Management’s Discussion & Analysis
This Management’s Discussion and Analysis (“MD&A”) for Compton Petroleum Corporation (“Compton” or the “Corporation”) should be read with the unaudited interim consolidated financial statements and related notes for the three and six months ended June 30, 2012 and March 31, 2012, as well as the audited consolidated financial statements and MD&A for the year ended December 31, 2011. 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 unaudited interim consolidated financial statements and comparative information has been prepared in accordance with International Financial Reporting Standards.
Further information regarding Compton, including the Annual Information Form for the year ended December 31, 2011 can be accessed under the Corporation’s public filings found on SEDAR atwww.sedar.com, EDGAR at www.sec.gov, and on the Corporation’s website at www.comptonpetroleum.com.
Amounts presented in this MD&A are stated in thousands (000’s) of dollars except per share and boe amounts, unless otherwise stated. This document is dated as at August 9, 2012.
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 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 opportunities.
Compton’s production focus has been on developing its high-return, liquids-rich natural gas areas of the Rock Creek Formation at its Niton property and exploring the crude oil potential of the property’s Wilrich and Notikewin Formations. 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 prices recover.
Compton will create value by providing appropriate investment returns for shareholders through further improving operating efficiencies, maximizing returns on capital invested and focusing on higher return assets.
COMPTON PETROLEUM CORPORATION |
Management’s Discussion & Analysis |
II. | Quarterly Highlights |
Management’s strategy throughout the first half of the year was to strengthen its capital structure and improve operating efficiencies to better position the Corporation within a historically low natural gas price environment.
Results for second quarter of 2012 include:
· | Average daily production of 12,678 boe/d; |
· | Completed maintenance turnarounds at the MPP sweet plant and McLeod River facilities ahead of schedule; |
· | Negotiated the sale of non-core assets for gross proceeds of $17.0 million for use in credit facility repayment. The transaction closed subsequent to the quarter; |
· | Subsequent to the quarter, announced the take-over bid offer by MFC Industrial Ltd. (“MFC”), as described in the ‘Take-Over Bid’ section; and |
· | Negotiated an extension to the cure period for the credit facility shortfall through to the anticipated closing of the MFC take-over bid offer. |
III. | Results of Operations |
three months ended June 30, | six months ended June 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
($000’s, except per share amounts) | ||||||||||||||||
Average production (boe/d) | 12,678 | 12,748 | 12,623 | 13,622 | ||||||||||||
Capital expenditures(2) | $ | 3,773 | $ | 8,494 | $ | 11,278 | $ | 15,368 | ||||||||
Cash flow(1) | $ | 5,409 | $ | 7,144 | $ | 9,163 | $ | 14,770 | ||||||||
Per share: basic | $ | 0.20 | $ | 5.42 | $ | 0.35 | $ | 11.21 | ||||||||
diluted | $ | 0.20 | $ | 2.24 | $ | 0.35 | $ | 4.63 | ||||||||
Operating loss(1) | $ | (17,710 | ) | $ | (5,650 | ) | $ | (36,454 | ) | $ | 1,082 | |||||
Net loss | $ | (47,021 | ) | $ | (7,677 | ) | $ | (91,285 | ) | $ | (4,217 | ) | ||||
Per share: basic | $ | (1.78 | ) | $ | (5.82 | ) | $ | (3.46 | ) | $ | (3.20 | ) | ||||
diluted | $ | (1.78 | ) | $ | (5.82 | ) | $ | (3.46 | ) | $ | (3.20 | ) | ||||
Revenue | $ | 25,289 | $ | 34,684 | $ | 50,262 | $ | 70,333 | ||||||||
Field netback (per boe)(1) | $ | 7.82 | $ | 18.94 | $ | 8.75 | $ | 17.93 |
(1) | Cash flow, operating loss and field netback are non-GAAP measures that are defined in this document |
(2) | Capital investment is before asset acquisitions and divestitures |
Cash flow
Cash flow is considered a non-GAAP measure; it is commonly used in the oil and gas industry and is used 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, nor more meaningful than, cash provided by operating, investing and financing activities or net earnings (loss) as determined in accordance with GAAP, in assessing the Corporation’s performance or liquidity.
COMPTON PETROLEUM CORPORATION | 2 |
Management’s Discussion & Analysis |
three months ended June 30, | six months ended June 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
Cash flow from operating activities | $ | 3,895 | $ | 18,457 | $ | 1,210 | $ | 10,356 | ||||||||
Add: Other expenses | 425 | - | 850 | - | ||||||||||||
Less: change in non-cash working capital | (1,089 | ) | $ | 11,313 | $ | (7,103 | ) | $ | (4,414 | ) | ||||||
Cash flow(1) | $ | 5,409 | $ | 7,144 | $ | 9,163 | $ | 14,770 |
(1) | Cash flow is a non-GAAP measure that is defined in this document |
Cash flow for the second quarter of 2012 decreased by approximately $1.7 million or 24% compared to 2011 as a result of:
· | a 4% decline in natural gas production volumes to 62.4 mmcf/d from 64.7 mmcf/d in 2011, resulting from a reduced level of capital expenditures and normal production declines; |
· | lower average realized natural gas prices, excluding financial hedges, which decreased 51% to $2.03 per mcf compared to $4.11 per mcf in 2011; |
· | lower average realized liquids prices, which decreased 5% to $78.85 per bbl compared to $82.66 per bbl in 2011; |
· | an increase in operating costs of $3.0 million relating to adjustments for pension contributions and gas cost allowance; |
· | realized risk management gains of $1.8 million compared to $3.7 million in 2011; and |
· | other expense of $0.4 million in 2012. |
These factors were partially offset by:
· | a 10% increase in liquids production volumes to 2,285 bbls/d from 2,082 bbls/d in 2011, resulting from capital expenditures focused on liquids rich areas; |
· | a $6.2 million decrease in finance costs resulting from reduced debt levels in 2012 compared to 2011; and |
· | a decline in administrative costs of $0.5 million resulting from staff reductions. |
On a year-to-date basis, cash flow decreased by approximately $5.6 million or 38% as a result of:
· | a 9% decline in natural gas production volumes to 62.4 mmcf/d from 68.5 mmcf/d in 2011, resulting from a reduced level of capital expenditures and normal production declines; |
