Connacher Reports Q3 2010 Results: Cash Flow Up 46% in the Quarter and 82%
YTD 2010; Great Divide Bitumen Production Rates Reach 14,000 bbl/d and Weekly
Recorded Rates Double YTD 2010 Results; Algar Commerciality Achieved
Effective October 2010; Conventional Property Rationalization Initiated
CALGARY, Nov. 10 /CNW/ - Connacher Oil and Gas Limited (CLL-TSX) announced today it continues to ramp up its production of bitumen at Great Divide, with recent daily levels reaching 14,000 bbl/d and recent weekly recorded rates double year-to-date ("YTD 2010") averages. Volumes reported include production from Algar. Results from Algar were being capitalized and are not included in the company's operating results for the reporting period. Commerciality for Algar has now been achieved. The determination occurred within two months of full steam-assisted gravity drainage ("SAGD") production startup. Algar operating results will now be included in fourth quarter 2010 and year-end 2010 reports.
We have had a string of achievements during 2010. Algar was built and completed on time and under budget. After a successful commissioning, steaming was initiated and full SAGD production commenced in August 2010. We now have 15 well pairs on full production rampup, we are circulating steam in a 16th well pair and have not yet steamed the 17th well pair on the project. We introduced some technical innovations in these wells, which we anticipate will contribute to the continuation of a rapid and possibly record rampup for SAGD operations in the oilsands and excellent continuing productivity.
We constructed our 13.1 megawatt Algar co-generation facility ("Co-Gen") on time and on budget and commenced producing electrical power for Algar in September 2010. We have accordingly derisked our previous exposure to erratic power supply from the regional grid. Islanding Algar also stabilized power supplies at Pod One. Once a new substation to be constructed in the area by the local power utility is completed, likely in the first half of 2011, we anticipate power reliability will further improve. The Co-Gen plant can also produce approximately 3,700 bbl/d of surplus steam, which derisks the possibility of stressing our steam generating capacity and provides increased operational flexibility.
With these developments, we are also pleased that operations at Pod One have become much more reliable, with increasingly consistent steam generation and bitumen production. We believe bitumen production from Pod One will continue to improve going forward and will realize further benefits once regional power supplies are enhanced in 2011, thus reducing the likelihood of power interruptions and the collateral impact on pump performance and reliability. Steam generation and injection should also occur on a more consistent basis, and this increased reliability is also anticipated to enhance production levels.
Our conventional production base continues to perform in a reliable manner despite adverse weather conditions throughout the summer months in western Canada, which slowed down certain projects being undertaken, especially at Battrum, Saskatchewan. We are pleased to report, however, that significant production improvements at this property are now being recorded as a result of successful workover and construction programs.
We have initiated rationalization of a portion of our conventional properties, having announced the proposed sale of Battrum, our legacy property in southwest Saskatchewan and the possible disposition of our northern Alberta natural gas properties. From our perspective, we feel that Battrum has matured and that it will be a more attractive property for companies either with an established base in the area, or seeking a stable new cash flow base. We also believe that, with recent developments in the natural gas industry, ample natural gas supplies at reasonable prices will be available to us for our oil sands operations for some time. Proceeds, if any, from concluded property sales will be redeployed in 2011 in our oil sands and conventional business, with anticipated higher returns. Completion of these proposed asset sales is dependent on negotiation of terms and conditions satisfactory to Connacher.
Our Great Falls, Montana refining operation had excellent results in Q3 2010 and YTD 2010, in part capitalizing on widened heavy oil differentials, which emerged during the reporting period and persisted into October 2010. Significant net operating income was generated, buoyed by higher commodity prices and strong asphalt markets, despite adverse weather conditions throughout the summer in regions around Great Falls and in southern Alberta. We substantially outperformed most of the refining industry during this period and continue to experience healthier economic returns than in many other parts of the USA and Canada.
Our year over year quarterly cash flow growth of 46 percent and year-to-date growth of 82 percent underscore the progress we are making as a company. We believe 2011 will be a solid year for Connacher, with the prospect of considerable growth in net operating income and cash flow, as we experience continuing improvements in our production levels from Great Divide, even if modestly tempered by temporarily reduced conventional production, if we are successful in our conventional rationalization program. We anticipate this growth of earnings before interest, taxes, depreciation and amortization or EBITDA, a non-GAAP measurement, will provide more than adequate coverage of our financial obligations as we grow into our balance sheet and the debt obligations incurred to construct our Pod One, Algar and Co-Gen plants at Great Divide. We believe this de-risking may result in improved equity prices and a better credit rating for the company.
Our application to expand Great Divide operations at Algar by a further 24,000 bbl/d of capacity is proceeding through the regulatory process. We do not expect a conclusion of this application to be reached much before the end of 2011. As a consequence, we anticipate a relatively "normal" year during 2011 as we consolidate and streamline our operations and conduct a much more modest capital spending program, financed by internally generated funds and the proceeds of our successful $25 million flow-through financing, which closed just after the end of the reporting period. This hiatus will enable us to concentrate on solid pre-planning on the scope and timing of our future expansion, while we advance our commitment to operational excellence in our production operations in Canada and Montana.
Subsequent to the reporting period we submitted an application to regulators to initiate a SAGD plus solvent pilot at one of the well pads at Algar. This process is designed to reduce steam requirements while considerably enhancing well productivity and reserve recovery factors over time. We have been conducting studies on this process for some time and are considerably enthused about its potential. It will likely take up to six months to secure regulatory approval and then sometime thereafter to report the results of the initiative. We continue to introduce technological innovations to enhance SAGD performance.
These results will be the subject of a Conference Call at 8:00 AM MT on November 11, 2010. To listen to or participate in the live conference call please dial either 1-647-427-7450 or 1-888-231-8191. A replay of the event will be available from Thursday, November 11, 2010 at 12:00 MT until 21:59 MT on Thursday, November 18, 2010. To listen to the replay please dial either 1-416-849-0833 or Toll Free at 1-800-642-1687 and enter the pass code 20779251. You can also listen to the conference call online, through the following webcast link: http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID=3285480
The company will soon post an updated investor presentation on its
website at www.connacheroil.com.
Highlights
- Q3 2010 cash flow up 46 percent; YTD 2010 up 82 percent
- Full SAGD bitumen production initiated at Algar; ramp up
proceeding favourably; commerciality achieved in October 2010
- Total Great Divide daily bitumen production has reached 14,000
bbl/d; recent weekly production double YTD levels(1)
- Algar cogeneration ("CoGen") plant completed on time, on budget;
commissioned and operational
- Strong refining results in reporting period, offsetting
temporarily wide upstream heavy oil price differentials
- Successful flow through equity raise for 2011 exploration at
Great Divide yields $25.3 million
- SAGD plus solvent application submitted for portion of Algar
(1) Algar results were capitalized and excluded from operating
results for the reporting periods.
Summary Results
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Three months ended and as at Sept 30
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FINANCIAL ($000 except
per share amounts) 2010 2009 % Change
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Revenues $150,293 $151,360 (1)
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Cash flow(1) $15,178 $10,410 46
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Per share, basic and diluted(1) $0.04 $0.03 33
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Net earnings (loss) $7,946 $47,767 (83)
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Per share, basic $0.02 $0.12 (83)
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Per share, diluted $0.02 $0.11 (82)
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Property and equipment additions $49,842 $100,727 (51)
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Cash on hand $51,120 $333,634 (85)
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Working capital $61,543 $347,139 (82)
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Long-term debt $867,650 $889,113 (2)
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Shareholders' equity $648,543 $658,336 (1)
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Total assets $1,717,700 $1,736,126 (1)
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OPERATIONAL
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Upstream daily production/sales
volumes
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Bitumen (bbl/d) 6,758 6,551 3
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Crude oil (bbl/d) 819 993 (18)
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Natural gas (Mcf/d) 9,158 10,377 (12)
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Barrels of oil equivalent
(boe/d)(2) 9,103 9,274 (2)
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Upstream pricing(3)
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Bitumen ($/bbl) $42.68 $45.30 (6)
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Crude oil ($/bbl) $62.45 $60.58 3
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Natural gas ($/Mcf) $3.42 $2.91 18
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Barrels of oil equivalent ($/boe)(2) $40.74 $41.74 (2)
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Downstream
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Throughput - Crude charged (bbl/d) 9,903 7,076 40
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Refinery utilization (%) 104 75 39
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Margins (%) 12 8 50
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Nine months ended and as at Sept 30
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FINANCIAL ($000 except
per share amounts) 2010 2009 % Change
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Revenues $409,974 $313,336 31
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Cash flow(1) $27,794 $15,288 82
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Per share, basic and diluted(1) $0.06 $0.05 -
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Net earnings (loss) $(19,634) $40,889 (148)
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Per share, basic $(0.05) $0.14 (136)
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Per share, diluted $(0.05) $0.14 (136)
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Property and equipment additions $227,430 $205,218 11
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Cash on hand $51,120 $333,634 (85)
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Working capital $61,543 $347,139 (82)
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Long-term debt $867,650 $889,113 (2)
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Shareholders' equity $648,543 $658,336 (1)
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Total assets $1,717,700 $1,736,126 (1)
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OPERATIONAL
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Upstream daily production/sales
volumes
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Bitumen (bbl/d) 6,635 6,336 5
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Crude oil (bbl/d) 887 1,095 (19)
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Natural gas (Mcf/d) 9,364 11,774 (20)
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Barrels of oil equivalent
(boe/d)(2) 9,083 9,394 (3)
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Upstream pricing(3)
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Bitumen ($/bbl) $46.02 $36.53 26
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Crude oil ($/bbl) $65.27 $51.20 27
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Natural gas ($/Mcf) $4.03 $3.77 7
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Barrels of oil equivalent ($/boe)(2) $44.15 $35.33 25
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Downstream
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Throughput - Crude charged (bbl/d) 9,541 7,696 24
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Refinery utilization (%) 100 81 23
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Margins (%) 7 7 -
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(1) Cash flow and cash flow per share do not have standardized meanings
prescribed by Canadian generally accepted accounting principles
("GAAP") and therefore may not be comparable to similar measures used
by other companies. Cash flow is calculated before changes in
non-cash working capital, pension funding and asset retirement
expenditures. The most comparable measure calculated in accordance
with GAAP would be cash flow from operating activities. Cash flow is
reconciled with cash flow from operating activities on the
Consolidated Statement of Cash Flows and in the accompanying
Management's Discussion & Analysis ("MD&A"). Commonly used in the oil
and gas industry, management uses these non-GAAP measurements for its
own performance measures and to provide its shareholders and
investors with a measurement of the company's efficiency and its
ability to internally fund future growth expenditures.
(2) All references to barrels of oil equivalent (boe) are calculated on
the basis of 6 Mcf: 1 bbl. This conversion is based on an energy
equivalency conversion method primarily applicable at the burner tip
and does not represent a value equivalency at the wellhead. Boes may
be misleading, particularly if used in isolation.
(3) Product pricing is net of transportation costs but before realized
and unrealized risk management contracts gains/losses.
On August 11, 2010 Connacher commenced full-scale steam-assisted gravity drainage ("SAGD") bitumen production at Algar, the company's second 10,000 bbl/d (design capacity) bitumen recovery plant in the Great Divide region of Alberta. We now have 15 of the project's 17 well pairs on stream, with one well still in the circulation phase. The seventeenth well has not yet been steamed. Recently, we completed workovers on selected wells to optimize steam injection and production from the middle of the well bores, a design innovation relative to Pod One. Our ramp up was temporarily flattened during this short process, but has since continued at record rates. Steam injection has increased following these minor planned modifications and production should continue to improve as more steam is injected and related steam chambers develop and eventually coalesce underground. It should be noted that production levels during ramp up can fluctuate on a daily basis, as produced emulsions in the early stages of a ramp up are variable, as new surface equipment is activated and as volumes escalate towards design capacity. Note that Algar production, related costs and revenues were capitalized and were not recorded in the company's operating results during the reporting periods.
Subsequent to the end of the reporting period following receipt of preliminary operating data for October 2010, we have achieved commerciality at Algar. In October 2010, operating results will be incorporated with our fourth quarter 2010 and full year 2010 results. Commerciality was remarkably achieved in under two months from start-up of full SAGD production.
Our total daily bitumen production from Pod One and Algar recently reached 14,000 bbl/d and recent weekly recorded rates have been double our YTD 2010 levels. When combined with our conventional production, which reached 2,460 boe/d (including 993 bbl/d of crude oil and natural gas liquids) during the same time frame, our total corporate production approached 16,000 boe/d.
In early September 2010, we activated our 13.1 megawatt CoGen facility at Algar. This plant was built on time and on budget at a cost of approximately $30 million. The plant is also capable of generating 3,700 bbl/d of steam at full design rate, which will provide Algar with more operational flexibility. It was integrated with the Algar plant upon activation approximately two weeks ahead of schedule and Algar is now islanded from the regional grid. The activation of the CoGen plant has contributed to improved power reliability, both at Algar and also at Pod One, where numerous power interruptions and collateral impact on pump durability were experienced during the second quarter and into the third quarter of 2010. This problem has ameliorated dramatically in recent weeks and months. Once a new nearby regional substation is completed by the local power utility, likely in the first half of 2011, power reliability may be further enhanced with additional operational benefits.
Pod One continues to demonstrate steady improvements in overall operating reliability and volumes. Recent bitumen production exceeded 7,300 bbl/d for a week in late October, an increase of ten percent over third quarter and year-to-date ("YTD") averages. A steady state operation with fewer electrical disruptions and continuous steam injection are contributing to this improved reliability. Also, recently we received regulatory approval for the co-injection of methane with steam on the five northern well pairs at Pod One. This process was designed to reduce steam: oil ratios ("SORs") while maintaining or improving production levels from these well pairs. Available steam could then be diverted to other well pairs with lower SORs at Pod One to increase overall production. This co-injection project is one of the first commercial approvals of its kind in the oil sands and its implementation aligns with Connacher's strategy of continuously pursuing methods of improving the SAGD process.
Subsequent to the reporting period, we further advanced our commitment to technical innovation in bitumen recovery with an application to regulators for approval to introduce SAGD plus solvent at one of our Algar well pads. This process is designed to lower steam oil ratios, enhance well productivity and improve overall recovery factors. We have been analysing this process in the laboratory and numerical simulation and are optimistic about the potential of our anticipated field application.
Operations at our 9,500 bbl/d heavy oil refinery located in Great Falls, Montana were strong during the third quarter 2010. Crude charged during the month of September 2010 averaged slightly in excess of 10,200 bbl/d, for a utilization rate of 108 percent. Weather conditions improved during the latter part of September and into October, which facilitated active paving and strong asphalt sales. Diesel and jet fuel prices continued to be robust. Overall refinery results during the reporting period also reflect the benefit of widening differentials for heavy oil, arising from the short term market interruption related to the disruption of the Enbridge pipeline system. These results partially offset the dampening effect of wider heavy oil pricing differentials on the company's upstream bitumen during September 2010 and October 2010. More normal pricing conditions for heavy oil are already evident.
We recently received gross proceeds of $25.3 million from a successful underwritten sale of 17,480,000 flow-through common shares from treasury at a price of $1.45 per flow through share. Proceeds will be used to finance Connacher's 3D seismic and core hole drilling exploration program on its oil sands acreage in the general Great Divide region. This program will be initiated in early 2011 with the drilling of approximately 80 core holes this winter.
Your company continues to make enviable progress in its operations. Cash flow growth for the third quarter and nine months ended September 30, 2010 grew by 46 percent and 82 percent, respectively. With the construction of Algar and the related CoGen plant, we reinforced our reputation for on time, on budget performance. Our rampup and total production at Great Divide Pod One and Algar continues to grow. Our conventional production remains stable and reliable with new play potential to be realized. Our refinery is making solid contributions and serving its purpose as a differential hedge during periods of market dislocation for heavy oil, such as was experienced following the Enbridge pipeline rupture.
While weaker selling prices, sticky operating costs and the adverse impact of the Enbridge pipeline break on heavy oil differentials and pricing caused us to reduce our detailed forecast for the full year, we remain optimistic about our growth potential, financial stability and ability to be self-sufficient in our capital programs during 2011. We envisage a capital budget of approximately $104 million during 2011, comprised of $50 million in sustaining and maintenance capital in our upstream operations and at our refinery in Montana along with a limited level of growth expenditures and our $25 million oil sands exploration program. We have examined the merits of rationalizing our conventional property base, to the extent these properties have matured or do not offer the same growth possibilities of other less-developed assets in our conventional base. As a result, we have initiated a sales process for our Battrum oil property and Marten Creek natural gas properties. Proceeds from such rationalization would be redeployed in our oil sands and conventional business activity. We do not anticipate any additional financing activity during the balance of 2010 or in 2011, with the possible exception of renegotiating our existing bank credit facility to extend term and reduce costs, in keeping with market conditions. All of our debt is long-term, with our first maturity in 2012 and remaining maturities in 2014 and 2015. We will monitor the long-term debt market for advantageous refinancing alternatives, when permitted by existing call provisions and maturities and provided price and term alternatives currently extant in the public debt market remain favourable.
Our focus in 2011 will be on optimizing our production at Great Divide, rationalizing our conventional assets and delivering successive and sustained improvement in operating and financial results at low cost.
Forward Looking Information:
This press release contains forward looking information including but not limited to expectations of future production growth at Pod One and Algar for the balance of 2010 and 2011, plans for continued optimization of Pod One and Algar, development of additional oil sands reserves (including the expansion of bitumen productive capacity from 20,000 bbl/d to 44,000 bbl/d and the anticipated timing of required regulatory approvals associated therewith), expected timing for completion of an electrical substation which is anticipated to improve the stability of power at Pod One and Algar, the proposed sale of Battrum and potential sale of natural gas properties in northern Alberta and the use of proceeds from such dispositions should they occur, anticipated improvements in operating and financial results in the balance of 2010 and 2011 as a result of increased production, low natural gas prices, improved operating efficiencies, stabilized crude oil prices and anticipated reductions in SORs and operating costs, the adequacy of coverage of our financial obligations and the resulting impact on the company's equity price and credit ratings, the capital spending program for 2011 and the anticipated timing of regulatory approvals associated with the application to introduce SAGD plus solvent at one of our Algar well pads.
Forward looking information is based on management's expectations regarding future growth, results of operations, production, future commodity prices and foreign exchange rates, future capital and other expenditures (including the amount, nature and sources of funding thereof), plans for and results of drilling activity, environmental matters, business prospects and opportunities and future economic conditions. Forward looking information involves significant known and unknown risks and uncertainties, which could cause actual results to differ materially from those anticipated. These risks include, but are not limited to: the risks associated with the oil and gas industry (e.g., operational risks in development, exploration and production; delays or changes in plans with respect to explorationor development projects or capital expenditures; the uncertainty of reserve and resource estimates, the uncertainty of geological interpretations, the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), the risk of commodity price and foreign exchange rate fluctuations, risks associated with the impact of general economic conditions, risks and uncertainties associated with securing and maintaining the necessary regulatory approvals and financing to proceed with the operation and continued expansion of the Great Divide oil sands project and the SAGD plus solvent pilot and risks associated with the marketing and proposed sale of certain of our conventional oil and gas properties. Additional risks and uncertainties affecting Connacher and its business and affairs are described in further detail in Connacher's Annual Information Form for the year ended December 31, 2009, which is available at www.sedar.com. Although Connacher believes that the expectations in such forward looking information are reasonable, there can be no assurance that such expectations shall prove to be correct. The forward looking information included in this press release is expressly qualified in its entirety by this cautionary statement. The forward looking information included herein is made as of the date of this press release and Connacher assumes no obligation to update or revise any forward looking information to reflect new events or circumstances, except as required by law.
