September 27, 2011 - The Corporation elected, under IFRS transitional provisions, to take an optional, event driven, revaluation of the book value of its assets and liabilities based on the negotiated value underlying the transactions, as provided in the approved Management proxy circular dated July 24, 2011. This resulted in a combined $111.1 million ($94.1 million, net of tax) write-down of its development and production, and exploration and evaluation assets. The adjustment was charged directly to retained earnings having no impact on current period earnings or cash flows. See Note 3 - “Development and Production” and Note 4 - “Exploration and Evaluation”; and |
| | • | September 30, 2011 - Further to the shareholder resolution approved July 25, 2011, the Corporation reduced its stated capital by eliminating the balances in other reserves, and deficit. The total stated capital reduction was $330.8 million, and did not affect current period earnings (see Note 10(b) - “Share Capital”). |
Management’s Discussion and Analysis Compton Petroleum – Q3 2011 | Page 16 |
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 $33.0 million was 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 11.68% 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 repayment 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 September 30, 2011, the threshold throughput volume was reduced to 55.2 mmcf/d. The cumulative prepayments of the purchase option are $10.1 million (2011 - $8.9 million, 2010 - $1.2 million, 2009 - $nil), reducing the amount of the MPP term financing liability. Subsequent to quarter end, an additional minimum payment of $0.3 million was made.
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 September 30, 2011.
| | | 2011 | | | 2012 | | | 2013 | | | 2014 | | | 2015 | | | Thereafter | |
| Credit facility | | $ | - | | | $ | - | | | $ | 104,000 | | | $ | - | | | $ | - | | | $ | - | |
MPP term financing (1) | | | 2,702 | | | | 9,592 | | | | 9,592 | | | | 20,594 | | | | - | | | | - | |
| Accounts payable | | | 37,114 | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Finance leases | | | 90 | | | | 1,030 | | | | 224 | | | | 224 | | | | - | | | | - | |
| Office facilities | | | 473 | | | | 1,938 | | | | 2,001 | | | | 2,001 | | | | 2,046 | | | | 5,449 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | $ | 40,379 | | | $ | 12,560 | | | $ | 115,817 | | | $ | 22,819 | | | $ | 2,046 | | | $ | 5,449 | |
| | (1) | Represents monthly fixed base fee payments. The 2011 amount includes purchase option repayments of $0.3 million |
Management’s Discussion and Analysis Compton Petroleum – Q3 2011 | Page 17 |
The current outlook for natural gas in North America remains weak throughout the remainder of 2011 and into 2012. As a result, Management’s strategy is focused on developing its high-return, liquids-rich natural gas area at Niton and emerging crude oil opportunities to offset continued low natural gas prices. Compton’s assets provide significant upside potential through their multiple zone development opportunities, contiguous land blocks and impact of horizontal multi-stage fracture technology.
Compton is on track to meet or exceed its 2011 guidance targets, including the lower end of its production range despite lower than anticipated capital expenditures to date. As a result of the Corporation’s focus on improving capital efficiencies and reducing costs, Management is revising its 2011 cash flow guidance upwards to between $35.0 and $40.0 million on a calendar year basis. Compton is in the process of finalizing its future development plan and 2012 budget, which is expected to be released prior to year-end. With a revised capital structure, Compton is focused on the development of its asset base and new opportunities for future growth.
| VI. | INTERNAL CONTROL OVER FINANCIAL REPORTING |
The adoption of IFRS effected Compton’s presentation of financial results and the accompanying disclosure. The impact on processes, controls and financial reporting systems have 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 January 1, 2011 and ending on September 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.
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 small 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.
Management’s Discussion and Analysis Compton Petroleum – Q3 2011 | Page 18 |
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.
| VIII. | FORTHCOMING AND NEWLY ADOPTED ACCOUNTING POLICIES |
INTERANTIONAL FINANCIAL REPORTING STANDARDS
The Corporation’s consolidated interim financial statements for the nine months ended September 30, 2011 are the third consolidated interim financial statements under IFRS and prepared in accordance with IAS 34 and IFRS 1 and as such include the application of IFRS 1 “First -Time Adoption of International Financial Reporting Standards”.