· | lower average realized natural gas prices, excluding financial hedges, which decreased 45% to $2.23 per mcf compared to $4.05 per mcf in 2011; |
· | an increase in operating costs of $2.3 million relating to adjustments for pension contributions and gas cost allowance; |
· | realized risk management gains of $3.5 million, including the monetization of all natural gas and oil hedges, as compared to $7.1 million in 2011; and |
· | other expense of $0.9 million in 2012. |
COMPTON PETROLEUM CORPORATION | 3 |
Management’s Discussion & Analysis |
These factors were partially offset by:
· | a 2% increase in liquids production volumes to 2,234 bbls/d from 2,199 bbls/d in 2011, resulting from capital expenditures focused on liquids rich areas |
· | higher average realized liquids prices, which increased 3% to $80.31 per bbl compared to $77.69 per bbl in 2011; |
· | a $13.5 million decrease in interest and finance charges resulting from reduced debt levels in 2012 compared to 2011; and |
· | a decline in administrative costs of $1.4 million resulting from staff reductions. |
Net Loss
Net loss for the second quarter of 2012 was $47.0 million, a decline of $39.3 million when compared to the $7.7 million net loss in the same period for 2011. In addition to the factors that impacted cash flow, second quarter 2012 net loss was affected by:
· | an impairment expense of $32.1 million in 2012, related to the value of development and production assets; |
· | deferred tax recovery of $3.2 million in 2011; |
· | unrealized risk management losses of $4.2 million compared to a gain of $0.1 million in 2011; |
· | unrealized foreign exchange and other gains of $nil compared to a gain of $2.0 million in 2011; and |
· | a $0.3 million increase in share based payment expense in 2012 following the restructuring of staff and approval of revised compensation plans. |
These factors were partially offset by:
· | decreased exploration and evaluation costs of $2.3 million compared to $5.1 million in 2011, relating to the expiry of undeveloped land; and |
· | a decline in depletion and depreciation expense to $12.3 million from $13.9 million in 2011, following asset impairments recognized during 2011 and 2012. |
On a year-to-date basis, net loss was $91.3 million, a decline of $87.1 million when compared to the $4.2 million net loss in the same period for 2011. In addition to the factors that impacted cash flow, year-to-date net loss was affected by:
· | an impairment expense of $65.3 million in 2012, related to the value of development and production assets; |
· | deferred tax recovery of $4.2 million in 2011; |
· | unrealized foreign exchange and other gains of $nil compared to a gain of $7.4 million in 2011; and |
· | a $1.0 million increase in share based payment expense in 2012 following the restructuring of staff and approval of revised compensation plans. |
These factors were partially offset by:
· | decreased exploration and evaluation costs of $3.2 million compared to $9.6 million in 2011, relating to the expiry of undeveloped land; |
COMPTON PETROLEUM CORPORATION | 4 |
Management’s Discussion & Analysis |
· | a decline in depletion and depreciation expense to $25.4 million from $28.8 million in 2011, following asset impairments recognized during 2011 and 2012; and |
· | unrealized risk management losses of $3.7 million compared to $6.3 million in 2011. |
Operating earnings (LOSS)
Operating earnings is an after tax non-GAAP measure used by the Corporation to facilitate comparability of earnings between periods. Operating earnings is derived by adjusting net earnings for certain items that are largely non-operational in nature, or one-time non-recurring items. Operating earnings should not be considered more meaningful than or an alternative to net earnings as determined in accordance with IFRS. The following provides the calculation of operating loss for period end.
three months ended June 30, | six months ended June 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
Net loss, as reported | $ | (47,021 | ) | $ | (7,677 | ) | $ | (91,285 | ) | $ | (4,217 | ) | ||||
Non-operational items | ||||||||||||||||
Unrealized foreign exchange and other (gains) losses | (3 | ) | (1,961 | ) | 4 | (7,367 | ) | |||||||||
Unrealized mark-to-market hedging (gains) losses | 4,220 | (46 | ) | 3,730 | 6,287 | |||||||||||
Exploratory land expiries | 2,310 | 5,119 | 3,199 | 9,617 | ||||||||||||
Impairment / reversals | 32,130 | - | 65,324 | - | ||||||||||||
Other expenses | 425 | - | 850 | - | ||||||||||||
Tax effect | (9,771 | ) | (1,085 | ) | (18,276 | ) | (3,238 | ) | ||||||||
Operating loss(1) | $ | (17,710 | ) | $ | (5,650 | ) | $ | (36,454 | ) | $ | 1,082 | |||||
Per share - basic(2) | $ | (0.67 | ) | $ | (4.29 | ) | $ | (1.38 | ) | $ | 0.82 | |||||
- diluted(2) | $ | (0.67 | ) | $ | (4.29 | ) | $ | (1.38 | ) | $ | 0.34 |
(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 |
CAPITAL EXPENDITURES
three months ended June 30, | six months ended June 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
Exploration & evaluation | ||||||||||||||||
Land | $ | 63 | $ | 771 | $ | 153 | $ | 957 | ||||||||
Drilling and completions | 96 | 111 | 174 | 515 | ||||||||||||
Development & production | ||||||||||||||||
Drilling and completions | 325 | 2,993 | 6,157 | 8,026 | ||||||||||||
Production facilities and equipment | 3,089 | 4,540 | 4,536 | 5,760 | ||||||||||||
Corporate and other | 200 | 79 | 258 | 110 | ||||||||||||
Total capital investment | 3,773 | 8,494 | 11,278 | 15,368 | ||||||||||||
Divestitures | ||||||||||||||||
Property | - | - | - | (8,066 | ) | |||||||||||
Production facilities and equipment | - | - | (6 | ) | (405 | ) | ||||||||||
Land | - | (200 | ) | - | (2,126 | ) | ||||||||||
Acquisitions (divestitures), net | - | (200 | ) | (6 | ) | (10,597 | ) | |||||||||
Total capital expenditures | $ | 3,773 | $ | 8,294 | $ | 11,272 | $ | 4,771 |
COMPTON PETROLEUM CORPORATION | 5 |
Management’s Discussion & Analysis |
The current natural gas price level has limited cash flow available to invest in development activities resulting in expected production volume declines. During the second quarter, Compton successfully completed two plant maintenance turnaround operations, one for the MPP sweet plant #2 and the second at the McLeod River facility. The turnarounds were completed ahead of schedule and under budget, minimizing the downtime required for maintenance. The reduced downtime combined with initiatives focused on strengthening base volumes resulted in strong production volumes quarter over quarter.