MANAGEMENT'S DISCUSSION AND ANALYSIS
This Management's Discussion and Analysis ("MD&A") is dated as of November 8, 2010 and should be read in conjunction with Connacher's interim consolidated financial statements for the three months ended September 30, 2010 ("Q3 2010") and 2009 ("Q3 2009") and nine months ended September 30, 2010 ("YTD 2010") and 2009 ("YTD 2009") and the MD&A and the audited consolidated financial statements for the years ended December 31, 2009 and 2008. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles ("GAAP") and are presented in Canadian dollars. MD&A provides management's view of the financial condition of the company and the results of its operations for the reporting periods. Additional information relating to Connacher, including Connacher's Annual Information Form ("AIF"), can be found on SEDAR at www.sedar.com or the company's website at www.connacheroil.com.
NON-GAAP MEASUREMENTS
The MD&A contains terms commonly used in the oil and gas industry, such as cash flow, cash flow per share, netback, bitumen netback, conventional netback, refinery margins or netback, corporate netback and adjusted earnings before interest, taxes, depreciation and amortization ("adjusted EBITDA"). These terms are not defined by GAAP and should not be considered an alternative to, or more meaningful than, cash provided by operating activities or net earnings as determined in accordance with GAAP as an indicator of Connacher's performance. Management believes that in addition to net earnings, cash flow, netbacks or margins and adjusted EBITDA are useful financial measurements which assist in demonstrating the company's ability to fund capital expenditures necessary for future growth or to repay debt. Connacher's determination of cash flow, netbacks, margins and adjusted EBITDA may not be comparable to that reported by other companies. All references to cash flow throughout this report are based on cash flow from operating activities before changes in non-cash working capital, pension funding and asset retirement expenditures. The company calculates cash flow per share by dividing cash flow by the weighted average number of common shares outstanding. Upstream netbacks, including by product, are calculated by deducting the related diluent, transportation, field operating costs and royalties from upstream revenues. Downstream margins or netbacks are calculated by deducting crude oil and operating costs from refining sales revenues. Adjusted EBITDA is calculated as net earnings before finance charges, taxes, depreciation, amortization and accretion, stock based compensation, foreign exchange gains/losses, unrealized gains/losses on risk management contracts, interest/other income, equity earnings/losses and dilution gains/losses. Cash flow is reconciled to cash flow from operating activities and netbacks and adjusted EBITDA are reconciled to net earnings herein. Additionally, future anticipated 2010 netbacks and 2010 adjusted EBITDA are reconciled to actual results in the MD&A on a quarterly basis.
FORWARD-LOOKING INFORMATION
This report, including the Letter to Shareholders and the updated 2010 financial outlook contained in the MD&A, contains forward-looking information including but not limited to, anticipated future operating and financial results, forecast netbacks and margins, forecast realized gain (loss) on risk management contracts, future corporate general and administration expenses, forecast adjusted EBITDA, future profitability, expectations of future production, anticipated sales volumes for the balance of 2010 and 2011, further anticipated reductions in operating costs as a result of continued operational optimization at Great Divide Pod One and Algar, expected operational performance of the cogeneration facility at Algar and subsequent completion of an electrical substation which is anticipated to improve the stability of power at Pod One and Algar, planned injection of methane into well pairs at Pod One, anticipated capital expenditures for the balance of 2010 and 2011, anticipated sources of funding for capital expenditures and current financial obligations, potential rationalization of the conventional property base, future development and exploration activities, estimates of future commodity prices, foreign exchange rates and heavy oil differentials, utilization of alternative financial derivative strategies to protect the company's cash flow and the anticipated impact of the conversion to International Financing Reporting Standards ("IFRS") on the company's consolidated financial statements. Forward-looking information is based on management's expectations regarding future growth, results of operations, production, future commodity prices and foreign exchange rates, future capital and other expenditures (including the amount, nature and sources of funding thereof), plans for and results of drilling activity, environmental matters, business prospects and opportunities, future economic conditions and the plans and expected impacts of adopting IFRS.
Forward-looking information involves significant known and unknown risks and uncertainties, which could cause actual results to differ materially from those anticipated. These risks include, but are not limited to operational risks in development, exploration, production and start-up activities; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve and resource estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks; the risk of commodity price and foreign exchange rate fluctuations; risks associated with the impact of general economic conditions; and risks and uncertainties associated with securing and maintaining the necessary regulatory approvals and financing to proceed with the continued expansion of the Great Divide oil sands project.
The 2010 financial outlook contained in the MD&A is based on certain assumptions regarding revenue (including production levels, refinery throughput, commodity prices, heavy oil pricing differentials, quality of bitumen produced, foreign exchange rates and transportation costs), operating and other costs, royalties, general and administrative costs and risk management contracts which are detailed in the notes to the tables contained in the MD&A. Actual netbacks and adjusted EBITDA realized by Connacher in 2010 could differ materially from the estimates contained in the 2010 financial outlook. Material risks and uncertainties that may impact achievement of the 2010 netbacks and adjusted EBITDA are described in the MD&A. In addition, the 2011 outlook contained in MD&A is based on certain assumptions regarding operational performance including, among others, steam generation levels and steam oil ratios, timing and duration of planned maintenance activities and results thereof, unplanned operational upsets, well productivity, realized netbacks which may accelerate or delay our capital program, including planned facility optimization programs and future market conditions and is subject to risk and uncertainties, including those risk and uncertainties described above. Additional risks and uncertainties are described in further detail in Connacher's Annual Information Form for the year ended December 31, 2009 which is available at www.sedar.com.
Although Connacher believes that the expectations in such forward-looking information are reasonable, there can be no assurance that such expectations shall prove to be correct. The forward-looking information included in this report is expressly qualified in its entirety by this cautionary statement. The forward-looking information included in this report is made as of November 8, 2010 and Connacher assumes no obligation to update or revise any forward-looking information to reflect new events or circumstances, except as required by law.
Throughout the MD&A, per barrel of oil equivalent (boe) amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil (6:1). The conversion is based on an energy equivalency conversion method primarily applicable to the burner tip and does not represent a value equivalency at the wellhead. Boes may be misleading, particularly if used in isolation
PRICING
General economic conditions and international and local supplies, together with many other uncontrollable variables, influence the price for crude oil (which is typically priced in U.S. dollars by reference to a West Texas Intermediate or "WTI", benchmark prices). Weather, domestic supplies, restricted continental markets and other variables influence the market price for natural gas. Our revenues, cash flow and earnings are significantly influenced by the volatility of crude oil and natural gas prices. The following table shows the market prices of the petroleum products.
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Average prices Three months ended Nine months ended
for the periods September 30 September 30
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2010 2009 % 2010 2009 %
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West Texas
Intermediate (WTI)
crude oil US$/
barrel at Cushing $76.09 $68.14 12 $77.58 $57.21 36
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Natural Gas
(Alberta spot)
Cdn$/Mcf at AECO $3.54 $2.99 18 $4.11 $3.77 9
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Upstream
Connacher's crude oil and bitumen production slate is heavier gravity than the referenced WTI. Consequently, the market price realized by the company is lower than the WTI reference price. This difference is commonly referred to as the "heavy oil differential". Although WTI was higher in Q3 2010 compared to Q3 2009, heavy oil differentials widened substantially resulting in lower bitumen realized prices in Q3 2010. Additionally, a change in the value of the U.S. dollar also resulted in lower realized bitumen prices as noted in the tables below. Before risk management contracts gains and losses and after deducting applicable diluent and transportation costs, Connacher realized the following commodity selling prices.
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Upstream average Three months ended Nine months ended
realized prices September 30 September 30
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(Canadian dollars) 2010 2009 % 2010 2009 %
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Bitumen - $/bbl $42.68 $45.30 (6) $46.02 $36.53 26
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Crude oil - $/bbl $62.45 $60.58 3 $65.27 $51.20 27
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Natural gas - $/Mcf $3.42 $2.91 18 $4.03 $3.77 7
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Diluted bitumen ("dilbit"), crude oil and natural gas are generally sold on month-to-month sales contracts negotiated with major Canadian or U.S. marketers, refiners, regional upgraders or other end users, at either spot reference prices or at prices subject to commodity contracts based on WTI market prices for crude oil and AECO market prices for natural gas. In this regard, Connacher has entered into various short-term contracts for the supply of dilbit to a variety of heavy oil purchasers in central and northern Alberta. In order to secure preferred diluent supplies, Connacher has also entered into several short-term diluent purchase contracts. As a means of managing the risk of commodity price volatility, Connacher enters into risk management commodity sales contracts from time to time. Our selling prices received for dilbit sales in the three and nine month periods ended September 30, 2010 were also influenced by the following WTI crude oil price hedging sales contracts.
- Calendar year 2010 - 2,500 bbl/d at WTI US$78.00/bbl;
- February 1, 2010 - April 30, 2010 - 2,500 bbl/d at WTI US$79.02/bbl;
- May 1, 2010 - December 31, 2010 - 2,500 bbl/d at a minimum of WTI
US$75.00/bbl and a maximum of WTI US$95.00/bbl;
- January 1, 2011 - March 31, 2011 - 1,000 bbl/d at WTI US$86.10/bbl;
- January 1, 2011 - March 31, 2011 - 1,000 bbl/d at WTI US$88.10/bbl;
- January 1, 2011 - December 31, 2011 - 2,000 bbl/d at WTI US$90.60/bbl
and the counterparty has a right, on December 30, 2011, to extend the
maturity of the contract for one additional year at the same price;
- January 1, 2011 - March 31, 2011 - 2,000 bbl/d at a minimum of WTI
US$80.00/bbl and a maximum of WTI US$100.25/bbl; and
- April 1, 2011 - June 30, 2011 - 2,000 bbl/d at WTI US$85.25/bbl.
Subsequent to September 30, 2010, the company entered in the following risk management contract:
- April 1, 2011 - March 31, 2012 - 2,000 bbl/d at a minimum of WTI
US$80.00 bbl/d and a maximum of WTI US$96.00/bbl.
The following table shows the realized and unrealized gains and losses recorded for these contracts.
-------------------------------------------------------------------------
Three months ended Nine months ended
(Canadian dollar in thousands) September 30 September 30
-------------------------------------------------------------------------
2010 2009 2010 2009
-------------------------------------------------------------------------
Unrealized gain (loss) $(6,933) $14,753 $2,725 $(1,757)
-------------------------------------------------------------------------
Realized gain (loss) 424 (8,311) (73) (14,068)
-------------------------------------------------------------------------
Gain (loss) on risk
management contracts $(6,509) $6,442 $2,652 $(15,825)
-------------------------------------------------------------------------
Downstream
Higher refined petroleum product prices in Q3 2010 and YTD 2010 were consistent with higher average WTI prices. Selling prices of refined petroleum products are also influenced by general economic conditions and local and international supply and demand factors. Realized selling prices for refined products sold by our wholly-owned subsidiary Montana Refinery Company, Inc. ("MRCI") are noted below.
-------------------------------------------------------------------------
Downstream average Three months ended Nine months ended
realized prices September 30 September 30
-------------------------------------------------------------------------
(U.S. dollars
per bbl) 2010 2009 % 2010 2009 %
-------------------------------------------------------------------------
Gasoline $88.32 $80.79 9% $87.29 $67.17 30%
-------------------------------------------------------------------------
Diesel $91.41 $75.90 20% $90.75 $67.90 34%
-------------------------------------------------------------------------
Asphalt $84.97 $78.22 9% $82.04 $72.85 13%
-------------------------------------------------------------------------
Jet fuel $94.80 $87.35 9% $95.06 $80.42 18%
-------------------------------------------------------------------------
Sales of refined petroleum products are generally made on monthly sales contracts negotiated with wholesalers, retailers and large end-users for gasoline, jet fuel and diesel and with construction contractors and road builders for asphalt. Occasionally, sales contracts are for periods in excess of one month.
In March 2010, the company entered into a risk management sales contract to hedge a portion of the Refinery's gasoline revenue. The contract expired on September 30, 2010 and resulted in a realized gain of $224,000 in Q3 2010 and a realized loss of $543,000 in YTD 2010.
FINANCIAL AND OPERATING REVIEW
UPSTREAM NETBACKS ($000)
-------------------------------------------------------------------------
Three months ended September 30, 2010
-------------------------------------------------------------------------
Natural
Oil sands Crude oil gas Total
-------------------------------------------------------------------------
Gross revenues(1) $47,942 $4,721 $2,884 $55,547
-------------------------------------------------------------------------
Diluent purchased(2) (17,250) - - (17,250)
-------------------------------------------------------------------------
Transportation costs (4,154) (16) - (4,170)
-------------------------------------------------------------------------
Production revenue 26,538 4,705 2,884 34,127
-------------------------------------------------------------------------
Royalties (902) (1,240) (135) (2,277)
-------------------------------------------------------------------------
Operating costs (13,086) (1,035) (1,026) (15,147)
-------------------------------------------------------------------------
Netbacks(3) $12,550 $2,430 $1,723 $16,703
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Three months ended September 30, 2009
-------------------------------------------------------------------------
Natural
Oil sands Crude oil gas Total
-------------------------------------------------------------------------
Gross revenues(1) $45,665 $5,642 $2,775 $54,082
-------------------------------------------------------------------------
Diluent purchased(2) (15,317) - - (15,317)
-------------------------------------------------------------------------
Transportation costs (3,050) (105) - (3,155)
-------------------------------------------------------------------------
Production revenue 27,298 5,537 2,775 35,610
-------------------------------------------------------------------------
Royalties (1,088) (1,516) 789 (1,815)
-------------------------------------------------------------------------
Operating costs (10,194) (778) (2,193) (13,165)
-------------------------------------------------------------------------
Netbacks(3) $16,016 $3,243 $1,371 $20,630
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Nine months ended September 30, 2010
-------------------------------------------------------------------------
Natural
Oil sands Crude oil gas Total
-------------------------------------------------------------------------
Gross revenues(1) $147,731 $15,852 $10,309 $173,892
-------------------------------------------------------------------------
Diluent purchased(2) (53,834) - - (53,834)
-------------------------------------------------------------------------
Transportation costs (10,533) (51) - (10,584)
-------------------------------------------------------------------------
Production revenue 83,364 15,801 10,309 109,474
-------------------------------------------------------------------------
Royalties (3,252) (4,126) (102) (7,480)
-------------------------------------------------------------------------
Operating costs (37,897) (3,076) (4,258) (45,231)
-------------------------------------------------------------------------
Netbacks(3) $42,215 $8,599 $5,949 $56,763
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Nine months ended September 30, 2009
-------------------------------------------------------------------------
Natural
Oil sands Crude oil gas Total
-------------------------------------------------------------------------
Gross revenues(1) $114,907 $15,568 $12,112 $142,587
-------------------------------------------------------------------------
Diluent purchased(2) (43,352) - - (43,352)
-------------------------------------------------------------------------
Transportation costs (8,374) (263) - (8,637)
-------------------------------------------------------------------------
Production revenue 63,181 15,305 12,112 90,598
-------------------------------------------------------------------------
Royalties (1,305) (4,010) (710) (6,025)
-------------------------------------------------------------------------
Operating costs (29,985) (3,029) (7,278) (40,292)
-------------------------------------------------------------------------
Netbacks(3) $31,891 $8,266 $4,124 $44,281
-------------------------------------------------------------------------
(1) No bitumen sales have yet been recognized at Algar, as all costs and
incidental revenue are capitalized until such operations are
considered "commercial". Algar commerciality was achieved in October
2010; accordingly, Algar production, revenue, operating costs and
related depletion will be reported in Q4 2010. Bitumen produced at
Pod One is mixed with purchased diluent and sold as "dilbit". Diluent
is a light hydrocarbon that improves the marketing and transportation
quality of bitumen. In the above tables, gross revenues represent
sales of dilbit, crude oil and natural gas. In the financial
statements Upstream Revenues represent sales of dilbit, crude oil and
natural gas, net of royalties and Upstream Operating Costs include
the cost of purchased diluent.
(2) Diluent volumes purchased and blended into dilbit sales have been
deducted in calculating production revenue and production volumes
sold. Diluent purchased includes purchases from our downstream
segment. Although they have been included in these upstream netback
calculations, these intercompany transactions have been eliminated in
our consolidated financial statements.
(3) As illustrated in this table, netbacks are calculated as bitumen,
crude oil and natural gas production revenue before adding/deducting
risk management contracts gains/losses, less royalties and operating
costs. Netbacks on a per-unit basis are calculated by dividing
netbacks by production volumes. Netbacks do not have a standardized
meaning prescribed by GAAP and, therefore, may not be comparable to
similar measures used by other companies. This non-GAAP measurement
is widely used in the oil and gas industry as a supplemental measure
of the company's efficiency and its ability to fund future growth
through capital expenditures. Netbacks are reconciled to net earnings
below.
Upstream Sales And Production Volumes
-------------------------------------------------------------------------
Three months ended Nine months ended
September 30 September 30
-------------------------------------------------------------------------
2010 2009 % Change 2010 2009 % Change
-------------------------------------------------------------------------
Dilbit sales - bbl/d 8,994 8,666 4 8,845 8,571 3
-------------------------------------------------------------------------
Diluent purchased -
bbl/d (2,236) (2,115) 6 (2,210) (2,235) (1)
-------------------------------------------------------------------------
Bitumen produced
and sold - bbl/d 6,758 6,551 3 6,635 6,336 5
-------------------------------------------------------------------------
Crude oil produced
and sold - bbl/d 819 993 (18) 887 1,095 (19)
-------------------------------------------------------------------------
Natural gas produced
and sold - Mcf/d 9,158 10,377 (12) 9,364 11,774 (20)
-------------------------------------------------------------------------
Total - boe/d 9,103 9,274 (2) 9,083 9,394 (3)
-------------------------------------------------------------------------
Upstream Netbacks Per Unit Of Production
-------------------------------------------------------------------------
Three months ended September 30, 2010
-------------------------------------------------------------------------
Natural
Bitumen Crude oil gas Total
($ per bbl) ($ per bbl) ($ per Mcf) ($ per boe)
-------------------------------------------------------------------------
Production revenue $42.68 $62.45 $3.42 $40.74
-------------------------------------------------------------------------
Royalties (1.45) (16.46) (0.16) (2.72)
-------------------------------------------------------------------------
Operating costs (21.05) (13.74) (1.22) (18.08)
-------------------------------------------------------------------------
Netback $20.18 $32.25 $2.04 $19.94
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Three months ended September 30, 2009
-------------------------------------------------------------------------
Natural
Bitumen Crude Oil gas Total
($ per bbl) ($ per bbl) ($ per Mcf) ($ per boe)
-------------------------------------------------------------------------
Production revenue $45.30 $60.58 $2.91 $41.74
-------------------------------------------------------------------------
Royalties (1.81) (16.59) 0.83 (2.13)
-------------------------------------------------------------------------
Operating costs (16.92) (8.51) (2.30) (15.43)
-------------------------------------------------------------------------
Netback $26.57 $35.48 $1.44 $24.18
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Nine months ended September 30, 2010
-------------------------------------------------------------------------
Natural
Bitumen Crude oil gas Total
($ per bbl) ($ per bbl) ($ per Mcf) ($ per boe)
-------------------------------------------------------------------------
Production revenue $46.02 $65.27 $4.03 $44.15
-------------------------------------------------------------------------
Royalties (1.80) (17.04) (0.04) (3.02)
-------------------------------------------------------------------------
Operating costs (20.92) (12.70) (1.66) (18.24)
-------------------------------------------------------------------------
Netback $23.30 $35.53 $2.33 $22.89
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Nine months ended September 30, 2009
-------------------------------------------------------------------------
Natural
Bitumen Crude Oil gas Total
($ per bbl) ($ per bbl) ($ per Mcf) ($ per boe)
-------------------------------------------------------------------------
Production revenue $36.53 $51.20 $3.77 $35.33
-------------------------------------------------------------------------
Royalties (0.75) (13.41) (0.22) (2.35)
-------------------------------------------------------------------------
Operating costs (17.34) (10.13) (2.26) (15.71)
-------------------------------------------------------------------------
Netback $18.44 $27.66 $1.29 $17.27
-------------------------------------------------------------------------
Gross upstream production revenues of $55.5 million in Q3 2010 were three percent higher than gross production revenues of $54.1 million in Q3 2009. The higher revenues were due to higher bitumen production partially offset by lower realized bitumen selling prices and lower crude oil and natural gas production in Q3 2010 compared to Q3 2009. In the latter part of Q3 2010, bitumen pricing was adversely affected by wider heavy oil differentials which were primarily caused by industry-wide pipeline transportation disruptions. We anticipate this will continue to impact our industry through October 2010.
