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Canadian Oil Sands Trust (2)
Symbol COS.UN
Shares Issued 468,318,182
Close 2006-10-24 C$ 30.28
Recent Sedar Documents
Canadian Oil Sands earns $278-million in Q3 2006
2006-10-24 19:11 ET - News Release
Mr. Marcel Coutu reports
CANADIAN OIL SANDS TRUST REPORTS RESULTS FOR THE THIRD QUARTER OF 2006 AND A DISTRIBUTION OF $0.30 PER TRUST UNIT
Canadian Oil Sands Trust's funds from operations declined slightly to $359-million, or 77 cents per trust unit, in the third quarter of 2006, compared with $364-million, or 79 cents per unit, for the same 2005 quarter. For the nine months ended Sept. 30, funds from operations rose to $824-million, or $1.77 per unit, from $741-million, or $1.61 per unit, in 2005. The increase in funds from operations year to date 2006 primarily reflects higher realized Syncrude sweet blend (SSB) selling prices and sales volumes. For the 2006 three-month period, the higher volumes and selling prices were offset by an increase in Crown royalties, which rose to $115-million, or $13.01 per barrel, in the third quarter of 2006 from $6-million, or 77 cents per barrel, in the comparable 2005 quarter. The increase in 2006 Crown royalties reflects the shift in royalty rate to 25 per cent of net revenues during the second quarter of the year. The trust is declaring a quarterly distribution of 30 cents per unit for unitholders of record on Nov. 3, 2006, payable on Nov. 30, 2006.
"In the past quarter we began to see the effect of the stage 3 expansion with a substantial lift in our production volumes," said Marcel Coutu, president and chief executive officer. "During September, when stage 3 came on-line, Syncrude production averaged 340,000 barrels per day. Our new environmental unit, the flue gas desulphurizer, which suspended stage 3 operations after its brief start-up in May, is now performing well with the use of purchased ammonia."
Third quarter 2006 overview
* Net income declined 27 per cent to $278-million, or 60 cents per unit, in the third quarter of 2006, from $380-million, or 83 cents per unit, in the same 2005 period. Net income before unrealized foreign exchange and future income tax, which management believes is a better measure of operational performance than net income, was $291-million, or 62 cents per unit, in the third quarter of 2006 compared with $312-million, or 68 cents per unit, in the same period of 2005.
* The decrease in quarter-over-quarter net income before unrealized foreign exchange and future income tax primarily reflects the full effect of the increase in Crown royalties to the 25-per-cent rate of net revenue, which offset the higher sales volumes and average realized SSB selling price and lower operating and non-production costs reported in the third quarter of 2006. An increase to depreciation, depletion and accretion also reduced net income in the third quarter of 2006 compared with the same 2005 period.
* Crown royalties increased to $115-million, or $13.01 per barrel, in the third quarter of 2006 from $6-million, or 77 cents per barrel, in the comparable 2005 quarter. For the nine months ended Sept. 30, Crown royalties were $149-million, or $6.37 per barrel, and $14-million, or 70 cents per barrel, in 2006 and 2005, respectively. The increase in 2006 Crown royalties reflects the shift in royalty rate to 25 per cent of net revenues from the minimum 1 per cent of gross revenue, which occurred in the second quarter of the year.
* Net income year to date rose 7 per cent to $706-million, or $1.52 per unit, compared with $657-million, or $1.43 per unit in 2005. Higher production and strong SSB selling prices contributed to the improvement in net income, partially offset by an increase in operating costs, Crown royalties and higher depreciation, depletion and accretion expense.
* Canadian Oil Sands' 2006 sales volumes averaged approximately 95,000 barrels per day in the third quarter and 86,000 barrels per day year to date, substantially higher than the 86,000 barrels per day and 75,000 barrels per day reported for the respective 2005 periods. The increase in volumes reflects the resumption of stage 3 operations late in the third quarter and better reliability and operating performance of the original Mildred Lake upgrading facility.
* Operating costs in the third quarter of 2006 decreased to $19.68 per barrel from $23.61 per barrel in 2005. Lower long-term employee incentive costs and purchased energy costs contributed to the approximate 17-per-cent decline in quarter-over-quarter unit operating costs. Year to date, operating costs were $28.57 per barrel in 2006 compared with $26.63 per barrel in 2005, primarily as a result of an expanded operating facility to support the stage 3 project without significant volume increases prior to the resumption of stage 3 operations.
* Capital expenditures declined to $47-million in the third quarter of 2006 from $230-million in 2005 with the stage 3 project being essentially complete.
* Net debt-to-book capitalization at Sept. 30, 2006, decreased to 28 per cent from 33 per cent at Dec. 31, 2005.