Subsequent to the quarter, Compton closed the disposition of its non-core Bigoray assets, located near the Niton area in Central Alberta, as well as approximately 5,600 gross acres of Cardium Formation mineral rights at Niton. Gross proceeds from the transaction were $17.0 million, and represent approximately 450 boe/d of production on an average combined basis over the past three months and net proved and net proved plus probable reserves of 1.7 MMboe and 2.1 MMboe, respectively, at December 31, 2011.
During this period of low natural gas prices, Compton will manage its capital expenditure program within current cash flow in accordance with Management’s prudent financial approach. The program remains flexible should commodity price levels increase or 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 second quarter 2012 free cash flow surplus of $1.6 million is higher as compared to the second quarter of 2011 due to curtailed capital spending due to continued low natural gas commodity prices. On a year to date basis the free cash flow deficit was $1.7 million.
three months ended June 30, | six months ended June 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
Cash flow | $ | 5,409 | $ | 7,144 | $ | 9,163 | $ | 14,770 | ||||||||
Less: capital investment | (3,773 | ) | (8,494 | ) | (11,278 | ) | (15,368 | ) | ||||||||
Free cash flow | $ | 1,636 | $ | (1,350 | ) | $ | (2,115 | ) | $ | (598 | ) |
COMPTON PETROLEUM CORPORATION | 6 |
Management’s Discussion & Analysis |
PRODUCTION VOLUMES AND REVENUES
three months ended June 30, | six months ended June 30, | |||||||||||||||
Average production | ||||||||||||||||
Natural gas(mmcf/d) | 62.4 | 64.7 | 62.4 | 68.5 | ||||||||||||
Liquids(bbls/d) | 2,285 | 1,947 | 2,234 | 2,199 | ||||||||||||
Total(boe/d) | 12,678 | 12,748 | 12,623 | 13,622 | ||||||||||||
Benchmark prices | ||||||||||||||||
AECO($/GJ) | ||||||||||||||||
Monthly index | $ | 1.74 | $ | 3.54 | $ | 2.38 | $ | 3.56 | ||||||||
Daily index | $ | 1.80 | $ | 3.67 | $ | 1.92 | $ | 3.62 | ||||||||
WTI(US$/bbl) | $ | 93.49 | $ | 102.56 | $ | 98.19 | $ | 98.30 | ||||||||
Edmonton sweet light($/bbl) | $ | 87.99 | $ | 103.09 | $ | 92.35 | $ | 95.54 | ||||||||
Realized prices | ||||||||||||||||
Natural gas($/mcf) | $ | 2.03 | $ | 4.11 | $ | 2.23 | $ | 4.05 | ||||||||
Liquids($/bbl) | $ | 78.85 | $ | 82.66 | $ | 80.31 | $ | 77.69 | ||||||||
Total($/boe) | $ | 24.19 | $ | 34.05 | $ | 25.18 | $ | 32.94 | ||||||||
Sales Revenue(1)(2) | ||||||||||||||||
Natural gas | $ | 11,508 | $ | 24,188 | $ | 25,365 | $ | 50,283 | ||||||||
Liquids | 17,932 | 17,505 | 35,173 | 34,111 | ||||||||||||
Total | $ | 29,440 | $ | 41,693 | $ | 60,538 | $ | 84,394 |
(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 six months of 2012 were 7% lower than in 2011 primarily due to limited new production additions and natural declines.
Compared to the second quarter 2011, sales revenue decreased by $12.3 million as a result of lower production volumes and lower realized natural gas and liquids prices in 2012. Realized prices and revenues are before any hedging gains or losses. The impact from hedging on realized natural gas prices for the first six months of 2012 was $0.11 per mcf compared to $0.48 per mcf in 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 $/boe basis. Funds flow netback equals field netback less administrative and interest costs. Field netback and funds flow netback should not be considered more meaningful than or an alternative to net earnings as determined in accordance with IFRS. The following provides the calculation of field netback and funds flow netback.
three months ended June 30, | six months ended June 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
($/boe) | ||||||||||||||||
Realized price(1) | $ | 24.19 | $ | 34.05 | $ | 25.18 | $ | 32.94 | ||||||||
Processing revenue | 1.33 | 1.58 | 1.17 | 1.29 | ||||||||||||
Realized commodity hedge gain | 1.56 | 3.15 | 1.52 | 2.88 | ||||||||||||
Royalties | (4.88 | ) | (8.09 | ) | (6.48 | ) | (8.34 | ) | ||||||||
Operating expenses | (13.17 | ) | (10.46 | ) | (11.41 | ) | (9.69 | ) | ||||||||
Transportation | (1.21 | ) | (1.29 | ) | (1.23 | ) | (1.15 | ) | ||||||||
Field netback | $ | 7.82 | $ | 18.94 | $ | 8.75 | $ | 17.93 | ||||||||
Administrative | $ | (3.12 | ) | $ | (3.51 | ) | $ | (3.29 | ) | $ | (3.61 | ) | ||||
Interest | (2.97 | ) | (7.96 | ) | (2.76 | ) | (7.65 | ) | ||||||||
Funds flow netback | $ | 1.73 | $ | 7.47 | $ | 2.70 | $ | 6.67 |
(1) | Prior periods have been revised to conform to current period presentation |
COMPTON PETROLEUM CORPORATION | 7 |
Management’s Discussion & Analysis |
Royalties
three months ended June 30, | six months ended June 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
Crown royalties | $ | 2,976 | $ | 5,249 | $ | 7,885 | $ | 10,211 | ||||||||
Freehold royalties | 1,175 | 1,760 | 2,391 | 3,850 | ||||||||||||
Royalties included in revenue | 4,151 | 7,009 | 10,276 | 14,061 | ||||||||||||
Overriding royalty(2) | 1,174 | 1,926 | 2,861 | 3,781 | ||||||||||||
Other royalties | 301 | 497 | 658 | 1,009 | ||||||||||||
Freehold mineral taxes | - | 30 | 1,089 | 1,714 | ||||||||||||
Other royalty obligations expense | 1,475 | 2,453 | 4,608 | 6,504 | ||||||||||||
Total royalties | $ | 5,626 | $ | 9,462 | $ | 14,884 | $ | 20,565 | ||||||||
Percentage of sales revenue | 19.1 | % | 22.7 | % | 24.5 | % | 24.4 | % |
(1) | Gas cost allowance received on crown volumes are presented as a reduction of Operating Expenses. |
(2) | The overriding royalty obligation represents a 5% commitment of the Corporation’s future gross production revenue, less certain transportation costs and marketing fees, on the existing land base at September 26, 2009. |
Total royalty expense decreased by 41% for the second quarter of 2012 compared to 2011. The decline is largely due to the decrease in production volume and lower natural gas prices in 2012. Royalty rates as a percentage of sales revenue decreased by 4% during the quarter due to low commodity natural gas prices. On a year-to-date basis, total royalties decreased by 28% due to lower natural gas prices and the reduction in produced volumes. On a year to date basis, the royalties as a percentage of sales revenue remained relatively consistent, decreasing by 0.1%.