YTD 2010 gross upstream production revenues increased by 22 percent to $173.9 million compared to $142.6 million in YTD 2009. The increase was primarily attributable to higher realized bitumen, crude oil and natural gas pricing, which was slightly offset by lower crude oil and natural gas production and sales volumes in YTD 2010. Lower crude oil and natural gas production and sales volumes in YTD 2010 reflected the impact of reduced development capital spending in 2009 and 2010.
Our Q3 2010 and YTD 2010 upstream results were also impacted by realized and unrealized risk management contract gains and losses. Details of these contracts and the gains and losses on risk management contracts are addressed in "Pricing-Upstream", above.
At Pod One, bitumen production averaged 6,758 bbl/d in Q3 2010 compared to 6,551 bbl/d in Q3 2009. Production was affected by numerous periodic power outages and pump failures in 2010 and operated volume variations reflect minor operational issues, including pump replacements or other manageable operational matters which require temporary individual well shutdowns. Operational reliability at Pod One has improved subsequent to the activation of the cogeneration facility at Algar in early September 2010, which reduced the load on the regional power grid.
Bitumen produced at Pod One is mixed with purchased diluent and sold as "dilbit." Diluent is a light liquid hydrocarbon used in our oil sands treating processes and enables the efficient marketing and transportation of bitumen. Diluent purchased represented approximately 25 percent of the dilbit barrel sold in Q3 2010 and YTD 2010, with bitumen the remaining 75 percent; in Q3 2009, these splits were 24 percent and 76 percent, respectively, whereas in YTD 2009, these splits were 26 percent and 74 percent, respectively. The price of diluent closely tracks WTI crude oil prices. Consequently, diluent costs were higher in 2010 than in 2009.
In Q3 2010, upstream diluent purchases of $17.3 million (Q3 2009 - $15.3 million) were required for our oil sands operations. YTD 2010 upstream diluent purchases were $53.8 million compared to $43.4 million in YTD 2009. These purchases include $2.8 million and $10.5 million of diluent purchased at market prices directly from our subsidiary, MRCI, in Q3 2010 and YTD 2010, respectively (Q3 2009 and YTD 2009 - $2.3 million and $5.7 million, respectively). Although these intercompany costs were included in our netback calculations above to accurately present bitumen netbacks, they were eliminated for consolidated financial statement presentation purposes.
Transportation costs represent costs to transport dilbit and crude oil to customers. Transportation costs were higher in 2010 than 2009 ($4.2 million in Q3 2010 compared to $3.2 million in Q3 2009 and $10.6 million in YTD 2010 compared to $8.6 million in YTD 2009). The overall increase of 32 percent in Q3 2010 compared to Q3 2009 and 23 percent in YTD 2010 compared to YTD 2009 was due to higher trucking costs and an increase in dilbit sales travel distances to markets in 2010. These costs were reported as an expense in our consolidated statement of operations but have been deducted in calculating average realized selling prices.
Royalties represent charges against production or revenue by governments and landowners. From quarter to quarter, royalties can change based on changes in the product mix, the components of which are subject to different royalty rates. Additionally, royalty rates are applied on a sliding scale to commodity prices. Royalties in Q3 2010 and YTD 2010 were $2.3 million and $7.5 million, respectively, compared to $1.8 million and $6.0 million in Q3 2009 and YTD 2009, respectively. The increase in overall royalties was primarily due to higher oil prices. This was generally reflected in higher per unit royalty costs for bitumen and crude oil. The reduction in the 2010 per unit royalty cost for natural gas compared to the 2009 reflected Alberta gas cost allowance recoveries in conjunction with lower natural gas prices.
Operating costs in Q3 2010 of $15.1 million were 15 percent higher than $13.2 million in Q3 2009. Similarly, operating costs in YTD 2010 of $45.2 million were 12 percent higher than $40.3 million in YTD 2009. Bitumen operating costs were $13.1 million ($21.05/bbl of bitumen) in Q3 2010 and $37.9 million ($20.92/bbl of bitumen) in YTD 2010, compared to $10.2 million ($16.92/bbl of bitumen) in Q3 2009 and $30.0 million ($17.34/bbl of bitumen) in YTD 2009, respectively. This represents an increase of 28 percent in Q3 2010 compared to Q3 2009 and an increase of 26 percent in YTD 2010 compared to YTD 2009.
The tables below summarizes Pod One field operating information.
-------------------------------------------------------------------------
Three months ended Nine months ended
September 30 September 30
-------------------------------------------------------------------------
2010 2009 2010 2009
-------------------------------------------------------------------------
(Canadian dollar
in thousands) % % % %
-------------------------------------------------------------------------
Natural gas
costs(1) $3,257 25 $2,510 25 $10,955 29 $9,384 31
-------------------------------------------------------------------------
Other operating
costs 9,829 75 7,684 75 26,945 71 20,601 69
-------------------------------------------------------------------------
Total Pod One
operating costs $13,086 100 $10,194 100 $37,897 100 $29,985 100
-------------------------------------------------------------------------
(1) Excluding risk management contracts gains and losses.
-------------------------------------------------------------------------
Three months ended Nine months ended
September 30 September 30
-------------------------------------------------------------------------
2010 2009 2010 2009
-------------------------------------------------------------------------
Natural gas consumed
-------------------------------------------------------------------------
Volume (Mcf/d) 9,894 9,500 9,602 9,300
-------------------------------------------------------------------------
Cost (per Mcf) $3.58 $2.88 $4.18 $3.69
-------------------------------------------------------------------------
SORs(1) 3.8 3.8 3.7 3.7
-------------------------------------------------------------------------
(1) SORs mean steam:oil ratio.
Pod One bitumen field operating costs were higher in 2010 primarily due to unplanned plant shut downs and start-ups associated with numerous power failures experienced. This also had collateral wear on down-hole pumps necessitating some replacements earlier than anticipated. Natural gas costs at Pod One was higher due to increased production and sale volumes and the higher cost of natural gas. In addition, our natural gas operating costs in the three and nine months period ended September 30, 2010 were also influenced by the following AECO natural gas purchase contracts. The company recorded realized and unrealized losses of $87,000 and $1.2 million, respectively, in the three and nine months ended September 30, 2010 relating to these contracts.
- September 1, 2010 - August 31, 2011 - 4,000 GJ/d at AECO CAD$3.87/GJ;
and
- October 1, 2010 - September 30, 2011 - 4,000 GJ/d at AECO CAD$4.20/GJ.
Our operational startup and production ramp up at Algar continues on trend and at a record rate. We commenced converting wells to full SAGD production in early August 2010 and now have 15 of Algar's 17 well pairs on full SAGD production. At a new SAGD facility such as Algar, the conversion to full SAGD and ramping up of production is a sequential process during approximately the first full year of operation. Currently, our measured volumes of bitumen production are occasionally exceeding 6,000 bbl/d. We do not record these volumes or the related revenues or operating costs in our reported operating results until we have concluded commerciality for the Algar project. In the interim, we record the volumes for royalty purposes and we capitalize sales proceeds, royalties and related operating costs. In early November 2010, we determined that Algar achieved management's threshold for achieving commerciality. Consequently, we will be reporting Algar production, revenue, operating costs and depletion in the fourth quarter 2010.
Connacher announced on September 8, 2010, that its 13.1 megawatt cogeneration ("CoGen") facility at Algar was completed, on-time and on-budget. The plant, which is also capable of generating 3,700 bbl/d of steam at full design rate, was commissioned in late August 2010 and was integrated with the Algar plant in early September 2010 following a short plant outage to facilitate the electrical work. Algar is now islanded from the regional electrical grid. The activation of the Algar CoGen plant will also contribute to increased power reliability at Pod One. It is anticipated that this improved power reliability will minimize the occurrence of, and any potential adverse impact from, grid-related power outages on pump durability and resultant production performance at Pod One. Once a new substation is completed by the local power utility, likely in the first half of 2011, power reliability may be further enhanced, with attendant operational benefits.
Conventional crude oil operating costs, being primarily fixed in nature, were slightly higher in the 2010 reporting periods due to additional expensed workovers; and on a per unit basis they were higher primarily due to lower production volumes in 2010 as noted above.
Natural gas operating costs were lower in the current year reporting periods due to improved operating efficiencies from last year's workovers and on a per unit basis, were also lower notwithstanding lower production volumes.
Total upstream netbacks were 28 percent higher at $56.8 million in YTD 2010 compared to $44.3 million in YTD 2009 and were 33 percent higher on a per unit basis ($22.89/bbl compared to $17.27/bb). This was primarily because our realized bitumen price was 26 percent higher, our crude oil selling price was 27 percent higher and our realized natural gas prices were 7 percent higher. The higher realized bitumen, crude oil prices and natural gas prices were in line with the increase in WTI crude oil and AECO natural gas prices. Total upstream netbacks were 19 percent lower at $16.7 million in Q3 2010 compared to $20.6 million in Q3 2009 because of lower realized bitumen and crude oil pricing and higher operating costs at Pod One as noted above.
RECONCILIATION OF UPSTREAM NETBACKS TO NET EARNINGS
-------------------------------------------------------------------------
Three months ended September 30
-------------------------------------------------------------------------
2010 2009
-------------------------------------------------------------------------
($000, except per unit amounts) Total Per boe Total Per boe
-------------------------------------------------------------------------
Upstream netbacks, as above $16,703 $19.94 $20,630 $24.18
-------------------------------------------------------------------------
Interest and other income 53 0.06 2,189 2.57
-------------------------------------------------------------------------
Downstream margin - net 12,753 15.23 7,699 9.02
-------------------------------------------------------------------------
Gain (loss) on risk
management contracts (7,663) (9.15) 6,442 7.55
-------------------------------------------------------------------------
General and administrative (4,531) (5.41) (3,364) (3.94)
-------------------------------------------------------------------------
Stock-based compensation (795) (0.95) (623) (0.73)
-------------------------------------------------------------------------
Finance charges (13,220) (15.78) (13,127) (15.39)
-------------------------------------------------------------------------
Foreign exchange gain 23,308 27.83 56,344 66.04
-------------------------------------------------------------------------
Depletion, depreciation and
accretion (19,307) (23.05) (16,691) (19.56)
-------------------------------------------------------------------------
Income tax recovery (provision) 1,144 1.37 (6,342) (7.43)
-------------------------------------------------------------------------
Equity interest in Petrolifera
loss (499) (0.60) (2,797) (3.28)
-------------------------------------------------------------------------
Dilution loss - - (2,593) (3.04)
-------------------------------------------------------------------------
Net earnings (loss) $7,946 $9.49 $47,767 $55.99
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Nine months ended September 30
-------------------------------------------------------------------------
2010 2009
-------------------------------------------------------------------------
($000, except per unit amounts) Total Per boe Total Per boe
-------------------------------------------------------------------------
Upstream netbacks, as above $56,763 $22.89 $44,281 $17.27
-------------------------------------------------------------------------
Interest and other income 173 0.07 3,363 1.31
-------------------------------------------------------------------------
Downstream margin - net 18,091 7.30 13,614 5.31
-------------------------------------------------------------------------
Gain (loss) on risk
management contracts 822 0.33 (15,825) (6.17)
-------------------------------------------------------------------------
General and administrative (14,361) (5.79) (11,062) (4.31)
-------------------------------------------------------------------------
Stock-based compensation (3,823) (1.54) (2,444) (0.95)
-------------------------------------------------------------------------
Finance charges (39,171) (15.80) (31,164) (12.15)
-------------------------------------------------------------------------
Foreign exchange gain 14,706 5.93 93,889 36.61
-------------------------------------------------------------------------
Depletion, depreciation and
accretion (55,950) (22.57) (49,678) (19.37)
-------------------------------------------------------------------------
Income tax recovery (provision) 8,505 3.43 166 0.06
-------------------------------------------------------------------------
Equity interest in Petrolifera
loss (1,116) (0.45) (1,658) (0.65)
-------------------------------------------------------------------------
Dilution loss (4,273) (1.72) (2,593) (1.01)
-------------------------------------------------------------------------
Net earnings (loss) $(19,634) $(7.92) $40,889 $15.95
-------------------------------------------------------------------------
DOWNSTREAM REVENUES AND MARGINS
Connacher's 9,500 bbl/d heavy oil refinery, located in Great Falls, Montana (the "Refinery"), is a strategic fit with our oil sands development. It processes Canadian heavy crude oil (similar to Great Divide dilbit) into a range of higher value refined petroleum products, including regular and premium gasoline, jet fuel, diesel and asphalt. Accordingly, the Refinery provides a notional hedge for our bitumen revenues by recovering a portion of the heavy oil differential under normal operating conditions.
The Refinery is complex and includes reforming, isomerization and alkylation processes for formulation of gasoline blends, hydro-treating for sulphur removal and fluid catalytic cracking for conversion of heavy gas oils to gasoline and distillate products. Also, it is a major supplier of paving grade asphalt, polymer modified grades and asphalt emulsions for road construction. The Refinery delivers products in Montana and neighboring regions, including Canada, by truck and rail transport.
The Refinery is subject to a number of seasonal factors which cause product sales revenues to vary throughout the year. The Refinery's primary asphalt market is paving for road construction, which is in greater demand during the summer. Consequently, prices and volumes for our asphalt tend to be higher in the summer and lower in the colder seasons. During the winter, most of the Refinery's asphalt production is stored in tankage for sale in the subsequent summer. Seasonal factors also affect the production and sale of gasoline, which has a higher demand in summer months and the production and sale of diesel, which has a higher winter demand. As a result, inventory levels, sales volumes and prices can be expected to fluctuate on a seasonal basis.
The Refinery operates in a "niche" market that incorporates Western Montana, Northern Idaho, Eastern Washington and Southern Alberta. The market provides some insulation from challenging North American refining market conditions. Unlike other market areas, MRCI's margins significantly improved in Q2 2010 and Q3 2010 because of higher product prices and increased product demand in our market area.
Downstream revenues of $106.2 million in Q3 2010 were 15 percent higher than the $93.0 million of refined products sold in Q3 2009. In Q3 2010 our volumes of refined products sales increased nine percent from the comparative Q3 2009 period and our average realized selling price was up five percent on a per barrel basis. In YTD 2010, downstream revenues were $251.7 million compared to $195.0 million in YTD 2009, an increase of 29 percent, reflecting a sales volume increase of 16 percent and an increase in average product selling prices of 23 percent.
In Q3 2010 asphalt sales of 452,000 barrels represented 39 percent of total refined product sales, compared to 499,000 barrels, or 46 percent in Q3 2009, averaging US$ 84.97/bbl in Q3 2010 and US$ 78.22/ bbl sold in Q3 2009. Sales of asphalt were affected by wetter weather conditions in the current year, but asphalt sales continued into October 2010 with favorable weather. Currently, MRCI has agreements to sell approximately 550,000 additional barrels of asphalt at prices approximating US$100 /bbl.
Current quarter and year-to-date sales volumes were also augmented by marginally higher sales volumes of gasoline, diesel and jet fuel produced at MRCI. Increased refining throughput volumes in 2010 were primarily due to the improved stability of refining operations subsequent to the completion of the ultra low sulphur diesel ("ULSD") project and our triennial plant turnaround in September and October last year.
Downstream revenues and refining margins (in the table below) include the benefit of diluent sales revenue of $2.8 million in Q3 2010 and $10.5 million for the YTD 2010 ($2.3 million - Q3 2009 and $5.7 million - YTD 2009) sold to our upstream oil sands operation, which were transacted at prevailing fair market prices. These transactions were eliminated on consolidation for financial statement presentation purposes.
General economic conditions affect refined product demand and pricing. We anticipate they will continue to influence our downstream financial results in the future. To mitigate some of the risk of reduced gasoline selling prices and margins, the company entered into a risk management sales contract to sell 2,000 bbl/d of gasoline at the calendar month average WTI price in US$/bbl plus US$9.00/bbl for the period of April 1, 2010 to September 30, 2010. The contract expired on September 30, 2010 and resulted in a realized gain of $224,000 in Q3 2010 and a realized loss of $543,000 in YTD 2010.
The quarterly operating results of our Refinery are summarized below.
Refinery Throughput
-------------------------------------------------------------------------
Sept 30, Dec 31, Mar 31, June 30, Sept 30,
2009 2009 2010 2010 2010
-------------------------------------------------------------------------
Crude charged - bbl/d(1) 7,076 8,188 9,347 8,943 9,903
-------------------------------------------------------------------------
Refinery production -
bbl/d(2) 8,131 8,674 10,814 10,546 11,149
-------------------------------------------------------------------------
Sales of produced
refined products -
bbl/d 10,596 8,841 8,267 9,842 12,403
-------------------------------------------------------------------------
Sales of refined
products (includes
purchased products) -
bbl/d(3) 11,697 9,646 8,439 10,076 12,773
-------------------------------------------------------------------------
Refinery utilization(4) 75% 86% 98% 94% 104%
-------------------------------------------------------------------------
(1) Crude charged represents the barrels per day of crude oil processed
at the Refinery.
(2) Refinery production represents the barrels per day of refined
products yielded from processing crude and other refinery feedstock.
(3) Includes refined products purchased for resale.
(4) Represents crude charged divided by total crude capacity of the
Refinery.
Feedstocks
-------------------------------------------------------------------------
Sept 30, Dec 31, Mar 31, June 30, Sept 30,
2009 2009 2010 2010 2010
-------------------------------------------------------------------------
Sour crude oil 91% 97% 87% 86% 92%
-------------------------------------------------------------------------
Other feedstocks & blends 9% 3% 13% 14% 8%
-------------------------------------------------------------------------
Total 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
Revenues And Margins ($000)
-------------------------------------------------------------------------
Sept 30, Dec 31, Mar 31, June 30, Sept 30,
2009 2009 2010 2010 2010
-------------------------------------------------------------------------
Refining sales
revenue(1) $92,714 $63,440 $61,589 $83,988 $106,159
-------------------------------------------------------------------------
Refining - crude oil
and operating costs 85,015 67,491 66,289 73,950 93,406
-------------------------------------------------------------------------
Refining margin $7,699 $(4,051) $(4,700) $10,038 $12,753
-------------------------------------------------------------------------
Refining margin (%) 8% (7%) (8%) 12% 12%
-------------------------------------------------------------------------
(1) Includes intersegment sales which have been eliminated from
consolidated statements of operations.
Revenues And Margins Per Barrel Of Refined Product Sold
-------------------------------------------------------------------------
Sept 30, Dec 31, Mar 31, June 30, Sept 30,
2009 2009 2010 2010 2010
-------------------------------------------------------------------------
Refining sales revenue $86.16 $71.73 $81.09 $91.58 $90.35
-------------------------------------------------------------------------
Refining - crude oil
and operating costs 79.00 76.36 87.28 80.65 79.78
-------------------------------------------------------------------------
Refining margin $7.16 $(4.63) $(6.19) $10.93 $10.57
-------------------------------------------------------------------------
Sales Of Refined Products (Volume %)
-------------------------------------------------------------------------
Sept 30, Dec 31, Mar 31, June 30, Sept 30,
2009 2009 2010 2010 2010
-------------------------------------------------------------------------
Gasoline 36% 39% 51% 45% 37%
-------------------------------------------------------------------------
Diesel fuels 10% 10% 20% 13% 15%
-------------------------------------------------------------------------
Jet fuels 6% 4% 8% 7% 7%
-------------------------------------------------------------------------
Asphalt 46% 45% 17% 32% 39%
-------------------------------------------------------------------------
Other 2% 2% 4% 3% 2%
-------------------------------------------------------------------------
Total 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
INTEREST AND OTHER INCOME
In Q3 2010 and YTD 2010, the company earned interest and other income of $53,000 and $173,000, respectively, (Q3 2009 - $2.2 million and YTD 2009 - $3.4 million), primarily from investing surplus funds in secure short-term investments. A portion of the interest earned was recognized as income and a portion (in respect of cash balances on hand from pre-funding oil sands projects under development) was credited to capitalized costs. Interest and other income in Q3 2009 and YTD 2009 included a gain of $1.8 million and $2.3 million, respectively, on the repurchase of Second Senior Lien Notes. No similar repurchases were made in 2010.