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.
Management’s Discussion and Analysis Compton Petroleum – Q3 2011 | Page 19 |
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.
Under Previous GAAP, the Corporation had 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%. For the nine months ended September 30, 2010, the cumulative impact on the deferred tax liability was a decrease of $110.7 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 perform 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.
For the three months ended September 30, 2010, an impairment write-down of $44.9 million was recognized across certain CGUs. An impairment write-down of $117.7 million was recognized for the nine months ended September 30, 2010. 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 $5.7 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 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 September 30, 2010, the expiry of undeveloped mineral rights resulted in the derecognition of $0.5 million of exploration and evaluation assets, and have been presented as exploration expense in net loss.
For the nine months ended September 30, 2010 land expiries charged to exploration and evaluation expense totalled $0.7 million.
Management’s Discussion and Analysis Compton Petroleum – Q3 2011 | Page 20 |
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 pension plan totalling $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 September 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.
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 September 30, 2010 was $97.4 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.
| | (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 asset, pension and decommissioning liabilities were also made.
For the nine months ended September 30, 2010, the impact of transitional IFRS adjustments was $0.3 million. No significant impact for the three months ended September 30, 2010.
The presentation of royalties under IFRS has changed from previous disclosures under Pervious 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.
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 September 30, 2010, development and production was increased by $7.6 million (net), capital lease obligations increased $4.3 million, and the impact of interest and depreciation expense of $1.2 million and $0.5 million respectively, was recorded through net loss.
Management’s Discussion and Analysis Compton Petroleum – Q3 2011 | Page 21 |
Under Pervious GAAP, share based payments were recognized as an expense on 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 September 30, 2010, there was no significant increase in share based compensation expense from the revised valuation methodology. For the nine months ended September 30, 2010, the increase was $0.3 million.
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 September 30, 2010, a decrease in depletion of $10.5 million resulted from the reduction of the Corporation’s petroleum and natural gas asset base and the revised depletion methodology. For the nine months ended September 30, 2010, depletion expense was reduced by $33.5 million.
CHANGES IN ACCOUNTING POLICY
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 or are outstanding in the third quarter, are effective on January 1, 2013, and may have an impact on the Corporation’s financial statements in the future.
| | • | IFRS 9, "Financial Instruments", which is the result of the first phase of the IASB’s project to replace IAS 39, "Financial Instruments: Recognition and Measurement". The new standard replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value. |
IFRS 10, "Consolidated Financial Statements", which is the result of the IASB’s project to replace Standing Interpretations Committee 12, "Consolidation - Special Purpose Entities" and the consolidation requirements of IAS 27, "Consolidated and Separate Financial Statements". The new standard eliminates the current risk and rewards approach and establishes control as the single basis for determining the consolidation of an entity.
| | • | IFRS 11, "Joint Arrangements", which is the result of the IASB’s project to replace IAS 31, “Interests in Joint Ventures”. The new standard redefines joint operations and joint ventures and requires joint operations to be proportionately consolidated and joint ventures to be equity accounted. Under IAS 31, joint ventures could be proportionately consolidated. |
| | • | IFRS 12, "Disclosure of Interests in Other Entities", which outlines the required disclosures for interests in subsidiaries and joint arrangements. The new disclosures require information that will assist financial statement users to evaluate the nature, risks and financial effects associated with an entity’s interests in subsidiaries and joint arrangements. |
| | • | IFRS 13, "Fair Value Measurement", which provides a common definition of fair value, establishes a framework for measuring fair value under IFRS and enhances the disclosures required for fair value measurements. The standard applies where fair value measurements are required and does not require new fair value measurements. |
| | • | IAS 19, "Post Employment Benefits", which amends the recognition and measurement of defined benefit pension expense and expands disclosures for all employee benefit plans. |
The Corporation is currently assessing the impact of the new standards, but does not anticipate that the adoption of the standards will have a significant impact on the Corporation’s consolidated financial statements.