Operating Expenses
three months ended June 30, | six months ended June 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
Operating expenses($000’s) | $ | 15,195 | $ | 12,246 | $ | 26,219 | $ | 23,890 | ||||||||
Operating expenses($/boe) | $ | 13.17 | $ | 10.46 | $ | 11.41 | $ | 9.69 |
Operating expenses in the second quarter of 2012 increased by 24%, while per boe costs increased by 26% from 2011. On a year-to-date basis, operating expense increased by 10% while per boe costs increased by 18%. The increase on a total dollar basis was a result of increased pension contributions and a reduction in the gas cost allowance. The increase in per boe costs reflects the increased costs, as well as the fixed cost component of certain operating costs, spread over reduced production levels quarter-over-quarter.
TRANSPORTATION
three months ended June 30, | six months ended June 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
Transportation costs | $ | 1,397 | $ | 1,510 | $ | 2,829 | $ | 2,827 | ||||||||
Transportation costs($/boe) | $ | 1.21 | $ | 1.29 | $ | 1.23 | $ | 1.15 |
COMPTON PETROLEUM CORPORATION | 8 |
Management’s Discussion & Analysis |
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 expense in the second quarter of 2012 decreased by 7% or $0.1 million compared to 2011, while per boe costs decreased by 6% from 2011. Transportation expense for the first six months of 2012 remained consistent with that of 2011. Increased per boe costs are as a result of higher proportion of liquids production to total production volumes which incur a higher transportation cost.
Administrative Expenses
three months ended June 30, | six months ended June 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
Gross administrative expenses | $ | 5,129 | $ | 5,204 | $ | 10,615 | $ | 11,749 | ||||||||
Capitalized administrative expenses | (293 | ) | (327 | ) | (1,174 | ) | (1,108 | ) | ||||||||
Operator recoveries | (1,237 | ) | (774 | ) | (1,885 | ) | (1,738 | ) | ||||||||
Administrative expenses | $ | 3,599 | $ | 4,103 | $ | 7,556 | $ | 8,903 | ||||||||
Administrative expenses($/boe) | $ | 3.12 | $ | 3.51 | $ | 3.29 | $ | 3.61 |
During the second quarter of 2012, gross administrative expenses remained consistent with levels in 2011; however increased capitalized costs and operator recoveries reduced 2012 administrative expenses by $0.5 million or 12%. On a year-to-date basis, 2012 gross administrative expenses were reduced by 10% and 15% net of recoveries compared to 2011. The decrease in total dollars was also a result of continued cost control initiatives as well as reduced staff levels. Costs per boe were down based on cost levels, partially offset by certain fixed administrative costs and a decline in production volumes.
SHARE-Based Compensation
three months ended June 30, | six months ended June 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
Stock option plan | $ | 189 | $ | (979 | ) | $ | 357 | $ | (1,421 | ) | ||||||
Employee long term incentive | - | 331 | - | 331 | ||||||||||||
Deferred share unit plan | - | 215 | - | 215 | ||||||||||||
Restricted share unit plan | 34 | - | 154 | - | ||||||||||||
Retention share plan | - | 266 | - | 266 | ||||||||||||
Share purchase plan | 149 | 235 | 336 | 418 | ||||||||||||
Stock-based compensation | $ | 372 | $ | 68 | $ | 847 | $ | (191 | ) |
Following the recapitalization completed in 2011, an issuance of stock options and the approved restricted share unit plan for directors increased share based compensation levels in 2012. Staff reductions have reduced the employee saving plan costs quarter over quarter.
COMPTON PETROLEUM CORPORATION | 9 |
Management’s Discussion & Analysis |
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.
At June 30, 2012, an impairment write down of development and production assets of $32.1 million was recorded to their estimated recoverable amount. The recoverable amount represents the assets value in use based on projected cash flows of Proved plus Probable reserves, discounted at 10%, derived from external reserve evaluation data and current pricing levels. An impairment write down of $33.2 million was recorded during the first quarter of 2012. There were no impairments recognized in the first six months of 2011.
The impairment was largely due to economic limitations from historically low pricing levels. The natural gas price forecast of the Corporation’s independent reserve evaluators has varied as follows:
June 30, 2012 | December 31, 2011 | |||||||
2012 | $ | 2.47 | $ | 3.49 | ||||
2013 | $ | 3.44 | $ | 4.13 | ||||
2014 | $ | 3.90 | $ | 4.59 | ||||
2015 | $ | 4.36 | $ | 5.05 | ||||
2016 | $ | 4.82 | $ | 5.51 |
EXPLORATION and EVALUATION
three months ended June 30, | six months ended June 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
Exploration and evaluation | $ | 2,310 | $ | 5,119 | $ | 3,199 | $ | 9,617 | ||||||||
Total costs($/boe) | $ | 2.00 | $ | 4.41 | $ | 1.39 | $ | 3.90 |
Exploration and evaluation expense relate entirely to the expiry of mineral land rights in 2012 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 June 30, | six months ended June 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
Interest on senior notes | $ | - | $ | 5,770 | $ | - | $ | 11,513 | ||||||||
Interest on credit facility | 2,227 | 2,074 | 3,448 | 4,211 | ||||||||||||
Interest on finance leases | 12 | 20 | 25 | 47 | ||||||||||||
Interest on MPP term financing | 979 | 1,141 | 1,991 | 2,250 | ||||||||||||
Interest expense | 3,218 | 9,005 | 5,464 | 18,021 | ||||||||||||
Other interest and finance charges | 211 | 304 | 869 | 845 | ||||||||||||
Accretion of decommissioning liabilities | 812 | 1,172 | 1,656 | 2,587 | ||||||||||||
Total interest and finance charges | $ | 4,241 | $ | 10,481 | $ | 7,989 | $ | 21,453 | ||||||||
Total interest and finance charges($/boe) | $ | 3.68 | $ | 9.08 | $ | 3.48 | $ | 9.34 |
COMPTON PETROLEUM CORPORATION | 10 |
Management’s Discussion & Analysis |
Interest expense for the second quarter of 2012 decreased by 64% and 70% on a year-to-date basis compared to the same periods in 2011. Interest paid on the Senior Term Notes was eliminated following their conversion to equity in 2011, and overall reduced debt levels in 2012. Higher interest rates during the second quarter of 2012 resulted from the credit facility shortfall.