GENERAL AND ADMINISTRATIVE EXPENSES
In Q3 2010, general and administrative ("G&A") expenses were $4.5 million, compared to $3.4 million in Q3 2009, an increase of 35 percent and $14.4 million in YTD 2010 compared to $11.1 million in YTD 2009, an increase of 30 percent. The increase primarily reflected additional staffing to support corporate growth. G&A of $1.3 million in Q3 2010 and $4.6 million in YTD 2010 was also capitalized (Q3 2009 - $1.1 million and YTD 2009 - $3.7 million).
FINANCE CHARGES
Finance charges include interest expense relating to the Convertible Debentures, standby fees associated with the company's Revolving Credit Facility, fees on letters of credit issued and a portion of the First and Second Lien Senior Notes interest not attributable to major development/capital projects. Finance charges also include non-cash accretion charges with respect to the Convertible Debentures and a portion of the First and Second Lien Senior Notes. The company capitalizes interest on a portion of its long-term debt raised to finance oil sands projects.
In Q3 2010, finance charges expensed were $13.2 million, which was slightly higher than $13.1 million in Q3 2009 and in YTD 2010, finance charges expensed were $39.2 million, which was $8 million higher than in YTD 2009. The higher finance charges were primarily a result of higher debt levels since issuing the First Lien Senior Notes in mid June 2009. Connacher capitalized finance charges of $12.9 million in Q3 2010 (Q3 2009 - $13.3 million) and $38.3 million in YTD 2010 (YTD 2009 - $39.4 million) in respect of oil sands activities.
STOCK-BASED COMPENSATION
The company recorded non-cash stock-based compensation charges in the respective periods as follows:
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Three months ended Nine months ended
September 30 September 30
-------------------------------------------------------------------------
($000) 2010 2009 2010 2009
-------------------------------------------------------------------------
Charged to expense $795 $623 $3,823 $2,444
-------------------------------------------------------------------------
Capitalized to property,
plant and equipment 396 162 1,582 669
-------------------------------------------------------------------------
Total $1,191 $785 $5,405 $3,113
-------------------------------------------------------------------------
The increase from the prior period is due to a higher fair market value for options granted in 2010.
FOREIGN EXCHANGE GAINS
In Q3 2010 and YTD 2010, the value of the Canadian dollar strengthened relative to the U.S. dollar. This had a significant impact on Connacher upon translating its U.S. dollar denominated long-term debt and U.S. dollar cash balances into Canadian dollars for financial reporting purposes.
Connacher had an unrealized foreign exchange gain of $23.1 million in Q3 2010 (Q3 2009 - $53.5 million) and $13.2 million in YTD 2010 (YTD 2009 - $87.1 million). Connacher also realized foreign exchange gains of $193,000 in Q3 2010 (Q3 2009 - $2.9 million) and $1.5 million in YTD 2010 (YTD 2009 - $6.8 million) upon the settlement of foreign currency denominated transactions.
DEPLETION, DEPRECIATION AND ACCRETION ("DD&A")
Depletion expense is calculated using the unit-of-production method based on total estimated proved reserves. Downstream refining properties and other assets are depreciated over their estimated useful lives. DD&A in Q3 2010 and YTD 2010 was $19.3 million and $56.0 million, respectively (Q3 2009 - $16.7 million and YTD 2009 - $49.7 million). Depletion of $15.4 million in Q3 2010 (Q3 2009 - $13.9 million) equated to $18.40/boe of production ($16.35/boe in Q3 2009). In YTD 2010, depletion was $44.6 million ($18.00/boe) compared to $41.8 million in YTD 2009 ($16.30/boe). The increase in depletion rate per boe of production was due to the increase in current and estimated future capital expenditures related to our increased proved reserves.
Future development costs of $1.6 billion (Q3 2009 - $1.3 billion) were included in the depletion calculation while capital costs of $722 million (Q3 2009 - $452 million) related to major development oil sands projects and undeveloped land costs of $12.0 million (Q3 2009 - $12.3 million) were excluded from the depletion calculation.
Included in DD&A for Q3 2010 was MRCI refinery depreciation of $2.6 million (Q3 2009 - $1.8 million), depreciation of furniture, equipment and leaseholds of $524,000 (Q3 2009 - $324,000) and an accretion charge of $744,000 (Q3 2009 - $592,000) in respect of the company's estimated asset retirement obligations ("ARO"). In YTD 2010, DD&A included, MRCI refinery deprecation of $7.5 million (YTD 2009 - $5.5 million), depreciation of furniture, equipment and leaseholds of $1.7 million (YTD 2009 - $800,000) and an accretion charge of $2.2 million in respect of ARO (YTD 2009 - $1.6 million). These ARO charges will continue in future years in order to accrete the currently booked discounted liability of $38.5 million to the estimated total undiscounted liability of $86.7 million over the remaining economic life of the company's oil sands, crude oil and natural gas properties.
INCOME TAXES
The total income tax recovery of $1.1 million in Q3 2010 and $8.5 million in YTD 2010 (Q3 2009 - income tax provision of $6.3 million and YTD 2009 - income tax recovery of $0.2 million) included a current income tax recovery of $994,000 in Q3 2010 and $638,000 in YTD 2010 (Q3 2009 - $2.1 million and YTD 2009 - $1.8 million), principally related to taxes refundable by MRCI. The future income tax recovery of $150,000 in Q3 2010 and $7.9 million in YTD 2010 (Q3 2009 - future income tax provision of $8.4 million and YTD 2009 -$1.6 million) reflected the change in tax pools during the periods.
EQUITY INTEREST IN PETROLIFERA PETROLEUM LIMITED ("PETROLIFERA")
Connacher accounts for its equity investment in Petrolifera under the equity method of accounting. Connacher's share of Petrolifera's loss in Q3 2010 was $499,000 (Q3 2009 - $2.8 million) and in YTD 2010 was a $1.1 million (YTD 2009 - $1.7 million).
In April 2010, Petrolifera closed a public offering of 23,678,500 common shares at a price of $0.85 per common share for gross proceeds of $20.1 million (the "Offering"). The company did not subscribe for shares in the Offering and accordingly, the company's equity interest in Petrolifera was reduced to 18.5 percent from 22 percent. The reduction in the ownership interest resulted in a dilution loss of $4.2 million in the nine months ended September 30, 2010. Given Connacher's representation on Petrolifera's Board of Directors and other factors, Connacher continues to equity account for this investment.
NET EARNINGS (LOSS)
In Q3 2010, the company reported net earnings of $7.9 million ($0.02 per basic and diluted shares outstanding) compared to $47.8 million ($0.12 per basic and $0.11 per diluted shares outstanding) in Q3 2009. For the YTD 2010, the company reported a net loss of $19.6 million ($0.05 per basic and diluted shares outstanding) compared to net earnings of $40.9 million ($0.14 per basic and diluted shares outstanding) in YTD 2009. The primary variant to these results related to unrealized foreign exchange gains as noted above.
SHARES OUTSTANDING
In Q3 2010, the basic and diluted weighted average number of common shares outstanding was 429.1 million and 431.5 million respectively, (Q3 2009 - 403.6 million basic and 424.1 million diluted). The increase from the prior year was due to the equity issuances late in 2009.
As at November 8, 2010, the company had the following securities issued and outstanding.
- 446,934,343 common shares;
- 25,657,365 share purchase options; and
- 380,598 share units under the share award plan.
Additionally, the company's $100 million of outstanding Convertible Debentures are convertible into 20,002,800 common shares of the company.
PROPERTY AND EQUIPMENT EXPENDITURES
Capital expenditures incurred are presented below.
-------------------------------------------------------------------------
Three months ended Nine months ended
September 30 September 30
-------------------------------------------------------------------------
($000) 2010 2009 2010 2009
-------------------------------------------------------------------------
Crude oil, natural gas and oil
sands expenditures $47,961 $92,207 $223,151 $189,930
-------------------------------------------------------------------------
Refinery expenditures 1,881 8,520 4,279 15,288
-------------------------------------------------------------------------
$49,842 $100,727 $227,430 $205,218
-------------------------------------------------------------------------
-------------------------------------------------------------------------
In Q3 2010, expenditures of $4 million were incurred on the Algar project; $10 million was incurred at Pod One for facility enhancement expenditures and to expand the trucking terminal; $8 million of capital expenditures were incurred for the CoGen plant construction, pipeline facilities and for environment impact assessment ("EIA") work for the Great Divide expansion project; $17 million was capitalized for interest, G&A and other costs; $8 million was incurred in conventional operations including land acquisitions and facility enhancements at Battrum; $2 million was incurred at the refinery; and $1 million of non-cash expenditures were recorded.
For the YTD 2010, expenditures of $69 million were incurred on the Algar project; $28 million was incurred on Pod One to finish the drilling and completion of two additional SAGD well pairs, to add down hole pumps, to expand the trucking terminal and for other facility enhancement expenditures; $24 million in exploration expenditures were incurred primarily to drill 68 exploratory core holes at Great Divide, 13 (6.5 net) exploratory core holes at Halfway Creek and for seismic expenditures related to the 2010 winter exploration program; $24 million of capital expenditures were incurred for co-generation, pipeline facilities and the Great Divide expansion project and $51 million was capitalized for interest, G&A and other costs. Additionally, $16 million was incurred on conventional drilling (one oil well, four natural gas wells and four abandoned wells), land acquisitions, seismic, well workovers, facilities and corporate and administrative assets, $4 million was incurred at the refinery for various projects and $11 million in non-cash expenditures, such as asset retirement costs, were recorded.
In Q3 2009, oil sands capital expenditures totaled $90 million; $57 million of this was incurred on the Algar oil sands project; $6 million of capital costs were incurred at Pod One for the completion of the two additional SAGD well pairs, for costs to install one ESP, the plant turnaround and for other facility enhancement expenditures, and $27 million was incurred on co-generation facilities, transfer pipeline facilities, for capitalized interest and G&A costs and for asset retirement expenditures. In Q3 2009, $2 million was also incurred for conventional facility expenditures.
In YTD 2009, expenditures of $89 million were incurred on the Algar project; $24 million was incurred at Pod One to drill and complete the additional SAGD well pairs and to install five ESPs, for the plant turnaround and for other facility enhancement expenditures and $69 million was incurred on drilling 23 exploratory core holes, for co-generation and pipeline facilities, for capitalized interest and for G&A costs. For the YTD 2009, $8 million was also incurred on conventional drilling (two wells), land acquisitions, seismic, well workovers and facilities.
The 2009 refinery capital expenditures were primarily directed to the completion and tie-in of our new hydrogen plant to complete the ultra-low sulphur diesel project and related to the turnaround and scheduled replacement of the fluid cat cracker reactor.
RECENT FINANCINGS
Common Share Issuance
On June 5, 2009 Connacher issued 191,762,500 common shares from treasury at a price of $0.90 per common share, for gross proceeds of $173 million. The proceeds were raised for working capital to fund the company's capital expenditures, including Algar and for general corporate purposes.
At September 30, 2010, the proceeds had been fully utilized to fund capital expenditures, including oil sands capital costs.
First Lien Senior Secured Notes
On June 16, 2009, the company issued US$200 million first lien five-year secured notes ("First Lien Senior Notes") at an issue price of 93.678 percent for gross proceeds of $212 million in equivalent Canadian funds. These financing proceeds were raised for working capital and general corporate purposes, including funding a portion of the remaining expenditures associated with the construction and drilling costs of Algar.
At September 30, 2010, the proceeds had been utilized to fund capital expenditures primarily related to Algar. Construction of Algar was completed in August 2010.
Flow-Through Shares
In October 2009, to fund the company's 2010 exploration program, the company issued 23,172,500 common shares on a flow-through basis at $1.30 per common share, for gross proceeds of $30.1 million. At September 30, 2010, proceeds of $26 million of the flow-through financing had been utilized for the exploration program and the balance of the proceeds was included in cash balances and will be utilized for additional qualified expenditures prior to December 31, 2010. The company renounced the income tax benefits of these expenditures ($30.1 million) to the subscribing investors, effective December 31, 2009.
In October 2010, to fund the company's 2011 exploration program, the company issued 17,480,0000 common shares on a flow-through basis at $1.45 per common share, for gross proceeds of $25.3 million.
Revolving Credit Facilities
In November 2009, the company successfully arranged a US$50 million Revolving Credit Facility. The two year facility is available for general corporate purposes and was provided by a syndicate of Canadian and international banks. The Revolving Credit Facility provides Connacher with additional liquidity and financial flexibility. It also facilitates the issuance of letters of credit and the conduct of hedging activities. The Revolving Credit Facility is secured by a first priority security interest in all present and after-acquired assets of Connacher, except Connacher's investment in Petrolifera and the pipeline assets of an inactive subsidiary. As arranged when Connacher issued its First Lien Senior Notes earlier in 2009, the Revolving Credit Facility ranks senior to all of Connacher's indebtedness, The Revolving Credit Facility has certain financial covenants, as is customary for this type of credit. As at September 30, 2010, Connacher was in compliance with all its debt covenants.
At September 30, 2010, $5.7 million of letters of credit were issued in the course of normal business activities pursuant to the Revolving Credit Facility.
LIQUIDITY AND CAPITAL RESOURCES
At September 30, 2010, the company had working capital of $61.5 million (December 31, 2009 - $245 million), including $51.1 million of cash (December 31, 2009 - $257 million). As there are limited outstanding capital expenditures commitments and as all of the company's indebtedness is long-term in nature, with no principal repayment obligation until June 2012, management believes that the company presently has sufficient liquidity and financial capacity to fund its ongoing capital program and to satisfy its financial obligations.
In light of the volatility of current commodity prices and the U.S.:Canadian dollar exchange rate and their significance to the company's operating performance, management constantly assesses alternative hedging strategies to protect the company's cash flow from the risk of potentially lower crude oil and refined product pricing and adverse foreign exchange rate fluctuations. Although the company's integrated business model provides some risk mitigation, it does not provide a perfect hedge, particularly against commodity price volatility. The purpose of any hedging activity we undertake is to ensure more predictable cash flow availability to supplement cash balances. This allows us to continue to service indebtedness, complete capital projects and protect the credit capacity of Connacher's oil and gas reserves in an uncertain and volatile commodity price environment.
In 2010, the company entered into WTI risk management contracts on a portion of its anticipated crude oil sales and a portion of its anticipated refined gasoline sales and AECO risk management contracts on a portion of its natural gas consumption requirements. Details of the outstanding risk management contracts are provided earlier in this MD&A.
In Q3 2010, Connacher generated cash flow of $15.2 million ($0.04 per basic and diluted share outstanding) compared to $10.4 million ($0.03 per basic and diluted share outstanding) in Q3 2009. In YTD 2010, cash inflow was $27.8 million ($0.06 per basic and diluted share outstanding) compared to $15.3 million ($0.05 per basic and diluted share outstanding) in YTD 2009.
Cash flow and cash flow per share do not have standardized meanings prescribed by GAAP and therefore may not be comparable to similar measures used by other companies. Cash flow includes all cash flow from operating activities and is calculated before changes in non-cash working capital, pension funding and asset retirement expenditures. The most comparable measure calculated in accordance with GAAP is cash flow from operating activities. Cash flow from operating activities is reconciled with cash flow for three and nine months ended September 30, 2010 and 2009 as follows.
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Three months ended Nine months ended
September 30 September 30
-------------------------------------------------------------------------
($000) 2010 2009 2010 2009
-------------------------------------------------------------------------
Cash flow $15,178 $10,410 $27,794 $15,288
-------------------------------------------------------------------------
Non-cash working capital
changes 21,262 25,074 10,216 (25,594)
-------------------------------------------------------------------------
Asset retirement expenditures (39) (23) (507) (156)
-------------------------------------------------------------------------
Pension funding (517) - (517) (234)
-------------------------------------------------------------------------
Cash flow from operating
activities $35,884 $35,461 $36,986 $(10,696)
-------------------------------------------------------------------------
Cash flow per share is calculated by dividing cash flow by the calculated weighted average number of shares outstanding. Management uses this non-GAAP measurement (which is a common industry parameter) for its own performance measure and to provide its shareholders and investors with a measurement of the company's efficiency and its ability to fund future growth expenditures.
Connacher's objectives in managing its cash, debt and equity and its future capital requirements are to safeguard its ability to meet its financial obligations, to maintain a flexible capital structure that allows multiple financing options when a financing need arises and to optimize its use of short-term and long-term debt and equity at an appropriate level of risk. The company manages its capital structure and follows a financial strategy that considers economic and industry conditions, the risk characteristics of its underlying assets and its growth opportunities. It strives to continuously improve its credit rating and reduce its cost of capital. Connacher monitors its capital structure using a number of financial ratios and industry metrics to ensure its objectives are being met and to ensure continued compliance with financial covenants. Connacher's capital structure and certain financial ratios are noted below.
-------------------------------------------------------------------------
September 30, December 31,
(Canadian dollar in thousands) 2010 2009
-------------------------------------------------------------------------
Long term debt(1) $867,650 $876,181
-------------------------------------------------------------------------
Shareholders' equity 648,543 671,588
-------------------------------------------------------------------------
Total Debt plus Equity ("capitalization") $1,516,193 $1,547,769
-------------------------------------------------------------------------
Debt to book capitalization(2) 57% 57%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Debt to market capitalization(3) 63% 62%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Long-term debt is stated at its carrying value, which is net of
transaction costs and the Convertible Debentures' equity component
value.
(2) Calculated as long-term debt divided by the book value of
shareholders' equity plus long-term debt.
(3) Calculated as long-term debt divided by the period end market value
of shareholders' equity plus long-term debt.
As at September 30, 2010, the company's net debt (long-term debt, net of cash on hand) was $816.5 million. Its net debt to book capitalization was 54 percent and its net debt to market capitalization was 59 percent. The company reported the following debt outstanding.
-------------------------------------------------------------------------
September 30, December 31,
(Canadian dollar in thousands) 2010 2009
-------------------------------------------------------------------------
First Lien Senior Notes, 11 3/4%, due
July 15, 2014 $189,911 $191,509
-------------------------------------------------------------------------
Second Lien Senior Notes, 10 1/4%, due
December 15, 2015 586,071 596,184
-------------------------------------------------------------------------
Convertible Debentures, 4 3/4%, due
June 30, 2012 91,668 88,488
-------------------------------------------------------------------------
Total - no current maturities $867,650 $876,181
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-------------------------------------------------------------------------
OUTLOOK
We expect stronger financial results in 2010 compared to 2009, due to anticipated operating performance at Pod One and the commencement of production at Algar; higher and more stabilized commodity prices (supported by our hedging program) and due to contributions from our refining operations. Current cash balances, together with available unused revolving lines of banking credit and positive full year upstream netbacks and downstream margins, are anticipated to be sufficient to meet all our budgeted capital expenditures and ongoing financial obligations throughout 2010. Based on year-to-date expenditures and current development plans, the company's full year 2010 revised cash capital budget has been increased from $233 million to $240 million.