Management’s Discussion and Analysis Compton Petroleum – Q3 2011 | Page 22 |
The following table sets forth certain quarterly financial information of the Corporation for the first seven most recent quarters.
| | | 2011 | | | 2010 | |
| ($millions, except where noted) | | | Q3 | | | | Q2 | | | | Q1 | | | | Q4 | | | | Q3 | | | | Q2 | | | | Q1 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Revenue | | $ | 39 | | | $ | 34 | | | $ | 36 | | | $ | 39 | | | $ | 37 | | | $ | 49 | | | $ | 61 | |
| Cash Flow | | $ | 15 | | | $ | 7 | | | $ | 8 | | | $ | 10 | | | $ | 1 | | | $ | 10 | | | $ | 21 | |
| Per share - basic | | $ | 1.76 | | | $ | 5.42 | | | $ | 5.79 | | | $ | 7.59 | | | $ | 0.64 | | | $ | 7.64 | | | $ | 15.85 | |
| - diluted | | $ | 1.28 | | | $ | 2.24 | | | $ | 3.85 | | | $ | 5.47 | | | $ | 0.64 | | | $ | 7.64 | | | $ | 15.85 | |
| Net earnings (loss) | | $ | 28 | | | $ | (8 | ) | | $ | 4 | | | $ | (440 | ) | | $ | (33 | ) | | $ | (90 | ) | | $ | 25 | |
| Per share - basic | | $ | 3.26 | | | $ | (5.82 | ) | | $ | 2.63 | | | $ | (333.84 | ) | | $ | (25.08 | ) | | $ | (68.29 | ) | | $ | 19.31 | |
| - diluted | | $ | 2.43 | | | $ | (5.82 | ) | | $ | 1.75 | | | $ | (333.84 | ) | | $ | (25.08 | ) | | $ | (68.29 | ) | | $ | 19.31 | |
| Operating earnings (loss) | | $ | (2 | ) | | $ | (6 | ) | | $ | 7 | | | $ | (28 | ) | | $ | (16 | ) | | $ | (16 | ) | | $ | 3 | |
| Production | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural gas (mmcf/d) | | | 67 | | | | 65 | | | | 72 | | | | 75 | | | | 81 | | | | 98 | | | | 97 | |
| Liquids (bbls/d) | | | 2,240 | | | | 1,947 | | | | 2,455 | | | | 2,411 | | | | 2,452 | | | | 3,076 | | | | 3,237 | |
| Total (boe/d) | | | 13,429 | | | | 12,748 | | | | 14,507 | | | | 14,852 | | | | 15,931 | | | | 19,481 | | | | 19,411 | |
| Average price | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural gas ($/mcf) | | $ | 4.01 | | | $ | 4.10 | | | $ | 4.01 | | | $ | 3.87 | | | $ | 3.84 | | | $ | 4.15 | | | $ | 5.67 | |
| Liquids ($/bbl) | | $ | 78.10 | | | $ | 88.39 | | | $ | 69.11 | | | $ | 69.30 | | | $ | 59.39 | | | $ | 66.00 | | | $ | 67.59 | |
| Total ($/boe) | | $ | 33.06 | | | $ | 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, 2011. |
| | (2) | Total shares outstanding changed from 263.6 million to 26.4 million on August 10, 2011 in accordance with the Recapitalization. |
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. Despite this, cash flow has increased due to Management’s focus on continued cost reductions and improvement to capital efficiencies. 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 the 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.
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 Compton Petroleum – Q3 2011 | Page 23 |
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 State 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 be 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 its 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 Compton Petroleum – Q3 2011 | Page 24 |