Other interest and finance charges for the second quarter of 2012 decreased by $0.1 million or 33% compared to the same period in 2011, as a result of lower fees for unutilized credit. On a year-to-date basis, other interest and finance charges have remained consistent.
Total interest and finance charges decreased on a per boe basis in the second quarter of 2012 due to lower overall borrowing costs, despite reduced production volumes.
Accretion of decommissioning liabilities decreased during the second quarter of 2012 as a result of gross abandonment and reclamation costs completed in 2011, and overall lower discount rates in 2012.
Effective interest rates on a weighted average debt basis are presented below.
three months ended June 30, | six months ended June 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
Credit Facility | $ | 143,778 | $ | 137,109 | $ | 127,704 | $ | 140,883 | ||||||||
Effective interest rate | 6.20 | % | 6.05 | % | 5.99 | % | 5.98 | % | ||||||||
2011 Mandatory convertible senior term notes (US$) | $ | - | $ | 45,000 | $ | - | $ | 45,000 | ||||||||
Coupon Rate (US$) | - | 10 | % | - | 10 | % | ||||||||||
Effective interest rate (Cdn$) | - | 9.68 | % | - | 9.77 | % | ||||||||||
2017 Senior term notes (US$) | $ | - | $ | 193,500 | $ | - | $ | 193,500 | ||||||||
Coupon Rate (US$) | - | 10 | % | - | 10 | % | ||||||||||
Effective interest rate (Cdn$) | - | 9.68 | % | - | 9.77 | % |
RISK MANAGEMENT
three months ended June 30, | six months ended June 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
Commodity contracts | ||||||||||||||||
Realized (gain) loss | $ | (950 | ) | $ | (3,690 | ) | $ | (3,017 | ) | $ | (7,094 | ) | ||||
Unrealized (gain) loss | (131 | ) | (148 | ) | (232 | ) | 5,981 | |||||||||
Foreign currency contracts | ||||||||||||||||
Unrealized (gain) loss | - | 102 | - | 306 | ||||||||||||
Total risk management (gain) loss | $ | (1,081 | ) | $ | (3,736 | ) | $ | (3,249 | ) | $ | (807 | ) | ||||
Realized (gain) loss | $ | (5,301 | ) | $ | (3,690 | ) | $ | (6,979 | ) | $ | (7,094 | ) | ||||
Unrealized (gain) loss | 4,220 | (46 | ) | 3,730 | 6,287 | |||||||||||
Total risk management (gain) loss | $ | (1,081 | ) | $ | (3,736 | ) | $ | (3,249 | ) | $ | (807 | ) |
COMPTON PETROLEUM CORPORATION | 11 |
Management’s Discussion & Analysis |
The Corporation’s financial results are impacted by external market risks associated with fluctuations in commodity prices, interest rates, and the Canadian/US dollar exchange rate. Compton utilizes various financial instruments for non-trading purposes to manage and mitigate exposure to these risks. Financial instruments are not designated for hedge accounting and accordingly are recorded at fair value on the consolidated balance sheets, with subsequent changes recognized in consolidated net earnings.
Financial instruments utilized to manage risk are subject to periodic settlements throughout the term of the instruments. Such settlements may result in a gain or loss, which is recognized as a realized risk management gain or loss at the time of settlement.
The mark-to-market values of financial instruments outstanding at the end of a reporting period reflect the values of the instruments based upon market conditions existing as of that date. Any change in the fair values of the instruments from that determined at the end of the previous reporting period is recognized as an unrealized risk management gain or loss. Unrealized risk management gains or losses may or may not be realized in subsequent periods depending upon subsequent moves in commodity prices, interest rates or exchange rates affecting the financial instruments.
The Corporation uses hedges for natural gas denominated in giga joules (“GJ”) and million British thermal units (“MMBtu”), oil denominated in barrels and electricity denominated megawatt hours (“MWh”) to stabilize fluctuations in commodity pricing. Currency hedges are applied to reduce exposure to payments due in foreign currencies. The Corporation’s outstanding hedging instruments at June 30, 2012, expressed in Canadian dollars unless otherwise noted, are as follows:
Type |
Term |
Volume | Average Price |
Index | ||||
Electricity | ||||||||
Swap | Jan. 2012 – Dec. 2013 | 72 MWh/d | $75.13/MWh | AESO |
During the quarter, the Corporation monetized all of its outstanding natural gas and oil hedges.
Depletion and Depreciation
three months ended June 30, | six months ended June 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
Total depletion and depreciation | $ | 12,253 | $ | 13,847 | $ | 25,371 | $ | 28,759 | ||||||||
Depletion and depreciation($/boe) | $ | 10.62 | $ | 11.83 | $ | 11.04 | $ | 11.66 |
Total depletion and depreciation expense decreased 12% during the second quarter and 12% on a year-to-date basis in 2012 as compared to 2011, largely due to a decrease in the asset base following impairments recognized in 2011 and 2012, and the reduction in overall production volumes. Depletion and depreciation expense per boe during the second quarter of 2012 decreased by 10% and by 2% on a year-to-date basis over the same period in 2011.
COMPTON PETROLEUM CORPORATION | 12 |
Management’s Discussion & Analysis |
Foreign Exchange and Other (gains) and losses
three months ended June 30, | six months ended June 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
Foreign exchange on translation of US$ debt | $ | - | $ | (1,963 | ) | $ | - | $ | (7,369 | ) | ||||||
(Gain)/loss on disposition of assets | - | 1,334 | (6 | ) | (15,034 | ) | ||||||||||
Other | (6 | ) | 130 | 10 | 156 | |||||||||||
Foreign exchange and other (gains) losses | $ | (6 | ) | $ | (499 | ) | $ | 4 | $ | (22,247 | ) |
The foreign exchange activity has largely been eliminated with the extinguishment of the US Senior Term Notes in September, 2011. The gain on disposition of assets during the second quarter of 2011 relates to two sales transactions including both producing properties and undeveloped lands for combined gross proceeds of $26.2 million.