Details of budgeted 2010 capital expenditures are as follows:
-------------------------------------------------------------------------
(Canadian dollar in millions)
-------------------------------------------------------------------------
Complete Algar $71
-------------------------------------------------------------------------
Algar capitalized interest, G&A and other costs 51
-------------------------------------------------------------------------
Cogeneration and sales transfer lines 23
-------------------------------------------------------------------------
Pod One, including two new SAGD wells, ESPs/PC pumps, trucking
terminal expansion and facility optimization 30
-------------------------------------------------------------------------
EIA application 2
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Exploration program 29
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Conventional and head office capital 24
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Refinery 10
-------------------------------------------------------------------------
$240
-------------------------------------------------------------------------
-------------------------------------------------------------------------
We have examined the merits of rationalizing our conventional property base, to the extent these properties have matured, do not serve the same purpose as when secured, or do not offer the same growth possibilities of other less-developed assets in our inventory of conventional assets. As a result, we have initiated a sales process for our Battrum oil property and Marten Creek natural gas properties. Proceeds from such rationalization would be redeployed in our oil sands and conventional business activity. We do not anticipate any additional financing activity during the balance of 2010 or in 2011, with the possible exception of renegotiating our existing bank credit facility to extend term and reduce costs, in keeping with market conditions. All of our debt is long-term, with first maturity in 2012 and remaining maturities in 2014 and 2015. We will monitor the long-term debt market for advantageous refinancing alternatives, when permitted by existing call provisions and maturities and provided price and term alternatives currently extant in the public debt market remain favorable. Our focus in 2011 will be on optimizing our production at Great Divide, rationalizing our conventional assets and delivering successive and sustained improvement in operating and financial results at low cost.
Future cash flows will be substantially sheltered from current cash taxes by the company's tax pools, which currently exceed $1.2 billion and which will be augmented by future capital expenditures.
ESTIMATED 2010 NETBACKS AND ADJUSTED EBITDA
In our 2009 MD&A as contained in our annual report and as filed separately on SEDAR, we provided guidance with regard to Connacher's estimated 2010 adjusted EBITDA per barrel of bitumen produced and sold. We updated that guidance in our Q2 2010 MD&A (the "Q2 2010 estimate"). Estimated 2010 adjusted EBITDA is calculated on an annual basis and, consequently, quarterly adjusted EBITDA per barrel of bitumen sold will vary from the average annual adjusted EBITDA. The table below compares the company's consolidated results for the nine months ended September 30, 2010 ("YTD 2010") to those annual estimates. Explanations for variances are provided below the table.
The table below also contains a revised estimate (the "revised estimate") for full year 2010 adjusted EBITDA per barrel of bitumen produced and sold based on actual results to September 30, 2010 and revised assumptions, reflecting current industry and market information, for the remaining quarter of 2010. An explanation of the revised assumptions is provided under the tables below.
-------------------------------------------------------------------------
Estimated Full Year 2010
Adjusted EBITDA
-------------------------------------------------------------------------
YTD 2010
Actual Results Q2 2010 Estimate Revised Estimate
-------------------------------------------------------------------------
$/bbl of Total ($ $/bbl of Total ($ $/bbl of Total ($
bitumen millions) bitumen millions) bitumen millions)
-------------------------------------------------------------------------
Bitumen
netback $23.30 $42 $27.85 $91 $21.42 $66
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Conventional
netback 8.03 15 6.00 20 6.01 19
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Refining
netback 9.99 18 6.05 20 8.88 27
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Loss on risk
management
contracts (0.39) (1) (0.10) (0) (0.79) (2)
-------------------------------------------------------------------------
Corporate
netback 40.93 74 39.80 131 35.52 110
-------------------------------------------------------------------------
Corporate G&A (7.93) (14) (5.73) (19) (6.21) (19)
-------------------------------------------------------------------------
Adjusted
EBITDA $33.00 $60 $34.07 $112 $29.31 $91
-------------------------------------------------------------------------
-------------------------------------------------------------------------
YTD 2010 adjusted EBITDA of $60 million was $10 million less than the Q2 2010 estimate for the same period for the reasons cited below.
The YTD 2010 bitumen netback of $42 million was $7 million below the Q2 2010 estimate for the same period. The lower bitumen netback was due primarily to wider heavy oil differentials and higher dilbit transportation costs resulting from disruptions of the Enbridge pipeline system and higher than anticipated operating and diluent transportation costs. YTD 2010 actual daily bitumen production and sales volumes were in line with the Q2 2010 estimate for the same period.
The YTD 2010 conventional netback of $15 million was in line with the Q2 2010 estimate for the same period.
The YTD 2010 refining margin or netback of $18 million was $3 million lower than the Q2 2010 estimate for this period as poor weather affected road paving conditions in Q3 2010 resulting in lower than anticipated asphalt volumes being sold during the period. Additionally, the benefit to downstream margins from wider heavy oil differentials and higher selling prices for diesel and jet fuel were offset by lower than anticipated selling prices for gasoline and asphalt.
YTD 2010 realized losses on risk management contracts of $1 million were in line with the Q2 2010 estimate for the same period.
YTD 2010 Corporate G&A of $14 million was in line with the Q2 2010 estimate for the same period.
The following table reconciles actual YTD 2010 adjusted EBITDA per barrel of bitumen produced and in total to YTD 2010 net loss.
-------------------------------------------------------------------------
$/bbl of bitumen Total ($ in millions)
-------------------------------------------------------------------------
Adjusted EBITDA $33.00 $60
-------------------------------------------------------------------------
Interest and other income 0.10 -
-------------------------------------------------------------------------
Unrealized gain on risk
management contracts 0.84 2
-------------------------------------------------------------------------
Stock-based compensation (2.11) (4)
-------------------------------------------------------------------------
Finance charges (21.63) (39)
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Foreign exchange gain 8.12 15
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Depletion, depreciation
and accretion (30.89) (56)
-------------------------------------------------------------------------
Income tax recovery 4.70 9
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Equity interest in Petrolifera loss (0.62) (1)
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Dilution loss (2.36) (5)
-------------------------------------------------------------------------
Net loss $(10.84) $(19)
-------------------------------------------------------------------------
The following tables are calculated on an annualized basis and may not be reflective of actual quarterly netbacks or adjusted EBITDA. Volatility in quarterly netbacks and adjusted EBITDA will occur due to, among other things, seasonality factors affecting our operations, especially in our refining operations. The following tables do not reflect any changes which may result from the proposed rationalization of the company's conventional property base, given the present stage of examination of these alternatives. Estimated 2010 bitumen netbacks and 2010 adjusted EBITDA constitute forward-looking information. See "Forward-Looking Information" and "Risk Factors" sections in this MD&A and in our AIF. The key assumptions relating to the 2010 outlook are set out in the notes following the tables below. The revised estimated full year 2010 bitumen netback and full year 2010 adjusted EBITDA reflected below include actual results for YTD 2010 and forecast results for the balance of 2010. The revised estimated full year bitumen netback and full year 2010 adjusted EBITDA will form the basis of comparison for future reporting periods.
The full year 2010 bitumen production and sales estimate for Pod One has been reduced from 7,200 bbl/d, as reported in our Q2 2010 estimate, to 6,800 bbl/d. Pod One's forecast 2010 exit production rate has been reduced from between 8,500 bbl/d - 9,000 bbl/d to between 7,500 bbl/d and 8,000 bbl/d. While the reliability of plant operations and downhole pumps have improved substantially compared to the second quarter of 2010, the ramp up of production at Pod One since the second quarter to date has been slower than that anticipated in the Q2 2010 estimate. As has been previously reported, our northern five wells are not as productive as our wells in the eastern and southern portion of Pod One. We are continuing with efforts to increase production from these northern wells, including future plans for the co-injection of methane with steam. The objective of the co-injection project is to reduce SORs, maintain or enhance production from these wells and use available steam on higher productivity wells to further enhance Pod One production. In the southern portion of the reservoir, there is evidence of a lower oil saturation lean zone which also exhibits lower pressure. As a result, even though our wells are on pump, it appears they will operate at a modestly lower production rate than previously forecast. Regardless, our average production in Pod One continues to improve with stable plant operations and with continued downhole and surface optimizations.
The full year 2010 or annualizing bitumen average daily production and sales estimate for Algar has been reduced from 1,800 bbl/d, as reported in our Q2 2010 estimate, to 1,650 bbl/d. The expected range of Algar's forecast 2010 exit production rate has been increased from between 7,000 bbl/d and 7,500 bbl/d to between 7,000 bbl/d and 8,000 bbl/d. The lower average annualized production estimate reflects the impact of longer than expected downtime experienced during planned well workovers conducted in the third quarter of 2010. The company recently completed brief workovers on selected well pairs at Algar to optimize steam injection and production from the middle of the well bores, in addition to the heel and toe of the well bores, a design innovation relative to Pod One. During this short time, our ramp up at Algar was temporarily flattened. Ramp up of total steam and fluid rates is now continuing as steam injection has been improved and as the steam chambers develop. The higher exit range reflects the potential of the Algar reservoir to accept higher levels of steam than originally estimated.
On a combined basis, the full year 2010 bitumen production and sales estimate has been reduced from 9,000 bbl/d, as reported in our Q2 2010 estimate, to 8,450 bbl/d. The combined forecast exit production rate for 2010 has been reduced from between 15,500 bbl/d and 16,500 bbl/d to between 14,500 bbl/d and 16,000 bbl/d.
Revised Estimated Full Year 2010 Bitumen Netback(1)
-------------------------------------------------------------------------
Total $/bbl of bitumen
-------------------------------------------------------------------------
Bitumen price at wellhead (2)(3) $42.67
-------------------------------------------------------------------------
Royalties(4) (1.75)
-------------------------------------------------------------------------
Operating costs
-------------------------------------------------------------------------
Natural gas(5) (5.43)
-------------------------------------------------------------------------
Other operating costs(6) (14.07)
-------------------------------------------------------------------------
Bitumen netback $21.42
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Assumes estimated total average daily bitumen production of
8,450 bbl/d in 2010; 6,800 bbl/d from Pod One and 1,650 bbl/d from
Algar and has not been adjusted for inflation. See "Forward-Looking
Information" and "Risk Factors" sections of our AIF. Production from
Algar assumes commerciality is achieved on October 1, 2010 and has
been annualized for calendar 2010.
(2) Based on average full year WTI price of US$79.00/bbl, a heavy oil
differential of US$13.65/bbl (average of 17 percent) and a quality
charge of US$6.83/bbl, resulting in a dilbit price of $60.28/bbl for
Pod One. Based on an average Q4 2010 WTI price of US$83.00/bbl, a
heavy oil differential of US$18.00/bbl (average of 22 percent) and a
quality charge of US$7.00/bbl, resulting in a dilbit price of
$58.00/bbl for Algar. Also assumes a full year average foreign
exchange rate of $1.03: US$1.00 and a Q4 2010 average foreign
exchange rate of $1.00:US$1.00.
(3) The assumed bitumen price at the wellhead of $44.35/bbl for Pod One
and $35.73/bbl for Algar is net of dilbit transportation costs of
$6.14/bbl of bitumen and assumed diluent blending cost of $29.86/bbl
of bitumen ($22.40/bbl of dilbit), including $1.87/bbl of bitumen of
diluent transportation costs ($5.61/bbl of diluent), a 4.0 percent
average diluent premium to WTI and a blending ratio of 25 percent
for Pod One; and a diluent blending cost of $42.37/bbl of bitumen
($28.87/bbl of dilbit), including $2.81/bbl of bitumen of diluent
transportation costs, ($6.00/bbl of diluent), a two percent average
diluent premium to WTI and a blending ratio of 32 percent for Algar.
(4) Royalties are calculated on a pre-payout basis and are estimated to
be $1.79/bbl for Pod One and $1.59/bbl for Algar.
(5) Based on an average SOR of 3.8 for Pod One and 3.7 for Algar and a
natural gas price of US$3.72/Mcf, which equates to $5.64/bbl or
approximately 10 MMcf/d of natural gas burned to produce 6,800 bbl/d
of bitumen at Pod One and a natural gas price of US $3.25/Mcf, which
equates to $4.55/bbl or approximately 2.3 MMcf/d of natural gas
burned to produce 1,650 bbl/d of bitumen at Algar. The SORs for Pod
One are a conservative estimate reflecting the impact of higher SORs
experienced to date. The SORs from Algar reflect the relative infancy
of the SAGD well pairs and are expected to trend downwards as the
wells are optimized and as ESPs are added.
(6) Assumes $14.75/bbl of non-natural gas operating costs for Pod One
and $11.23/bbl of non-natural gas operating costs at Algar. Higher
Pod One non-natural gas operating costs compared to the Q2 2010
estimate is due primarily to costs of continued production
optimization efforts.
Estimated Full Year 2010 Adjusted EBITDA(1)
-------------------------------------------------------------------------
Total $/bbl of bitumen Total ($millions)
-------------------------------------------------------------------------
Corporate netback contribution
-------------------------------------------------------------------------
Bitumen netback(2) $21.42 $66
-------------------------------------------------------------------------
Conventional netback(3) 6.01 19
-------------------------------------------------------------------------
Refining(4) 8.88 27
-------------------------------------------------------------------------
Loss on risk management contracts(5) (0.79) (2)
-------------------------------------------------------------------------
Corporate netback 35.52 110
-------------------------------------------------------------------------
Corporate G&A(6) (6.21) (19)
-------------------------------------------------------------------------
Adjusted EBITDA $29.31 $91
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Assumes estimated total average daily bitumen production of
8,450 bb/d in 2010; 6,800 bbl/d from Pod One and 1,650 bbl/d from
Algar and has not been adjusted for inflation. Also assumes an
average foreign exchange rate of $1.03=US$1.00.
(2) See the table above for assumptions.
(3) Assumes estimated production of 900 bbl/d of conventional crude oil
and 9 MMcf/d of natural gas production, based upon ownership of the
existing conventional property base throughout 2010. Conventional
oil assets anticipated revenue based on average realized oil price
of US$64.53/bbl and natural gas assets revenue based on average
realized natural gas price of US$3.75/Mcf. Conventional asset netback
is based on 17 percent average royalty rate and average operating
costs of $11.37/boe.
(4) Assumes estimated refinery crude charged of 9,430 bbl/d, feedstock
purchased at US$76.80/bbl, refined products sold with a spread of
US$14.50/bbl to the full year average WTI estimate of US$79.00/bbl
and operating costs of US$8.90/bbl, implying a refining margin of
US$7.80/bbl of crude charged. The higher refining netback compared
to the Q2 2010 estimate reflects widening heavy oil differentials
and stronger than anticipated full year 2010 asphalt sales results.
(5) Anticipated net cost from a US$78.00/bbl WTI swap on 2,500 bbl/d of
bitumen production for calendar 2010, a US$79.02/bbl WTI swap on
2,500 bbl/d of bitumen production from February to April 2010, a
US$9.00/bbl spread to WTI swap on 2,000 bbl/d of gasoline from April
to September 2010, a $4.20/GJ natural gas swap on 4,000 GJ/d for Q4
2010 and a $3.87/GJ natural gas swap on 4,000 GJ/d for Q4 2010.
(6) Excludes capitalized G&A of $1.25/bbl of bitumen.
The company estimates that the impact of the Enbridge pipelines disruptions for the full year 2010, as reflected in its Revised Estimated Full Year 2010 Adjusted EBITDA, will result in a $13 million negative impact on bitumen netbacks and a $6 million positive impact on Refining netback.
Actual netbacks and adjusted EBITDA achieved during 2010 could differ materially from the estimates contained in our 2010 outlook. The material risk factors that we have identified toward achieving these future netbacks and adjusted EBITDA are outlined in the "Risk Factors" and "Forward-Looking Information" sections of our 2009 annual MD&A and in our AIF and include, without limitation, difficulties or interruptions and additional costs during the production of bitumen, crude oil and natural gas; we may encounter timing difficulties or delays and additional costs relating to the steaming or start-up of the Algar project; we may experience difficulties in delivering diluent to our oil sands projects and dilbit to commercial markets; the performance and availability of facilities owned by third parties may adversely affect our operations; crude oil and natural gas prices may fluctuate from current estimates; there may be changes in refining spreads to WTI and changes in the differential pricing between heavy and light crude oil prices; there may be adverse currency fluctuations; general economic conditions may experience periods of uncertainty or volatility thus affecting demand for our products and/or the costs for labour, equipment and services and changes in, or the introduction of new, government regulations relating to our business may increase operating costs.
2011 OUTLOOK
The company's 2011 production guidance and cash capital expenditure budget is described below.
-------------------------------------------------------------------------
2011 Production guidance
-------------------------------------------------------------------------
Bitumen Production (bbl/d) 14,500 - 16,500
-------------------------------------------------------------------------
Conventional Production (boe/d) 1,800 - 2,200
-------------------------------------------------------------------------
Total Upstream Production (boe/d) 16,300 - 18,700
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2011 Capital budget on cash basis (Canadian dollars in millions)
-------------------------------------------------------------------------
Oil sands $39
-------------------------------------------------------------------------
Conventional 11
-------------------------------------------------------------------------
Refinery 15
-------------------------------------------------------------------------
Exploration 25
-------------------------------------------------------------------------
EIA and Algar expansion engineering 8
-------------------------------------------------------------------------
Corporate and Head Office 6
-------------------------------------------------------------------------
Total $104
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Included in the 2011 capital budget are $22 million of growth projects - $8 million in oil sands, $6 million in conventional, and $8 million in EIA and Algar expansion engineering. Included in the refinery capital budget are $7 million of expenditures to complete the mandated benzene removal project. The company anticipates that cash balances and full year 2011 upstream netbacks and downstream margins (assuming similar WTI pricing and foreign exchange levels compared to 2010) together with available unused revolving lines of banking credit should be more than sufficient to meet all our budgeted capital expenditures and ongoing financial obligations throughout 2011.
Actual production achieved and capital expenditures incurred during 2011 could differ materially from these estimates - please see "Forward-Looking Information" and "Risk Factors".
SENSITIVITY ANALYSIS
The following table shows sensitivities to full year 2010 adjusted EBITDA for changes to oil prices, production volumes and foreign exchange rates. The analysis is based on recent prices and production volumes.
-------------------------------------------------------------------------
Change $million $/share(1)
-------------------------------------------------------------------------
WTI price US$5.00/bbl 4 $0.01
-------------------------------------------------------------------------
Bitumen production 500 bbl/d 2 $0.00
-------------------------------------------------------------------------
Exchange rate (U.S./Canadian) $0.05 4 $0.01
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Based on 429 million shares outstanding at September 30, 2010.
Information relating to Connacher, including Connacher's AIF is on SEDAR at www.sedar.com. See also the company's website at www.connacheroil.com.
RISK FACTORS AND RISK MANAGEMENT
Connacher is engaged in the oil and gas exploration, development, production, and refining industry. This business is inherently risky and there is no assurance that hydrocarbon reserves will be discovered and economically produced. Operational risks include competition, reservoir performance uncertainties, production reliability, performance of third party services and supplies, environmental factors, and regulatory and safety concerns. Financial risks associated with the petroleum industry include fluctuations in commodity prices, interest rates, currency exchange rates and the cost of goods and services.
Connacher's financial and operating performance is potentially affected by a number of factors including, but not limited to, risks associated with the oil and gas industry, commodity prices and exchange rates, the impacts of varying weather conditions on product sales, operating performance, environmental legislation, changes to royalty and income tax legislation, credit and capital market conditions, credit risk for failure of performance of third parties and other risks and uncertainties described in more detail in Connacher's AIF for the year ended December 31, 2009 filed with securities regulatory authorities.
Connacher employs highly qualified people, uses sound operating and business practices and evaluates all potential and existing wells using the latest applicable technology. The company has designed policies and procedures for compliance with government regulations and has in place an up-to-date emergency response program. Connacher monitors and seeks to adhere to environment and safety policies and standards. Asset retirement obligations are recognized upon acquisition, construction and development of the assets. Connacher maintains property and liability insurance coverage. The coverage provides a reasonable amount of protection from risk of loss; however, not all risks are foreseeable or insurable.