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. The Corporation’s objectives when managing its capital structure are to:
(a) | ensure the Corporation can meet its financial obligations; |
(b) | retain an appropriate level of leverage relative to the size and risk of Compton’s underlying assets; and |
(c) | finance internally generated growth and potential acquisitions. |
Compton manages its capital structure based on changes in economic conditions and the Corporation’s planned capital requirements. Compton has the ability to adjust its capital structure by making modifications to its capital expenditure program, divesting of assets and by issuing new debt or equity.
The Corporation monitors its capital structure and financing requirements using non-GAAP measures consisting of total net debt to capitalization and total net debt to “Adjusted EBITDA” to steward the Corporation’s debt position as measures of Compton’s overall financial strength.
Adjusted EBITDA is a non-GAAP measure defined as net earnings (loss) before interest and finance charges, income taxes, depletion and depreciation, accretion of decommissioning liabilities, unrealized foreign exchange and other gains (losses), and unrealized risk management gains (losses). The Corporation targets a total net debt to Adjusted EBITDA of 2.5 to 3.0 times.
Capitalization is a non-GAAP measure defined as working capital, long-term debt including current portion, MPP term financing, and shareholders' equity. The Corporation targets a total net debt to Capitalization ratio of between 40% and 50%.
As at June 30, 2012 | As at December 31, 2011 | |||||||
Working capital deficit(1) | $ | 9,952 | $ | 17,070 | ||||
Credit facility(2) | 127,134 | 112,608 | ||||||
MPP term financing(3) | 27,277 | 31,369 | ||||||
Total net debt | 164,363 | 161,047 | ||||||
Total equity | 231,196 | 321,835 | ||||||
Total capitalization | $ | 395,559 | $ | 482,882 | ||||
Total net debt to adjusted EBITDA(4) | 2.6 | x | 2.0 | x | ||||
Total net debt to total capitalization | 41.6 | % | 33.4 | % |
COMPTON PETROLEUM CORPORATION | 13 |
Management’s Discussion & Analysis |
(1) | Adjusted working capital excludes risk management, current MPP term financing and the credit facility. |
(2) | Includes unamortized transaction costs of $218 (December 31, 2011 – $879) |
(3) | Includes unamortized financing fees of $280 (December 31, 2011 – $360) |
(4) | Based on trailing 12 month adjusted EBITDA |
As a result of the Recapitalization reducing the Senior Term Notes by $238.5 million, the Corporation was below the targeted net debt to capitalization ratio as well as the net debt to adjusted EBITDA target at December 31, 2011. At June 30, 2012 persistent low natural gas prices, and the resulting impairment on D&P assets reducing shareholders’ equity, have significantly increased net debt to capitalization and net debt to adjusted EBITDA ratios back to within targeted levels.
Taking into account the current and expected level of natural gas prices, these ratios are expected to be adversely impacted. Thus, the Corporation is in the process of a recapitalization to strengthen its balance sheet sufficiently to establish a sustainable operating base and to create a platform that can take advantage of growth opportunities in the future.
Working Capital
Compton had a working capital deficiency of $10.0 million at June 30, 2012, as compared to a deficiency of $17.1 million as at December 31, 2011. In the oil and gas industry, there is typically 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.)
TAKE-OVER BID
On July 9, 2012, Compton entered into a support agreement (the "Support Agreement") with MFC pursuant to which MFC has agreed to offer to acquire all of the issued and outstanding shares of the Corporation for $1.25 in cash per common share (the “MFC Offer”). Concurrent with the Support Agreement, Compton also entered into an equity private placement agreement (the "Warrant Agreement") with MFC for gross proceeds of approximately $8.2 million, the proceeds of which are to be used for repayment of the credit facility shortfall. The MFC Offer is open for acceptance by Shareholders until 5:00 p.m. (Vancouver time) on August 16, 2012 and is conditional upon, among other things, acceptance by holders of at least 66.67% of the outstanding Common Shares on a fully-diluted basis, including any Special Warrants held by MFC. As of the date of announcement, shareholders holding approximately 54% of the issued and outstanding Common Shares have entered into lock-up agreements to tender their Common Shares. Full details concerning the conditions to the MFC Offer are set out in the MFC Offer and Circular, as well as Compton’s Directors’ Circular. All documents are available on Compton’s website and on SEDAR (www.sedar.com).
CREDIT FACILITY
On April 5, 2012, the credit facility lenders provided notice of a reduction in the credit available under its credit facility from $140.0 million to $110.0 million, with any excess drawn over the available amount with an initial due date of May 7, 2012. The lenders under the credit facility have entered into an extension agreement with Compton under which they have agreed to extend the borrowing base cure period to the earliest of September 30, 2012 (which may be extended in certain circumstances to as late as October 30, 2012), the date on which the MFC Offer is completed, and any date on which the lenders otherwise terminate the extension agreement in accordance with its terms. If the MFC Offer is not completed or the lenders terminate the extension agreement significant uncertainty of the Corporation’s ability to continue as a going concern exists (see “Risk Factors – Liquidity”).
COMPTON PETROLEUM CORPORATION | 14 |
Management’s Discussion & Analysis |
The borrowing base of the credit facility 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 trailing cash flow ratio. The Credit Facility is secured by a fixed and floating charge debenture on the assets of the Corporation.
MPP TERM FINANCING
MPP term financing at June 30, 2012 totaled $27.3 million comprised of the present value of monthly base processing fees, the outstanding purchase option, and unamortized financing fees.
As of June 30, 2012, the remaining purchase option to be paid on or before April 30, 2014 is $16.0 million. The 2011 minimum reserve threshold purchase option prepayment of $4.8 million, which was due prior to the quarter end, has been deferred pending completion or termination of the MFC Offer (see “Take-Over Bid”). Subsequent to quarter end, a purchase option payment of $0.4 million was made.
Management has provided notification of its intent to exercise the purchase option at the end of the term, April 30, 2014.