INTERNATIONAL FINANCIAL REPORTING STANDARDS
The company is executing a conversion project to complete the transition to IFRS by January 1, 2011, including the preparation of 2010 required comparative information. The conversion plan consists of four phases: diagnostic; design and planning; solution development; and implementation. A fulsome description of the company's IFRS conversion project phases and the company's progress to the end of 2009 is contained within the company's MD&A for the year ended December 31, 2009. The company is currently in the implementation phase and is still in the process of determining the financial impact of adopting IFRS. However, we have determined that the differences that could have the greatest impact on Connacher's consolidated financial statements relate to accounting for exploration and development activities, property, plant and equipment, goodwill, asset retirement obligations and income taxes.
The majority of the adjustments made on transition to IFRS will be recorded retrospectively to the opening balance of retained earnings at January 1, 2010. Changes arising from the transition where the accounting standards do not require retrospective application will be applied prospectively to transactions occurring subsequent to January 1, 2010.
IFRS 1 "First-Time Adoption of International Financial Reporting Standards" provides entities adopting IFRS for the first time with a number of optional and mandatory exemptions, in certain specific areas, to the general requirement for full retrospective application of IFRS. The company is analyzing the various accounting policy choices available and will implement those determined to be most appropriate in the company's circumstances.
One such exemption we expect to utilize is the amendment to IFRS 1 issued by the International Accounting Standards Board (IASB) in July 2009 respecting the determination of opening balances of property, plant and equipment. That amendment permits oil and gas companies currently using the full cost method of accounting to allocate the balance of property, plant and equipment as determined under Canadian GAAP to the IFRS categories of exploration and evaluation assets and development and producing properties without requiring full retrospective restatement of historic property, plant and equipment balances to the IFRS basis of accounting.
Other exemptions from retrospective application of IFRS which we may use are those available for foreign currency translation differences recorded in accumulated other comprehensive income, actuarial gains and losses relating to MRCI's defined benefit pension plan, stock-based compensation, leases and business combinations.
The following discussion provides an overview of the areas that could have the greatest impact on Connacher's consolidated financial statements. The items discussed below should not be considered a complete list of the changes which may occur as a result of the transition to IFRS. The discussion is intended to highlight the areas of most significant impact on Connacher based on the work completed to date. However, the company's analysis of the changes is ongoing. Additionally, Connacher has not finished quantifying the anticipated effects of the transition to IFRS on the consolidated financial statements.
Property, Plant & Equipment
International Accounting Standard (IAS) 16 "Property, Plant & Equipment" and Canadian GAAP contain the same basic principles. However there are some differences. IFRS requires that significant components of an asset be depreciated separately. Depreciation under IFRS commences when an asset is available for use. Capitalization of costs under IFRS ceases when an item of PP&E is in the location and condition necessary for it to be capable of operating in the manner intended by management. IFRS also permits property, plant and equipment to be measured using the fair value model or the historical cost model. The company does not plan to adopt the fair value model to measure its property, plant and equipment. Additionally, under IFRS exploration and evaluation assets are accounted for separately from development and production assets.
IFRS 1 contains an elective exemption where an entity may elect to reset as the new cost basis for property, plant and equipment, its fair value at the date of transition. The company is not planning to use this exemption and will continue to measure its property, plant and equipment at cost.
Impairment Testing of Assets
Impairment testing of non-financial assets under IFRS, including property, plant and equipment and goodwill, is measured using discounted cash flows and fair values. Under Canadian GAAP, an asset's carrying amount was first compared to its undiscounted future cash flows. If the carrying value exceeded that amount, the impairment was measured as the excess of the carrying value over the asset's discounted future cash flows. Under IFRS, there is no initial assessment using undiscounted cash flows. Therefore, impairments may occur more frequently under IFRS compared to Canadian GAAP. Under IFRS there is an opportunity to reverse impairment losses for assets other than goodwill where there is a favorable change in the circumstances which gave rise to the impairment. Under Canadian GAAP, impairments were not reversed.
Additionally, under Canadian GAAP, Connacher's oil and gas assets were tested for impairment in a single, country-wide full cost pool. Under IFRS, assets must be segregated into "cash-generating units" ("CGUs") for purposes of impairment testing. A CGU is defined as the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets. As a result, impairments may occur with respect to certain of the company's assets which would not have been incurred under Canadian GAAP because of the ability under full cost accounting to shelter assets using the cash flow from the all of the company's oil and gas properties included in the full cost pool. The effect of this difference on Connacher's oil and gas assets is not presently determinable.
Asset Retirement Obligations
Differences exist between Canadian GAAP and IFRS with respect to the measurement of asset retirement obligations. Specifically, under Canadian GAAP asset retirement obligations were measured at fair value using a credit-adjusted risk-free discount rate. Under IFRS, asset retirement obligations are measured using the best estimate of the expenditure required to settle the obligation, and are discounted using a risk-free interest rate. Using such a lower discount rate will likely result in an increase in Connacher's asset retirement obligation recorded on the consolidated balance sheet.
In addition, IFRS requires changes to the timing of cash flows, estimated amounts of cash flows and discount rates to be accounted for prospectively. Canadian GAAP is similar; however, changes to the discount rates for ARO are only applied to the incremental changes in the liability and not to the entire liability.
Income Taxes
Under IAS 12 "Income Taxes", deferred taxes are not recognized for temporary differences arising from the initial recognition of an asset or liability in a transaction which is not a business combination and which at the time of the transaction affects neither accounting nor taxable income. Canadian GAAP contains no such exemption.
Additionally, under IFRS current and deferred taxes are normally recognized in the income statement, except to the extent that deferred tax arises from (1) an item that has been recognized directly in equity, whether in the same or a different period, (2) a business combination or (3) a share-based payment transaction. If a deferred tax asset or liability is remeasured subsequent to initial recognition, the impact of remeasurement is recorded in earnings, unless it relates to an item originally recognized in equity, in which case the change would also be recorded in equity. The practice of tracking the remeasurement of taxes back to the item which originally triggered the recognition is commonly referred to as ''backwards tracing.'' Canadian GAAP prohibits backwards tracing except in relation to business combinations and financial reorganizations.
Internal Controls
Connacher is currently assessing the impact of the conversion to IFRS on internal controls and business processes. Based on our initial assessment, the impact is not expected to be significant. However, some additional controls will be required in regard to recording transitional adjustments and new processes for identifying and separately accounting for exploration and evaluation assets.
DISCLOSURE CONTROLS AND PROCEDURES
The company's Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO") have designed, or caused to be designed under their supervision, disclosure controls and procedures to provide reasonable assurance that: (i) material information relating to the company is made known to the company's CEO and CFO by others, particularly during the period in which the annual and interim filings are being prepared; and (ii) information required to be disclosed by the company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation.
INTERNAL CONTROLS OVER FINANCIAL REPORTING
The CEO and CFO have designed, or caused to be designed under their supervision, internal controls over financial reporting to provide reasonable assurance regarding the reliability of the company's financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP.
The company's CEO and CFO are required to cause the company to disclose any change in the company's internal controls over financial reporting that occurred during the company's most recent interim period that has materially affected, or is reasonably likely to materially affect, the company's internal controls over financial reporting. No changes in the company's internal controls over financial reporting were identified during such period that have materially affected, or are reasonably likely to materially affect, the company's internal controls over financial reporting.
It should be noted that a control system, including the company's disclosure and internal controls and procedures, no matter how well conceived, can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud. In reaching a reasonable level of assurance, management necessarily is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.
QUARTERLY RESULTS
Fluctuations in results over the previous eight quarters are due principally to variations in oil and gas prices, production and sales volumes and foreign exchange rates relative to U.S. dollar denominated debt. Significant volatility and declining commodity prices, together with severe economic uncertainty in Q4 2008 and Q1 2009 are the primary factors affecting financial results during those quarters. The magnitude of the changes in commodity prices during these periods was unprecedented.
-------------------------------------------------------------------------
($000 except per
share amounts) 2008 2009 2009 2009 2009
-------------------------------------------------------------------------
Three Months Ended Dec 31 Mar 31 June 30 Sept 30 Dec 31
-------------------------------------------------------------------------
Revenues, net of
royalties 102,109 61,757 100,219 151,360 108,354
-------------------------------------------------------------------------
Cash flow(1) (4,688) (4,692) 9,570 10,410 (2,766)
-------------------------------------------------------------------------
Basic, per share(1) (0.02) (0.02) 0.04 0.03 (0.07)
-------------------------------------------------------------------------
Diluted, per share(1) (0.02) (0.02) 0.03 0.03 (0.06)
-------------------------------------------------------------------------
Net earnings (loss) (43,592) (46,844) 39,966 47,767 (14,731)
-------------------------------------------------------------------------
Basic per share (0.21) (0.22) 0.15 0.12 (0.03)
-------------------------------------------------------------------------
Diluted per share (0.21) (0.22) 0.14 0.11 (0.03)
-------------------------------------------------------------------------
Property and equipment
additions 86,174 64,255 40,236 100,727 116,846
-------------------------------------------------------------------------
Cash on hand 223,663 96,220 401,160 333,634 256,787
-------------------------------------------------------------------------
Working capital surplus 197,914 120,035 455,001 347,139 245,067
-------------------------------------------------------------------------
Long-term debt 778,732 803,915 960,593 889,113 876,181
-------------------------------------------------------------------------
Shareholders' equity 469,087 428,276 622,235 658,336 671,588
-------------------------------------------------------------------------
Operating Information
-------------------------------------------------------------------------
Upstream: Daily
production/sales volumes
-------------------------------------------------------------------------
Bitumen - bbl/d 7,086 6,170 6,284 6,551 6,090
-------------------------------------------------------------------------
Crude oil - bbl/d 1,187 1,180 1,114 993 880
-------------------------------------------------------------------------
Natural gas - Mcf/d 12,405 12,828 12,144 10,377 10,319
-------------------------------------------------------------------------
Equivalent - boe/d(2) 10,341 9,488 9,421 9,274 8,690
-------------------------------------------------------------------------
Product sales prices(3)
-------------------------------------------------------------------------
Bitumen - $/bbl 12.06 22.45 40.95 45.30 48.23
-------------------------------------------------------------------------
Crude oil - $/bbl 48.13 39.63 54.87 60.58 67.24
-------------------------------------------------------------------------
Natural gas - $/Mcf 6.61 4.89 3.35 2.91 4.34
-------------------------------------------------------------------------
Selected highlights -
$/boe(2)
-------------------------------------------------------------------------
Weighted average
sales price(3) 21.73 26.13 38.11 41.74 45.76
-------------------------------------------------------------------------
Royalties 3.19 3.02 1.90 2.13 2.45
-------------------------------------------------------------------------
Operating costs 20.76 17.73 13.98 15.43 20.61
-------------------------------------------------------------------------
Netback(4) (2.22) 5.38 22.23 24.18 22.70
-------------------------------------------------------------------------
Downstream: Refining
-------------------------------------------------------------------------
Crude charged - bbl/d 8,333 6,867 9,145 7,076 8,188
-------------------------------------------------------------------------
Refining utilization - % 88 72 96 75 86
-------------------------------------------------------------------------
Margins - % (18) 7 5 8 (7)
-------------------------------------------------------------------------
Common Share Information
-------------------------------------------------------------------------
Shares outstanding end
of period (000) 211,182 211,291 403,546 403,567 427,031
-------------------------------------------------------------------------
Weighted average shares
outstanding for
the period
-------------------------------------------------------------------------
Basic (000) 211,182 211,286 266,425 403,565 421,804
-------------------------------------------------------------------------
Diluted (000) 211,575 211,286 286,985 424,058 422,344
-------------------------------------------------------------------------
Volume traded (000) 110,244 67,387 249,700 129,206 207,978
-------------------------------------------------------------------------
Common share price ($)
-------------------------------------------------------------------------
High 2.95 1.00 1.66 1.15 1.33
-------------------------------------------------------------------------
Low 0.60 0.61 0.74 0.76 0.94
-------------------------------------------------------------------------
Close (end of period) 0.74 0.74 0.92 1.10 1.28
-------------------------------------------------------------------------
-----------------------------------------------------
($000 except per
share amounts) 2010 2010 2010
-----------------------------------------------------
Three Months Ended Mar 31 June 30 Sept 30
-----------------------------------------------------
Revenues, net of
royalties 118,411 141,270 150,293
-----------------------------------------------------
Cash flow(1) 3,948 8,668 15,178
-----------------------------------------------------
Basic, per share(1) 0.01 0.02 0.04
-----------------------------------------------------
Diluted, per share(1) 0.01 0.02 0.04
-----------------------------------------------------
Net earnings (loss) 5,546 (33,126) 7,946
-----------------------------------------------------
Basic per share 0.01 (0.08) 0.02
-----------------------------------------------------
Diluted per share 0.01 (0.08) 0.02
-----------------------------------------------------
Property and equipment
additions 118,272 59,316 49,842
-----------------------------------------------------
Cash on hand 118,382 69,412 51,120
-----------------------------------------------------
Working capital surplus 127,186 99,834 61,543
-----------------------------------------------------
Long-term debt 851,978 888,323 867,650
-----------------------------------------------------
Shareholders' equity 668,722 644,166 648,543
-----------------------------------------------------
Operating Information
-----------------------------------------------------
Upstream: Daily
production/sales volumes
-----------------------------------------------------
Bitumen - bbl/d 6,936 6,211 6,758
-----------------------------------------------------
Crude oil - bbl/d 937 906 819
-----------------------------------------------------
Natural gas - Mcf/d 9,662 9,278 9,158
-----------------------------------------------------
Equivalent - boe/d(2) 9,483 8,663 9,103
-----------------------------------------------------
Product sales prices(3)
-----------------------------------------------------
Bitumen - $/bbl 51.98 43.13 42.68
-----------------------------------------------------
Crude oil - $/bbl 71.08 61.90 62.45
-----------------------------------------------------
Natural gas - $/Mcf 4.86 3.78 3.42
-----------------------------------------------------
Selected highlights -
$/boe(2)
-----------------------------------------------------
Weighted average
sales price(3) 49.99 41.44 40.74
-----------------------------------------------------
Royalties 3.57 2.73 2.72
-----------------------------------------------------
Operating costs 17.47 19.25 18.08
-----------------------------------------------------
Netback(4) 28.95 19.46 19.94
-----------------------------------------------------
Downstream: Refining
-----------------------------------------------------
Crude charged - bbl/d 9,347 9,373 9,903
-----------------------------------------------------
Refining utilization - % 98 99 104
-----------------------------------------------------
Margins - % (8) 12 12
-----------------------------------------------------
Common Share Information
-----------------------------------------------------
Shares outstanding end
of period (000) 428,246 429,103 429,120
-----------------------------------------------------
Weighted average shares
outstanding for
the period
-----------------------------------------------------
Basic (000) 427,830 429,023 429,106
-----------------------------------------------------
Diluted (000) 430,077 429,023 431,487
-----------------------------------------------------
Volume traded (000) 167,483 182,419 98,105
-----------------------------------------------------
Common share price ($)
-----------------------------------------------------
High 1.65 1.88 1.52
-----------------------------------------------------
Low 1.16 1.20 1.15
-----------------------------------------------------
Close (end of period) 1.49 1.29 1.20
-----------------------------------------------------
(1) Cash flow and cash flow per share do not have standardized meanings
prescribed by Canadian generally accepted accounting principles
("GAAP") and therefore may not be comparable to similar measures used
by other companies. Cash flow is calculated before changes in
non-cash working capital, pension funding and asset retirement
expenditures. The most comparable measure calculated in accordance
with GAAP would be cash flow from operating activities. Cash flow is
reconciled with cash flow from operating activities on the
Consolidated Statement of Cash Flows and in the applicable Management
Discussion & Analysis ("MD&A") for the periods referenced. Management
uses these non-GAAP measurements for its own performance measures and
to provide its shareholders and investors with a measurement of the
company's efficiency and its ability to fund its future growth
expenditures.
(2) All references to barrels of oil equivalent (boe) are calculated on
the basis of 6 Mcf: 1 bbl. This conversion is based on an energy
equivalency conversion method primarily applicable at the burner tip
and does not represent a value equivalency at the wellhead. Boes may
be misleading, particularly if used in isolation.
(3) Product and weighted average sales prices are net of diluent and
transportation costs and exclude risk management contract
gains/losses.
(4) Netback is a non-GAAP measure used by management as a measure of
operating efficiency and profitability. Netback per boe is calculated
as bitumen, crude oil and natural gas revenue before consideration of
risk management contracts/losses, less royalties and operating costs
divided by related production volumes.
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
-------------------------------------------------------------------------
September 30, December 31,
As at (Canadian dollar in thousands) 2010 2009
-------------------------------------------------------------------------
-------------------------------------------------------------------------
ASSETS
-------------------------------------------------------------------------
CURRENT
-------------------------------------------------------------------------
Cash $ 51,120 $ 256,787
-------------------------------------------------------------------------
Accounts receivable 54,642 43,038
-------------------------------------------------------------------------
Inventories 38,544 36,871
-------------------------------------------------------------------------
Due from Petrolifera Petroleum Limited 96 29
-------------------------------------------------------------------------
Prepaid expenses and other assets 15,822 15,874
-------------------------------------------------------------------------
Income taxes recoverable 1,005 2,608
-------------------------------------------------------------------------
Risk management contracts (note 8.2) 4,200 -
-------------------------------------------------------------------------
165,429 355,207
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Property, plant and equipment 1,402,956 1,230,256
-------------------------------------------------------------------------
Goodwill 103,676 103,676
-------------------------------------------------------------------------
Investment in Petrolifera Petroleum
Limited (note 13) 44,558 50,379
-------------------------------------------------------------------------
Risk management contracts (note 8.2) 1,081 -
-------------------------------------------------------------------------
$ 1,717,700 $ 1,739,518
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
-------------------------------------------------------------------------
CURRENT LIABILITIES
-------------------------------------------------------------------------
Accounts payable and accrued liabilities $ 102,686 $ 105,620
-------------------------------------------------------------------------
Risk management contracts (note 8.2) 1,200 4,520
-------------------------------------------------------------------------
103,886 110,140
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Long term debt (note 3) 867,650 876,181
-------------------------------------------------------------------------
Future income taxes 51,048 47,695
-------------------------------------------------------------------------
Asset retirement obligations (note 5) 38,504 32,848
-------------------------------------------------------------------------
Risk management contracts (note 8.2) 7,076 -
-------------------------------------------------------------------------
Employee future benefits 993 1,066
-------------------------------------------------------------------------
1,069,157 1,067,930
-------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
-------------------------------------------------------------------------
Share capital (note 6.1) 586,390 590,845
-------------------------------------------------------------------------
Equity component of convertible debentures 16,817 16,817
-------------------------------------------------------------------------
Contributed surplus (note 7.1) 34,704 30,560
-------------------------------------------------------------------------
Retained earnings 29,910 49,544
-------------------------------------------------------------------------
Accumulated other comprehensive loss (19,278) (16,178)
-------------------------------------------------------------------------
648,543 671,588
-------------------------------------------------------------------------
$ 1,717,700 $ 1,739,518
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Subsequent events (notes 8.2 and 14)
The accompanying notes to the interim consolidated financial statements
are an integral part of these statements.
CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS
(UNAUDITED)
-------------------------------------------------------------------------
Three months ended Nine months ended
September 30 September 30
-------------------------------------------------------------------------
(Canadian dollar in
thousands, except per
share amounts) 2010 2009 2010 2009
-------------------------------------------------------------------------
REVENUE
-------------------------------------------------------------------------
Upstream, net of
royalties $ 53,270 $ 52,267 $ 166,412 $ 136,562
-------------------------------------------------------------------------
Downstream 103,346 90,462 241,280 189,236
-------------------------------------------------------------------------
Gain (loss) on risk
management contracts
(note 8.2) (6,376) 6,442 2,109 (15,825)
-------------------------------------------------------------------------
Interest and other income 53 2,189 173 3,363
-------------------------------------------------------------------------
150,293 151,360 409,974 313,336
-------------------------------------------------------------------------
-------------------------------------------------------------------------
EXPENSES
-------------------------------------------------------------------------
Upstream - diluent purchases
and operating costs 29,584 26,230 88,609 77,920
-------------------------------------------------------------------------
Upstream transportation
costs 4,170 3,155 10,584 8,637
-------------------------------------------------------------------------
Downstream - crude oil
purchases and operating
costs 93,406 85,015 233,645 181,346
-------------------------------------------------------------------------
Loss on risk management
contracts (note 8.2) 1,287 - 1,287 -
-------------------------------------------------------------------------
General and administrative 4,531 3,364 14,361 11,062
-------------------------------------------------------------------------
Stock-based compensation
(note 7) 795 623 3,823 2,444
-------------------------------------------------------------------------
Finance charges (note 11) 13,220 13,127 39,171 31,164
-------------------------------------------------------------------------
Foreign exchange gain
(note 8.2) (23,308) (56,344) (14,706) (93,889)
-------------------------------------------------------------------------
Depletion, depreciation
and accretion 19,307 16,691 55,950 49,678
-------------------------------------------------------------------------
142,992 91,861 432,724 268,362
-------------------------------------------------------------------------
Earnings (loss) before
income taxes and other
items 7,301 59,499 (22,750) 44,974
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Current income tax recovery (994) (2,096) (638) (1,803)
-------------------------------------------------------------------------
Future income tax (recovery)
provision (150) 8,438 (7,867) 1,637
-------------------------------------------------------------------------
(1,144) 6,342 (8,505) (166)
-------------------------------------------------------------------------
Earnings (loss) before
other items 8,445 53,157 (14,245) 45,140
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Equity interest in
Petrolifera Petroleum
Limited's lossarnings (499) (2,797) (1,116) (1,658)
-------------------------------------------------------------------------
Dilution loss (note 13) - (2,593) (4,273) (2,593)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NET EARNINGS (LOSS) 7,946 47,767 (19,634) 40,889
-------------------------------------------------------------------------
Retained earnings, beginning
of period 21,964 16,508 49,544 23,386
-------------------------------------------------------------------------
Retained earnings, end
of period $ 29,910 $ 64,275 $ 29,910 $ 64,275
-------------------------------------------------------------------------
-------------------------------------------------------------------------
EARNINGS (LOSS) PER SHARE
(note 6.3)
-------------------------------------------------------------------------
Basic $ 0.02 $ 0.12 $ (0.05) $ 0.14
-------------------------------------------------------------------------
Diluted $ 0.02 $ 0.11 $ (0.05) $ 0.14
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The accompanying notes to the interim consolidated financial statements
are an integral part of these statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
-------------------------------------------------------------------------
Three months ended Nine months ended
September 30 September 30
-------------------------------------------------------------------------
(Canadian dollar
in thousands) 2010 2009 2010 2009
-------------------------------------------------------------------------
Net earnings (loss) $ 7,946 $ 47,767 $ (19,634) $ 40,889
-------------------------------------------------------------------------
Foreign currency
translation adjustment (4,637) (12,163) (3,100) (20,731)
-------------------------------------------------------------------------
Comprehensive
income (loss) $ 3,309 $ 35,604 $ (22,734) $ 20,158
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
-------------------------------------------------------------------------
Three months ended Nine months ended
September 30 September 30
-------------------------------------------------------------------------
(Canadian dollar
in thousands) 2010 2009 2010 2009
-------------------------------------------------------------------------
Balance, beginning of
period $ (14,641) $ (766) $ (16,178) $ 7,802
-------------------------------------------------------------------------
Foreign currency
translation adjustment (4,637) (12,163) (3,100) (20,731)
-------------------------------------------------------------------------
Balance, end of period $ (19,278) $ (12,929) $ (19,278) $ (12,929)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The accompanying notes to the interim consolidated financial statements
are an integral part of these statements.
CONSOLIDATED STATEMENTS OF CASH FLOW
(UNAUDITED)
-------------------------------------------------------------------------
Three months ended Nine months ended
September 30 September 30
-------------------------------------------------------------------------
(Canadian dollar
in thousands) 2010 2009 2010 2009
-------------------------------------------------------------------------
Cash provided by (used in)
the following activities:
-------------------------------------------------------------------------
OPERATING
-------------------------------------------------------------------------
Net earnings (loss) $ 7,946 $ 47,767 $ (19,634) $ 40,889
-------------------------------------------------------------------------
Items not involving cash:
-------------------------------------------------------------------------
Depletion, depreciation
and accretion 19,307 16,691 55,950 49,678
-------------------------------------------------------------------------
Stock-based compensation 795 623 3,823 2,444
-------------------------------------------------------------------------
Financing charges -
non-cash portion 1,516 1,438 4,406 3,613
-------------------------------------------------------------------------
Defined benefit pension
plan expense 156 70 465 364
-------------------------------------------------------------------------
Future income tax
(recovery) provision (150) 8,438 (7,867) 1,637
-------------------------------------------------------------------------
Unrealized (gain) loss
on risk management
contracts - net 8,224 (14,753) (1,525) 1,757
-------------------------------------------------------------------------
Gain on repurchase of
Second Lien Senior Notes - (1,796) - (2,271)
-------------------------------------------------------------------------
Equity interest in
Petrolifera Petroleum
Limited's loss 499 2,797 1,116 1,658
-------------------------------------------------------------------------
Dilution loss (note 13) - 2,593 4,273 2,593
-------------------------------------------------------------------------
Unrealized foreign
exchange gain (note 8.2) (23,115) (53,458) (13,213) (87,074)
-------------------------------------------------------------------------
Cash flow from operations
before working capital
and other changes 15,178 10,410 27,794 15,288
-------------------------------------------------------------------------
Pension funding (517) - (517) (234)
-------------------------------------------------------------------------
Asset retirement
expenditures (note 5) (39) (23) (507) (156)
-------------------------------------------------------------------------
Changes in non-cash
working capital 21,262 25,074 10,216 (25,594)
-------------------------------------------------------------------------
35,884 35,461 36,986 (10,696)
-------------------------------------------------------------------------
FINANCING
-------------------------------------------------------------------------
Proceeds on issue of
common shares (note 6.1) 13 12 1,392 172,758
-------------------------------------------------------------------------
Share issue costs - (145) (80) (8,930)
-------------------------------------------------------------------------
Issuance of First Lien
Senior Notes - - - 226,475
-------------------------------------------------------------------------
Debt issue cost of First
Lien Senior Notes - (260) - (21,118)
-------------------------------------------------------------------------
Repurchase of Second Lien
Senior Notes - (2,592) - (2,901)
-------------------------------------------------------------------------
13 (2,985) 1,312 366,284
-------------------------------------------------------------------------
INVESTING
-------------------------------------------------------------------------
Capital expenditures (48,447) (95,560) (216,855) (198,324)
-------------------------------------------------------------------------
Proceeds on disposition of
property, plant and equipment - - 1,205 -
-------------------------------------------------------------------------
Decrease in restricted cash - - - (10,000)
-------------------------------------------------------------------------
Investments in Petrolifera
Petroleum Limited - (12,029) - (12,029)
-------------------------------------------------------------------------
Changes in non-cash
working capital (5,154) 25,559 (25,295) (23,964)
-------------------------------------------------------------------------
(53,601) (82,030) (240,945) (244,317)
-------------------------------------------------------------------------
NET INCREASE (DECREASE)
IN CASH (17,704) (49,554) (202,647) 111,271
-------------------------------------------------------------------------
Foreign exchange loss on
cash balances held in
foreign currency (588) (17,972) (3,020) (11,300)
-------------------------------------------------------------------------
CASH, BEGINNING OF PERIOD 69,412 391,160 256,787 223,663
-------------------------------------------------------------------------
CASH, END OF PERIOD $ 51,120 $ 323,634 $ 51,120 $ 323,634
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For supplementary cash flow information - see note 12
The accompanying notes to the interim consolidated financial statements
are an integral part of these statements.
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. NATURE OF OPERATIONS AND ORGANIZATION
Connacher Oil and Gas Limited ("Connacher" or "the company") is a
publicly traded and integrated energy company headquartered in Calgary,
Alberta, Canada.
Management has segmented the company's business based on differences in
products and services and management responsibility. The company's
business is conducted predominantly through two major business segments -
upstream in Canada and downstream in USA, through its wholly owned
subsidiary, Montana Refining Company, Inc. ("MRCI"). Upstream includes
exploration for, development and production of crude oil, natural gas,
natural gas liquids and bitumen. Downstream includes refining of
primarily crude oil to produce and market gasoline, jet fuel, diesel
fuels, asphalt and ancillary products.
The company also has an investment in Petrolifera Petroleum Limited
("Petrolifera") which has been accounted for on the equity basis. As at
September 30, 2010 and December 31, 2009, the company owned 26.9 million
Petrolifera common shares representing 18.5 percent and 22 percent,
respectively, of Petrolifera's issued and outstanding common shares and
6.8 million Petrolifera share purchase warrants. See also note 13.
Petrolifera is engaged in petroleum and natural gas exploration,
development and production activities in South America.
2. SIGNIFICANT ACCOUNTING POLICIES
The interim consolidated financial statements were prepared in accordance
with Canadian generally accepted accounting standards and follow the same
accounting policies and methods of computation as the most recent annual
consolidated financial statements. Certain information and disclosures
normally required to be included in notes to the annual consolidated
financial statements have been condensed or omitted. Accordingly, these
interim consolidated financial statements should be read in conjunction
with the annual consolidated financial statements and the notes thereto
for the year ended December 31, 2009. In the opinion of management, these
interim consolidated financial statements contain all adjustments of a
normal and recurring nature necessary to present fairly Connacher's
financial position at September 30, 2010 and December 31, 2009 and the
results of its operations and cash flows for the three and nine months
ended September 30, 2010 and 2009.
3. LONG-TERM DEBT
-------------------------------------------------------------------------
September 30, December 31,
(Canadian dollar in thousands) 2010 2009
-------------------------------------------------------------------------
First Lien Senior Notes $189,911 $191,509
-------------------------------------------------------------------------
Second Lien Senior Notes 586,071 596,184
-------------------------------------------------------------------------
Convertible Debentures 91,668 88,488
-------------------------------------------------------------------------
Long-term debt $867,650 $876,181
-------------------------------------------------------------------------
The following table provides the key terms and conditions of the long-
term debt:
-------------------------------------------------------------------------
Face Interest
Value of Rate Interest Principal
Principal Maturity Per Payment Payment
(in millions) Date Annum Terms Terms
-------------------------------------------------------------------------
First Lien
Senior Notes
(Secured)
Issue date: Semi-annually One payment
June 16, July on January 15 on maturity
2009 US$ 200 15, 2014 11.75% and July 15 (note 3.1)
-------------------------------------------------------------------------
Second Lien
Senior Notes
(Secured)
Issue date: Semi-annually One payment
December 3, December on June 15 and on maturity
2007 US$ 587.3 15, 2015 10.25% December 15 (note 3.1)
-------------------------------------------------------------------------
Convertible
into common
June 30, shares at a
Convertible 2012 conversion
Debentures unless price of
(Unsecured) converted Semi-annually $5.00 per
Issue date: prior to on June 30 and share
May 25, 2007 $100 that date 4.75% December 31 (note 3.1)
-------------------------------------------------------------------------
3.1 The company may redeem some or all of the First and Second Lien
Senior Notes (together the "Notes") and Convertible Debentures prior
to their maturity subject to the terms of the agreements. Upon a
change of control of the company, Connacher is obliged to offer to
purchase the outstanding Convertible Debentures; additionally, the
holders of the First and Second Lien Senior Notes may require
Connacher to purchase the Notes. There were no changes to the terms
and conditions of the long-term debt during three and nine months
ended September 30, 2010.
4. REVOLVING CREDIT FACILITY
As at September 30, 2010, the company had a US$50 million revolving
credit facility (the "Facility"). The Facility has a two year term
starting from November 2009 and ranks ahead of the company's First and
Second Lien Senior Notes. It is secured by a first lien charge on all of
the company's assets, excluding certain pipeline assets in the USA and
the company's investment holdings in Petrolifera. The Facility bears
interest at the lenders' Canadian prime rate, a U.S. base rate, a
Bankers' Acceptance rate, or at a LIBOR rate plus applicable margins.
Access to the Facility is subject to certain covenants, which the company
was in compliance with at September 30, 2010. At September 30, 2010, $5.7
million of letters of credit were issued and outstanding pursuant to the
Facility.
5. ASSET RETIREMENT OBLIGATIONS
The following table reconciles the beginning and ending aggregate
carrying amount of the obligation associated with the company's
retirement of its upstream crude oil, natural gas and oil sands
properties and facilities.
-------------------------------------------------------------------------
Nine months
ended Year ended
September 30, December 31,
(Canadian dollar in thousands) 2010 2009
-------------------------------------------------------------------------
Balance, beginning of period $32,848 $26,396
-------------------------------------------------------------------------
Liabilities incurred 4,260 6,194
-------------------------------------------------------------------------
Liabilities settled (507) (142)
-------------------------------------------------------------------------
Liabilities disposed (264) -
-------------------------------------------------------------------------
Change in estimates - (1,803)
-------------------------------------------------------------------------
Accretion expense 2,167 2,203
-------------------------------------------------------------------------
Balance, end of period $38,504 $32,848
-------------------------------------------------------------------------
At September 30, 2010, the estimated total undiscounted amount required
to settle the asset retirement obligations was $86.7 million (December
31, 2009 - $72.0 million). The company has not recorded an asset
retirement obligation for its refining property, plant and equipment as
it is currently the company's intent to maintain and upgrade the
refinery, so that it will be operational for the foreseeable future.
Consequently, it is not possible at the present time to estimate a date
or range of dates for settlement of any asset retirement obligation
related to the refinery.
6. SHARE CAPITAL
Authorized: unlimited number of common voting shares
Authorized: unlimited number of first preferred shares of which none were
outstanding
Authorized: unlimited number of second preferred shares of which none
were outstanding
6.1 ISSUED AND OUTSTANDING COMMON SHARE CAPITAL
-------------------------------------------------------------------------
Amount
(Canadian
Number of dollar in
Shares thousands)
-------------------------------------------------------------------------
Balance, January 1, 2010 427,031,362 $590,845
-------------------------------------------------------------------------
Shares issued upon exercise of stock
options (note 7.2) 1,450,468 1,392
-------------------------------------------------------------------------
Assigned value of stock options
exercised (note 7.1) 759
-------------------------------------------------------------------------
Shares issued to directors as
compensation (note 7.3) 638,496 1,002
-------------------------------------------------------------------------
Share issue cost, net of future income tax (59)
-------------------------------------------------------------------------
Tax effect of flow-through shares (note 6.2) (7,549)
-------------------------------------------------------------------------
Balance, September 30, 2010 429,120,326 $586,390
-------------------------------------------------------------------------
6.2 In October 2009, the company issued 23,172,500 common shares on a
flow-through basis at $1.30 per common share for gross proceeds of
$30.1 million and renounced the qualifying expenditures to investors
effective December 31, 2009. As at September 30, 2010, the remaining
commitments to the qualifying expenditures pursuant to this flow-
through share issue was $4 million. The related tax effect of $7.5
million was recorded in the nine months ended September 30, 2010.
6.3 PER SHARE AMOUNTS
The following table summarizes the common shares used in per share
calculations.
-------------------------------------------------------------------------
Three months ended Nine months ended
September 30 September 30
-------------------------------------------------------------------------
(000) 2010 2009 2010 2009
-------------------------------------------------------------------------
Weighted average common
shares outstanding - basic 429,106 403,565 428,658 294,463
-------------------------------------------------------------------------
Dilutive effect of employee
stock options 2,000 - - -
-------------------------------------------------------------------------
Dilutive effect of share
award plan 381 490 - 406
-------------------------------------------------------------------------
Dilutive effect of convertible
debentures - 20,003 - -
-------------------------------------------------------------------------
Weighted average common
shares outstanding - diluted 431,487 424,058 428,658 294,869
-------------------------------------------------------------------------
7. CONTRIBUTED SURPLUS, STOCK OPTIONS AND SHARE AWARD PLAN FOR NON-
EMPLOYEE DIRECTORS
7.1 CONTRIBUTED SURPLUS
The following table shows the changes in contributed surplus.
-------------------------------------------------------------------------
Nine months
ended Year ended
September 30, December 31,
(Canadian dollar in thousands) 2010 2009
-------------------------------------------------------------------------
Balance, beginning of period $30,560 $26,053
-------------------------------------------------------------------------
Stock based compensation expensed 3,321 3,5941
-------------------------------------------------------------------------
Stock based compensation capitalized 1,582 1,096
-------------------------------------------------------------------------
Assigned value of stock options exercised (759) (183)
-------------------------------------------------------------------------
Balance, end of period $34,704 $30,560
-------------------------------------------------------------------------
7.2 STOCK OPTIONS
The stock options have a term of five years to maturity and vest over the
period of two to three years. The following table shows the changes in
stock options and the related weighted average exercise price.
-------------------------------------------------------------------------
Nine months ended Nine months ended
September 30, 2010 September 30,2009
-------------------------------------------------------------------------
Weighted Weighted
Average Average
Number Exercise Number Exercise
of Options Price of Options Price
-------------------------------------------------------------------------
Outstanding, beginning
of period 22,579,045 $1.72 16,383,104 $3.16
-------------------------------------------------------------------------
Granted 9,633,649 1.37 5,114,047 $0.75
-------------------------------------------------------------------------
Exercised (1,450,468) 0.96 (288,171) $0.60
-------------------------------------------------------------------------
Forfeited (2,339,334) 1.93 (726,783) 2.07
-------------------------------------------------------------------------
Expired (1,364,000) 1.52 (190,000) 1.35
-------------------------------------------------------------------------
Cancelled - - (4,407,000) 5.04
-------------------------------------------------------------------------
Outstanding, end of period 27,058,892 $1.63 15,885,197 $1.98
-------------------------------------------------------------------------
Exercisable, end of period 13,405,526 $2.06 9,868,030 $2.45
-------------------------------------------------------------------------
The following table summarizes stock options outstanding and exercisable
under the plan.
-------------------------------------------------------------------------
September 30, 2010 September 30, 2009
-------------------------------------------------------------------------
Weighted Weighted
Weighted Average Weighted Average
Range of Average Remaining Average Remaining
Exercise Number Exercise Contract- Number Exercise Contract-
Prices Outstanding Price ual Life Outstanding Price ual Life
-------------------------------------------------------------------------
$0.20 -
$0.99 3,850,933 $0.75 3.6 5,425,637 $0.76 3.9
-------------------------------------------------------------------------
$1.00 -
$1.99 17,675,680 1.26 4.1 4,321,645 1.33 3.1
-------------------------------------------------------------------------
$2.00 -
$3.99 4,913,770 3.32 1.1 5,180,406 3.31 2.1
-------------------------------------------------------------------------
$4.00 -
$5.99 618,509 4.48 1.0 957,509 4.68 1.7
-------------------------------------------------------------------------
27,058,892 $1.63 3.4 15,885,197 $1.98 3.0
-------------------------------------------------------------------------
The fair value of each stock option granted is estimated on the date of
grant using the Black-Scholes option-pricing model using the following
weighted average assumptions.
-------------------------------------------------------------------------
Nine months ended September 30 2010 2009
-------------------------------------------------------------------------
Risk free interest rate (percent) 1.9 1.3
-------------------------------------------------------------------------
Expected option life (years) 3.0 3.0
-------------------------------------------------------------------------
Expected volatility (percent) 72 68
-------------------------------------------------------------------------
The weighted average fair value at the date of grant of options granted
during the three months ended September 30, 2010 was $0.63 per option
(three months ended September 30, 2009 - $0.47 per option) and during the
nine months ended September 30, 2010 was $0.66 per option (nine months
ended September 30, 2009 - $0.34 per option).
7.3 SHARE AWARD PLAN FOR NON-EMPLOYEE DIRECTORS
Under the share award plan, share units (comprised of one common share
per unit) may be granted to non-employee Directors of the company in
amounts determined by the Board of Directors on the recommendation of its
Governance Committee.