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 June 30, 2012:
2012 | 2013 | 2014 | 2015 | 2016 | Thereafter | |||||||||||||||||||
Credit facility | $ | 139,122 | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||||
MPP term financing(1) | 10,062 | 9,592 | 13,959 | - | - | - | ||||||||||||||||||
Accounts payable | 32,170 | - | - | - | - | - | ||||||||||||||||||
Finance leases | - | 224 | 223 | - | - | - | ||||||||||||||||||
Office facilities | 790 | 1,631 | 1,609 | 1,637 | 1,688 | 2,672 | ||||||||||||||||||
$ | 182,144 | $ | 11,447 | $ | 15,791 | $ | 1,637 | $ | 1,688 | $ | 2,672 |
(1) | Represents monthly fixed base fee payments; the 2012 amount includes purchase option repayments of $5.2 million |
V. | Outlook |
The current outlook for natural gas in North America remains weak throughout the remainder of 2012 and constrains the Corporation’s ability to generate cash flow for reinvestment. As a result, Management is focused on those areas of its asset base that provide the highest economic return and on maximizing the return of currently producing assets. For the balance of 2012, Compton will continue to limit activity to operate within existing cash flow given the forecast for the natural gas market and financial constraints of the Corporation, including its requirement to repay $30.0 million on its credit facility. Despite a limited 2012 capital expenditure program, Compton’s production performance continues to meet expectations and the annual guidance targets remain unchanged from previous forecasts.
COMPTON PETROLEUM CORPORATION | 15 |
Management’s Discussion & Analysis |
As discussed in the ‘Take-Over Bid’ section, MFC has agreed to offer to acquire all of the issued and outstanding shares of the Corporation for $1.25 in cash per Common Share. Compton’s board of directors (the “Board”) unanimously recommends to shareholders that they accept the MFC Offer and tender their Common Shares thereunder as it’s their determination that the MFC Offer is in the best interests of Compton and its shareholders. The Board took into account numerous factors in reaching the recommendation that Shareholders accept the MFC Offer and tender their Common Shares, including:
· | The MFC Offer is the result of an active, extensive and public process to assess Compton’s strategic alternatives and represents the most attractive and best alternative available to shareholders; |
· | The MFC Offer provides immediate value and liquidity to shareholders; |
· | A number of Compton’s largest shareholders, who collectively hold approximately 54% of the issued and outstanding Common Shares, have entered into lock-up agreements with MFC under which those shareholders have agreed to tender their Common Shares to the MFC Offer; |
· | Compton faces significant financial constraints, including an outstanding borrowing base shortfall under its credit facility, which substantially challenges Compton’s continuing status as a going concern. Compton will be forced to seek creditor protection in the event the MFC Offer is not completed; |
· | The Board of Directors has preserved the ability to respond to unsolicited Superior Proposals; and |
· | The MFC Offer contains a 66.67% Minimum Deposit Condition that cannot be lowered to less than 50% of the outstanding Common Shares plus one (including any Common Shares acquired by MFC or its affiliates as permitted under applicable law or issued or issuable to MFC or its affiliates pursuant to the Special Warrants). |
The MFC Offer will be open for acceptance until 5:00 p.m., Vancouver Time, on August 16, 2012, unless extended or withdrawn by MFC. The MFC Offer is expected to close by early September 2012.
VI. | Internal Control Over Financial Reporting |
The impact on processes, controls and financial reporting systems has been evaluated and necessary modifications have been made to the control environment. There were no significant changes to internal control over financial reporting during the period beginning on January 1, 2012 and ending on June 30, 2012 that materially affected or are reasonably likely to materially affect Compton’s internal control over financial reporting.
VII. | Risks |
The following discussion highlights key risks which could negatively impact Compton’s business, financial condition, and results of operations, cash flows and prospects.
Business Risks
Compton’s exploration and production activities are concentrated in the Western Canadian Sedimentary Basin, where activity is highly competitive and includes a variety of different sized companies ranging from smaller junior producers, intermediate and senior producers, to much larger integrated petroleum companies. Compton is subject to a number of risks that are also common to other organizations involved in the oil and gas industry. Such risks include: finding and developing oil and gas reserves at economic costs; estimating amounts of recoverable reserves; production of oil and gas in commercial quantities; marketability of oil and gas produced; fluctuations in commodity prices; financial and liquidity risks; and environmental and safety risks.
COMPTON PETROLEUM CORPORATION | 16 |
Management’s Discussion & Analysis |
In order to reduce exploration risk, Compton employs qualified and motivated professionals who have demonstrated the ability to generate high-quality proprietary geological and geophysical prospects. To achieve drilling success, Compton explores in areas that afford multi-zone prospect potential, targeting a range of shallower and low to moderate risk prospects with some exposure to select, deeper, and high-risk prospects that offer high-reward opportunities.
Compton engages an independent engineering consulting firm that assists the Corporation in evaluating recoverable amounts of oil and gas reserves. Values of recoverable reserves are based on a number of factors and assumptions such as commodity prices, projected production, future production costs and government regulation. Such estimates may vary from actual results.
The Corporation mitigates its risk related to producing hydrocarbons through the utilization of advanced technology and information systems. In addition, Compton operates the majority of its prospects, thereby maintaining operational control. The Corporation relies on its partners in jointly owned properties that Compton does not operate.
Compton is exposed to market risk to the extent that the demand for oil and gas produced by the Corporation exists within Canada and the United States. External factors beyond the Corporation’s control may affect the marketability of oil and gas. These factors include commodity prices and variations in the Canada-United States currency exchange rate, which in turn respond to economic and political circumstances throughout the world. Oil prices are affected by worldwide supply and demand fundamentals while natural gas prices are affected by North American supply and demand fundamentals. Compton may periodically use futures and options contracts to hedge its exposure against the potential adverse impact of commodity price volatility.
Exploration and production for oil and gas is very capital intensive. As a result, the Corporation relies on debt and equity markets as a source of capital. In addition, Compton utilizes bank financing to support on-going capital investment. Funds from operations also provide Compton with capital required to grow its business. Equity and debt capital is subject to market conditions and availability may increase or decrease from time to time. Funds from operations also fluctuate with changing commodity prices.
Liquidity
Liquidity risk is the risk that the Corporation is not able to meet its financial obligations as they fall due. If the excess drawn on the credit facility cannot be repaid by the due date, or the credit facility is not renewed on February 8, 2013, Compton’s credit facility will mature. If the MFC offer is not completed or the lenders terminate the extension agreement significant uncertainty of the Corporation’s ability to continue as a going concern exists.
Reliance of Key Employees
Compton depends to a large extent on the services of key management personnel, including the Corporation’s executive officers and other key employees. Over the past several months, several employees and executive officers have departed the Corporation and have not been replaced pending resolution of its credit facility issues, which has impacted operations. Compton’s future success will be dependent upon its ability to employ and retain skilled personnel.
COMPTON PETROLEUM CORPORATION | 17 |
Management’s Discussion & Analysis |
Additional Funding Requirements
In the current natural gas price environment, Compton’s ongoing activities do not generate sufficient cash flow from operations to fund future exploration, development or acquisition programs. The Corporation will require additional funding and there can be no assurance that debt or equity financing will be available or sufficient to meet these requirements or that it will be on acceptable terms. Continued uncertainty in domestic and international credit markets compounds the risk of obtaining debt financing. Failure to obtain such financing on a timely basis could cause Compton to forfeit interests in certain properties, miss certain acquisition opportunities, and reduce or terminate operations. This may result in the Corporation not being able to replace its reserves or maintain production, which will have an adverse effect on its financial position. Failure to obtain additional funding may also result in the Corporation failing to meet financial obligations as they come due or result in the acceleration of the Corporation’s debt. (see “Risk Factors- Liquidity”)
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, 2011, available onwww.sedar.com.
VIII. | Forthcoming and Newly Adopted Accounting Policies |
changes in accounting policies
Recent Accounting Pronouncements
There were no new accounting pronouncements issued that affected the Corporation during the second quarter of 2012.
IX. | Quarterly Information |
The following table sets forth certain quarterly financial information of the Corporation for the eight most recent quarters.
2012 | 2011(1) | 2010(1) | ||||||||||||||||||||||||||||||
$millions, except where noted | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | ||||||||||||||||||||||||
Total revenue | $ | 25.3 | $ | 25.0 | $ | 32.7 | $ | 39.0 | $ | 34.7 | $ | 35.6 | $ | 39.8 | $ | 36.7 | ||||||||||||||||
Cash flow | $ | 5.4 | $ | 3.8 | $ | 12.4 | $ | 15.3 | $ | 7.1 | $ | 7.6 | $ | 14.9 | $ | 0.8 | ||||||||||||||||
Per share - basic | $ | 0.20 | $ | 0.14 | $ | 0.49 | $ | 1.76 | $ | 5.42 | $ | 5.79 | $ | 7.59 | $ | 0.64 | ||||||||||||||||
- diluted | $ | 0.20 | $ | 0.14 | $ | 0.49 | $ | 1.28 | $ | 2.24 | $ | 3.85 | $ | 5.47 | $ | 0.64 | ||||||||||||||||
Net earnings (loss) | $ | (47.0 | ) | $ | (44.3 | ) | $ | (6.8 | ) | $ | 28.3 | $ | (7.7 | ) | $ | 3.5 | $ | (440.0 | ) | $ | (33.0 | ) | ||||||||||
Per share - basic | $ | (1.78 | ) | $ | (1.68 | ) | $ | (0.26 | ) | $ | 3.26 | $ | (5.82 | ) | $ | 2.63 | $ | (333.84 | ) | $ | (25.08 | ) | ||||||||||
- diluted | $ | (1.78 | ) | $ | (1.68 | ) | $ | (0.26 | ) | $ | 2.41 | $ | (5.82 | ) | $ | 2.17 | $ | (333.84 | ) | $ | (25.08 | ) | ||||||||||
Operating earnings (loss) | $ | (17.7 | ) | $ | (18.7 | ) | $ | (2.2 | ) | $ | (2.0 | ) | $ | (5.7 | ) | $ | 6.5 | $ | (31.6 | ) | $ | (16.3 | ) | |||||||||
Production | ||||||||||||||||||||||||||||||||
Natural gas (mmcf/d) | 62.4 | 62.5 | 63.6 | 67.1 | 64.8 | 72.3 | 74.6 | 80.9 | ||||||||||||||||||||||||
Liquids (bbls/d) | 2,284.9 | 2,158.7 | 2,126.0 | 2,239.6 | 1,946.7 | 2,454.9 | 2,411.0 | 2,452.5 | ||||||||||||||||||||||||
Total (boe/d) | 12,678.1 | 12,568.7 | 12,725.3 | 13,428.8 | 12,747.8 | 14,506.6 | 14,851.9 | 15,930.5 | ||||||||||||||||||||||||
Average price | ||||||||||||||||||||||||||||||||
Natural gas ($/mcf) | $ | 2.03 | $ | 2.44 | $ | 3.53 | $ | 4.01 | $ | 4.10 | $ | 4.01 | $ | 3.87 | $ | 3.84 | ||||||||||||||||
Liquids ($/bbl) | $ | 78.85 | $ | 81.85 | $ | 88.31 | $ | 78.10 | $ | 88.39 | $ | 69.11 | $ | 69.30 | $ | 59.39 | ||||||||||||||||
Total ($/boe) | $ | 24.19 | $ | 26.17 | $ | 32.40 | $ | 33.06 | $ | 34.35 | $ | 31.68 | $ | 30.70 | $ | 28.61 |
(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 |
COMPTON PETROLEUM CORPORATION | 18 |
Management’s Discussion & Analysis |
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 from 2011 to 2012. The second quarter of 2012 also had reduced production levels resulting from a scheduled facility maintenance outage. Seasonality of winter operating conditions results in production increases that are typically higher in the third and fourth quarters.
Net earnings for each of last three quarters in 2011 and the first two quarters of 2012 include impairment adjustments for petroleum and natural gas assets. During the third quarter of 2011, net earnings were increased following a gain on extinguishment of Senior Term Notes.
Cash flow and operating earnings are affected by realized commodity prices, and realized hedging. Prior to the third quarter of 2011, the impact of fluctuations in the US dollar against the Canadian dollar relating to the conversion of USD denominated Senior Term Notes also affected cash flow and operating earnings.
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.
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, does 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.
COMPTON PETROLEUM CORPORATION | 19 |
Management’s Discussion & Analysis |
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.
COMPTON PETROLEUM CORPORATION | 20 |