-------------------------------------------------------------------------
Nine months Nine months
ended ended
September September
(Number of common share units) 30, 2010 30, 2009
-------------------------------------------------------------------------
Outstanding, beginning of period 648,916 392,705
-------------------------------------------------------------------------
Granted 380,598 478,872
-------------------------------------------------------------------------
Issued (638,496) (327,623)
-------------------------------------------------------------------------
Cancelled (10,420) (54,662)
-------------------------------------------------------------------------
Outstanding, end of period 380,598 489,292
-------------------------------------------------------------------------
Exercisable, end of period - 5,210
-------------------------------------------------------------------------
The 380,598 share awards granted in the nine months ended September 30,
2010 vest on January 1, 2011. The 478,872 share awards granted in the
nine months ended September 30, 2009 vested on January 1, 2010. In three
months and nine months ended September 30, 2010, $137,000 and $502,000,
respectively (three and nine months ended September 30, 2009 - $193,000
and $516,000, respectively) was accrued as a liability and stock based
compensation expense in respect of outstanding shares under the share
award plan.
8. FINANCIAL INSTRUMENTS
Connacher's financial instruments include cash, accounts receivable,
amounts due from Petrolifera, accounts payable and accrued liabilities,
risk management contracts and long-term debt (First and Second Lien
Senior Notes and Convertible Debentures).
8.1 FAIR VALUE MEASUREMENTS FOR FINANCIAL INSTRUMENTS
The following table shows the comparison of the carrying and fair values
of the company's financial instruments as at September 30, 2010.
-------------------------------------------------------------------------
Carrying
(Canadian dollar in thousands) Value Fair Value
-------------------------------------------------------------------------
Held for trading
-------------------------------------------------------------------------
Cash $51,120 $51,120
-------------------------------------------------------------------------
Accounts receivable $54,642 $54,642
-------------------------------------------------------------------------
Due from Petrolifera $96 $96
-------------------------------------------------------------------------
Accounts payable and accrued liabilities $102,686 $102,686
-------------------------------------------------------------------------
Risk management contracts $2,995 $2,995
-------------------------------------------------------------------------
Other liabilities
-------------------------------------------------------------------------
First Lien Senior Notes $189,911 $230,866
-------------------------------------------------------------------------
Second Lien Senior Notes $586,071 $632,639
-------------------------------------------------------------------------
Convertible Debentures $91,668 $97,049
-------------------------------------------------------------------------
8.2 RISK EXPOSURES
The company is exposed to market risks related to the volatility of
commodity selling prices and foreign exchange rates. In certain
instances, the company uses derivative instruments to manage the
company's exposure to these risks. The company is also exposed, to a
lesser extent, to credit risk on accounts receivable and counterparties
to risk management contracts and to liquidity risk. The company employs
risk management strategies and policies to ensure that any exposures to
risk are in compliance with the company's business objectives and risk
tolerance levels. Risk management is ultimately authorized by the
company's Board of Directors and is implemented and monitored by senior
management of the company.
At September 30, 2010, the company's exposure to risks associated with or
arising from the use of financial instruments had not changed
significantly from December 31, 2009 and June 30, 2010.
Market Risk And Sensitivity Analysis
Market risk is the risk that the fair value or future cash flows of a
financial instrument will fluctuate because of changes in market prices.
Market risk is comprised of commodity price risk and foreign currency
rate risk. The objective of market risk management is to manage and
control market price exposures within acceptable limits, while maximizing
returns.
Commodity price risk
The company is exposed to commodity price risk as a result of potential
changes in the market prices of its crude oil, bitumen, natural gas,
natural gas liquids and refined products.
The following table summarizes the net position of the company's risk
management contracts.
-------------------------------------------------------------------------
September 30, December 31,
(Canadian dollar in thousands) 2010 2009
-------------------------------------------------------------------------
Current asset $4,200 $ -
-------------------------------------------------------------------------
Non-current asset 1,081 -
-------------------------------------------------------------------------
$5,281 $ -
-------------------------------------------------------------------------
Current liability $1,200 $4,520
-------------------------------------------------------------------------
Non-current liability 7,076 -
-------------------------------------------------------------------------
$8,276 $4,520
-------------------------------------------------------------------------
Net risk management contracts liability $2,995 $4,520
-------------------------------------------------------------------------
The following table shows the net unrealized risk management positions.
-------------------------------------------------------------------------
September 30, December 31,
(Canadian dollar in thousands) 2010 2009
-------------------------------------------------------------------------
Crude oil liability - Upstream $1,795 $4,520
-------------------------------------------------------------------------
Natural gas liability - Upstream 1,200 -
-------------------------------------------------------------------------
Liability, end of period $2,995 $4,520
-------------------------------------------------------------------------
The following tables show the details of the risk management positions as
at September 30, 2010 and December 31, 2009.
September 30, 2010 - Crude oil contracts - Upstream
-------------------------------------------------------------------------
Liability
(Asset)
as at
September 30,
2010
Price (Canadian
Volume (WTI dollar in
(bbl/d) Term Type U.S.$/bbl) thousands)
-------------------------------------------------------------------------
2,500 Jan 1, 2010 - Dec 31, 2010 Swap $78.00 $756
-------------------------------------------------------------------------
1,000 Jan 1, 2011 - Mar 31, 2011 Swap $86.10 (259)
-------------------------------------------------------------------------
1,000 Jan 1, 2011 - Mar 31, 2011 Swap $88.10 (444)
-------------------------------------------------------------------------
2,000 Apr 1, 2011 - Jun 30, 2011 Swap $85.25 (146)
-------------------------------------------------------------------------
2,000 Jan 1, 2011 - Dec 31, 2011 Swap* $90.60 2,753
-------------------------------------------------------------------------
2,000 Jan 1, 2011 - Mar 31, 2011 Call option $100.25 234
-------------------------------------------------------------------------
2,000 Jan 1, 2011 - Mar 31, 2011 Put option $80.00 (911)
-------------------------------------------------------------------------
2,500 May 1, 2010 - Dec 31, 2010 Call option $95.00 68
-------------------------------------------------------------------------
2,500 May 1, 2010 - Dec 31, 2010 Put option $75.00 (256)
-------------------------------------------------------------------------
Balance,
as at
September
30, 2010 $1,795
-------------------------------------------------------------------------
* On December 30, 2011, the counterparty has a right to extend the
maturity date of the contract for additional one year from January 1,
2012 to December 31, 2012 at US$ 90.60/bbl.
September 30, 2010 - Natural gas contracts - Upstream
-------------------------------------------------------------------------
Liability
as at
September 30,
2010
Price (Canadian
Volume (AECO dollar in
(GJ/d) Term Type CAD$/GJ) thousands)
-------------------------------------------------------------------------
4,000 Sept 1, 2010 - Aug 31, 2011 Swap $3.87 $355
-------------------------------------------------------------------------
4,000 Oct 1, 2010 - Sept 30, 2011 Swap $4.20 845
-------------------------------------------------------------------------
Balance, as at September 30, 2010 $1,200
-------------------------------------------------------------------------
December 31, 2009 - Crude oil contracts - Upstream
-------------------------------------------------------------------------
Liability
as at
December 31,
2009
Price (Canadian
Volume (WTI dollar in
(bbl/d) Term Type U.S.$/bbl) thousands)
-------------------------------------------------------------------------
2,500 Jan 1 - Dec 31, 2010 Swap $78.00 $4,115
-------------------------------------------------------------------------
2,500 Feb 1 - Apr 30, 2010 Swap $79.02 405
-------------------------------------------------------------------------
Balance, as at December 31, 2009 $4,520
-------------------------------------------------------------------------
Subsequent to September 30, 2010, the company entered in the following
risk management contract:
- April 1, 2011 - March 31, 2012 - 2,000 bbl/d at a minimum of WTI U.S.
$80.00 bbl/d and a maximum of WTI U.S.$96.00/bbl
The following table summarizes the income statement effects of revenue-
related risk management contracts.
-------------------------------------------------------------------------
Three
months
ended
(Canadian dollar in September
thousands) Three months ended September 30, 2010 30, 2009
-------------------------------------------------------------------------
Upstream Downstream Upstream
Revenue Revenue* Total Revenue
-------------------------------------------------------------------------
Unrealized gain (loss) $(6,933) $(91) $(7,024) $14,753
-------------------------------------------------------------------------
Realized gain (loss) 424 224 648 (8,311)
-------------------------------------------------------------------------
Gain (loss) on risk
management contracts $(6,509) $133 $(6,376) $6,442
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Nine
months
ended
(Canadian dollar in September
thousands) Nine months ended September 30, 2010 30, 2009
-------------------------------------------------------------------------
Upstream Downstream Upstream
Revenue Revenue* Total Revenue
-------------------------------------------------------------------------
Unrealized gain (loss) $2,725 $ - $2,725 $(1,757)
-------------------------------------------------------------------------
Realized gain (loss) (73) (543) (616) (14,068)
-------------------------------------------------------------------------
Gain (loss) on risk
management contracts $2,652 $(543) $2,109 $(15,825)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
* In April 2010, the company entered into a commodity price risk
contract to hedge its gasoline revenue at floating price of WTI plus
US$9/bbl. The contract expired on September 30, 2010.
The following table summarizes the income statement effects of operating
cost-related risk management contracts.
-------------------------------------------------------------------------
Three and nine Three and nine
months ended months ended
(Canadian dollar September 30, September 30,
in thousands) 2010 2009
-------------------------------------------------------------------------
Unrealized loss $ (1,200) $ -
-------------------------------------------------------------------------
Realized loss (87) -
-------------------------------------------------------------------------
Loss on risk management contracts $ (1,287) $ -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As at September 30, 2010, had the forward price for WTI been U.S. $1/bbl
higher or lower, the impact would have been to increase or decrease,
respectively, the loss before income taxes by $2.0 million.
As at September 30, 2010, had the forward price for AECO been
CAD $0.10/GJ higher or lower, the impact would have been to decrease or
increase, respectively, the loss before income taxes by $366,000.
Currency risk
Currency risk is the risk that the fair value or future cash flows of a
financial instrument will fluctuate because of changes in foreign
exchange rates. The following table summarizes the components of the
company's foreign exchange gain (loss).
-------------------------------------------------------------------------
Three months ended Nine months ended
(Canadian dollar in thousands) September 30 September 30
-------------------------------------------------------------------------
2010 2009 2010 2009
-------------------------------------------------------------------------
Unrealized foreign exchange
gain (loss) on translation of:
-------------------------------------------------------------------------
U.S. denominated First and
Second Lien Senior Notes $ 23,230 $ 69,221 $ 15,940 $ 95,074
-------------------------------------------------------------------------
Foreign currency denominated
cash balances (625) (17,259) (2,789) (10,460)
-------------------------------------------------------------------------
Foreign exchange collar - 346 - 1,620
-------------------------------------------------------------------------
Other foreign currency
denominated monetary items 510 1,150 62 840
-------------------------------------------------------------------------
Unrealized foreign
exchange gain 23,115 53,458 13,213 87,074
-------------------------------------------------------------------------
Realized foreign exchange gain 193 2,886 1,493 6,815
-------------------------------------------------------------------------
Foreign exchange gain $ 23,308 $ 56,344 $ 14,706 $ 93,889
-------------------------------------------------------------------------
The company is exposed to fluctuations in foreign currency primarily as
a result of its U.S. dollar denominated Notes, crude oil sales based on
U.S. dollar indices and commodity price contracts that are settled in
U.S. dollars. A $0.01 change in the U.S. to Canadian dollar exchange rate
would have resulted in a $7.6 million change in foreign exchange
gain/loss at September 30, 2010. The company's downstream operations
operate with a U.S. dollar functional currency, which gives rise to
currency exchange rate risk on translation of MRCI's operations. The
impact is recorded in other comprehensive income/loss. A $0.01 change in
the U.S. to Canadian dollar exchange rate would have resulted in a
$0.3 million change in other comprehensive income (loss) at September 30,
2010.
9. CAPITAL MANAGEMENT
The company is exposed to financial risks on its financial instruments
and in the way it finances its capital requirements. The company manages
these financial and capital structure risks by operating in a manner
that minimizes its exposures to volatility of the company's financial
performance. Connacher continues to structure its capital consistent with
last year.
Connacher's objectives in managing its cash, debt and equity and its
future capital requirements are to safeguard its ability to meet its
financial obligations, to maintain a flexible capital structure that
allows multiple financing options when a financing need or opportunity
arises and to optimize its use of long-term debt and equity at an
appropriate level of risk.
The company manages its capital structure and follows a financial
strategy that considers economic and industry conditions, the risk
characteristics and the long-term nature of its underlying assets and
its growth opportunities. It strives to continuously improve its credit
rating with objective of reducing its cost of capital. Connacher monitors
its capital structure using a number of financial ratios and industry
metrics to ensure its objectives are being met and to ensure continued
compliance with its financial covenants.
Connacher's current capital structure and certain financial ratios are
noted below.
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September 30, December 31,
(Canadian dollar in thousands) 2010 2009
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Long term debt(1) $ 867,650 $ 876,181
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Shareholders' equity 648,543 671,588
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Total Debt plus Equity ("capitalization") $ 1,516,193 $ 1,547,769
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Debt to book capitalization(2) 57% 57%
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Debt to market capitalization(3) 63% 62%
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(1) Long-term debt is stated at its carrying value, which is net of
transaction costs and the Convertible Debentures' equity component
value.
(2) Calculated as long-term debt divided by the book value of
shareholders' equity plus long-term debt.
(3) Calculated as long-term debt divided by the period end market value
of shareholders' equity plus long-term debt.
As at September 30, 2010, the company's net debt (long-term debt, net of
cash on hand) was $816.5 million. Its net debt to book capitalization
was 54 percent and its net debt to market capitalization was 59 percent.
10. SEGMENTED INFORMATION
The company has two business segments. In Canada, the company is in the
business of exploring for and producing crude oil, natural gas, natural
gas liquids and bitumen. In the USA, the company is in the business of
refining and marketing petroleum products. The significant information
of these operating segments is presented below.
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(Canadian dollar
in thousands) Canada USA
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Intersegment
Three months ended Elimination
September 30, 2010 Oil and Gas Refining (1) Total
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Net revenues $ 53,270 $ 106,159 $ (2,813) $ 156,616
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Gain (loss) on risk
management
contracts - net (7,796) 133 - (7,663)
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Equity interest in
Petrolifera (loss) (499) - - (499)
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Interest and other income 24 29 - 53
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Finance charges 13,214 6 - 13,220
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Depletion, depreciation
and accretion 16,677 2,630 - 19,307
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Income tax provision
(recovery) (2,867) 1,723 - (1,144)
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Net earnings 2,204 5,742 - 7,946
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Property, plant and
equipment 1,319,386 83,570 - 1,402,956
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Goodwill 103,676 - - 103,676
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Capital expenditures 47,961 1,881 - 49,842
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Total assets $ 1,546,379 $ 171,321 $ - $ 1,717,700
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Three months ended
September 30, 2009
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Net revenues $ 52,267 $ 92,714 $ (2,252) $ 142,729
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Gain on risk management
contracts 6,442 - - 6,442
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Equity interest in
Petrolifera loss (2,797) - - (2,797)
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Interest and other income 2,006 183 - 2,189
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Finance charges 13,120 7 - 13,127
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Depletion, depreciation
and accretion 14,864 1,827 - 16,691
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Income tax provision 5,254 1,088 - 6,342
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Net earnings 45,162 2,605 - 47,767
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Property, plant and
equipment 1,045,583 85,622 - 1,131,205
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Goodwill 103,676 - - 103,676
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Capital expenditures 92,207 8,520 - 100,727
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Total assets 1,557,824 178,302 $ - $ 1,736,126
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(1) Intersegment transactions are eliminated on consolidation.
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(Canadian dollar
in thousands) Canada USA
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Intersegment
Nine months ended Elimination
September 30, 2010 Oil and Gas Refining (1) Total
-------------------------------------------------------------------------
Net revenues $ 166,412 $ 251,736 $ (10,456) $ 407,692
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Gain (loss) on risk
management
contracts - net 1,365 (543) - 822
-------------------------------------------------------------------------
Equity interest in
Petrolifera loss (1,116) - - (1,116)
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Interest and other income 87 86 - 173
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Finance charges 39,152 19 - 39,171
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Depletion, depreciation
and accretion 48,474 7,476 - 55,950
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Income tax recovery (8,072) (433) - (8,505)
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Net earnings (loss) (22,710) 3,076 - (19,634)
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Property, plant and
equipment 1,319,386 83,570 - 1,402,956
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Goodwill 103,676 - - 103,676
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Capital expenditures 223,151 4,279 - 227,430
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Total assets $ 1,546,379 $ 171,321 $ - $ 1,717,700
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Nine months ended
September 30, 2009
-------------------------------------------------------------------------
Net revenues $ 136,562 $ 194,960 $ (5,724) $ 325,798
-------------------------------------------------------------------------
Loss on risk management
contracts (15,825) - - (15,825)
-------------------------------------------------------------------------
Equity interest in
Petrolifera loss (1,658) - - (1,658)
-------------------------------------------------------------------------
Interest and other income 2,797 566 - 3,363
-------------------------------------------------------------------------
Finance charges 30,796 368 - 31,164
-------------------------------------------------------------------------
Depletion, depreciation
and accretion 44,187 5,491 - 49,678
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Income tax provision (107) (59) - (166)
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Net earnings 39,924 965 - 40,889
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Property, plant and
equipment 1,045,583 85,622 - 1,131,205
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Goodwill 103,676 - - 103,676
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Capital expenditures 189,930 15,288 - 205,218
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Total assets $ 1,557,824 $ 178,302 $ - $ 1,736,126
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(1) Intersegment transactions are eliminated on consolidation.
11. FINANCE CHARGES
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Three months ended Nine months ended
(Canadian dollar in thousands) September 30 September 30
-------------------------------------------------------------------------
2010 2009 2010 2009
-------------------------------------------------------------------------
Interest expense on
long-term debt $ 25,470 $ 26,427 $ 75,880 $ 68,850
-------------------------------------------------------------------------
Amortization of transaction
costs on revolving credit
facility 209 41 536 780
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Bank charges and other fees 403 - 1,045 897
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26,082 26,468 77,461 70,527
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Less: Interest capitalized
(note 11.1) (12,862) (13,341) (38,290) (39,363)
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Finance charges - net $ 13,220 $ 13,127 $ 39,171 $ 31,164
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11.1 Interest on the First Lien Senior Notes and interest on that portion
of the Second Lien Senior Notes which has been used to fund the
construction of the Algar project continues to be capitalized during
its construction and pre-operating phases.
12. SUPPLEMENTARY CASH FLOW INFORMATION
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Three months ended Nine months ended
(Canadian dollar in thousands) September 30 September 30
-------------------------------------------------------------------------
2010 2009 2010 2009
-------------------------------------------------------------------------
Interest paid $ 12,110 $ 160 $ 59,347 $ 37,565
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Income taxes paid $ 106 $ 250 $ 284 $ 1,613
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13. INVESTMENT IN PETROLIFERA PETROLEUM LIMITED
In April 2010, Petrolifera closed a public offering of 23,678,500 common
shares at a price of $0.85 per common share for gross proceeds of
$20.1 million (the "Offering"). The company did not subscribe for shares
in the Offering and accordingly, the company's equity interest in
Petrolifera was reduced to 18.5 percent from 22 percent. The reduction
in the ownership interest resulted in a dilution loss of $4.2 million
for the nine months ended September 30, 2010.
14. SUBSEQUENT EVENT
In October 2010, to fund its future exploration program, the company
completed an equity financing of 17,480,000 flow-through common shares
at a price of $1.45 per common share for gross proceeds of $25.3 million.
For further information: Richard A. Gusella, Chairman and Chief Executive Officer, or Grant D. Ukrainetz, Vice President, Corporate Development, Phone: (403) 538-6201, Fax: (403) 538-6225, [email protected], Website: connacheroil.com
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