Third quarter operations marked by restart of stage 3
Figures provided below are the gross Syncrude numbers and are not the trust's 35.49-per-cent net share.
Syncrude's poststage 3 facilities now have a design productive capacity of approximately 350,000 barrels per day. Referred to as barrels per calendar day, this figure reflects the average daily production rate under normal operating conditions, which include scheduled downtime required for maintenance and turnaround activities, and unscheduled downtime as a result of mechanical problems, unanticipated repairs and other slowdowns. The maximum rate a facility can produce when operating at full capacity under optimal conditions and with no downtime for maintenance or turnarounds is referred to as barrels per stream day. Syncrude's poststage 3 facilities have the design capability to produce about 375,000 barrels per stream day. All references to Syncrude's daily production in the following discussions refer to Syncrude's barrels per calendar day, unless stated otherwise.
SSB production during the third quarter of 2006 totalled 26 million barrels, or approximately 283,000 barrels per day, compared with 21.9 million barrels, or approximately 238,000 barrels per day in the third quarter of last year. Third quarter 2006 production reflects solid operations from the base plant supplemented by new volumes from the stage 3 facilities during September. The same quarter of 2005 was affected by the start of maintenance and revamp activities on the vacuum distillation unit.
For the nine months ended Sept. 30, 2006, production totalled 66.4 million barrels, or about 243,000 barrels per day, compared with 57.3 million barrels, or approximately 210,000 barrels per day, in the same 2005 period. Year-to-date 2006 volumes reflect an extended turnaround of Coker 8-1 earlier in the year offset by the start-up of stage 3 and improved reliability of the base plant operations. The same period of 2005 reflects the extended turnaround of Coker 8-2 and repairs to a hydrogen plant.
Syncrude employees and contractors recorded a lost-time injury rate of 0.15 per 200,000 work force hours for the nine-month period ended Sept. 30, 2006. While still reflecting a good safety record, the 2006 rate is up from the outstanding LTI performance of 0.04 during the same time period last year.
Stage 3 commences production
Syncrude resumed its stage 3 operations with the introduction of bitumen feed into Coker 8-3 on Aug. 30, 2006. Production volumes gradually ramped up during the month of September to allow for regular monitoring and testing of the flue gas desulphurization (FGD) and other units. Investigations into the odorous emissions that occurred during the operation of Syncrude's new FGD unit and coker in May determined that the ammonia being used in the FGD was largely responsible for these emissions. Analysis indicated the ammonia produced at the Syncrude operation contains impurities, including odour-causing compounds. In order to support the operation of the FGD, Syncrude will be processing purchased aqueous ammonia while it investigates a long-term strategy to use the on-site produced ammonia. Certain other modifications also were undertaken on the FGD to help improve its performance.
In addition to enabling the restart of the stage 3 facilities, the use of purchased ammonia is expected to help prevent odours and realize the FGD's environmental benefit of significantly reducing sulphur dioxide emissions from the expansion facilities. Syncrude has been testing the FGD using purchased ammonia since late July with good results. The cost to import the ammonia is expected to total about $3-million per month. No estimates are available at this time for any potential costs associated with developing permanent changes to enable Syncrude to use its internally produced ammonia.
Syncrude continues to focus on lining out and optimizing the new stage 3 operating units in order to ramp up to full annual productive capability of 128 million barrels, or 45 million barrels net to the trust. During the introduction of the stage 3 units into full operations in 2006, Syncrude's first priority has been on the safe and reliable expansion of volumes. The next area of focus will be on improving product quality from SSB to Syncrude sweet premium (SSP). Syncrude has identified unanticipated hydrogen limitations, which will require modifications to the steam generation unit of the new hydrogen plant before SSP can be produced. Syncrude plans to implement these modifications during planned turnarounds in the fall of 2007; accordingly, the transition to the fully upgraded, higher-quality SSP product is now not expected to occur until the fourth quarter of 2007. The trust believes that SSP's higher quality should enable some of its existing customers to increase the amount of Syncrude production they process and potentially attract new customers. With the delay in producing SSP, the trust expects more of its production will now have to be shipped to further markets, potentially resulting in a wider price discount to WTI (West Texas Intermediate) going forward, however, the supply/demand equation for synthetic oil is difficult to predict and quantify.
With the stage 3 project being essentially complete, Syncrude has expended approximately $8.45-billion on the project. Ancillary costs of about $100-million, gross to Syncrude, remain to be incurred.
Offer to acquire Canada Southern Petroleum Ltd.
Canadian Oil Sands' offer to purchase all of the outstanding common shares of Canada Southern Petroleum expired on Sept. 6, at which time the trust had taken up about 78 per cent of the common shares outstanding. A special meeting of the shareholders of Canada Southern is planned for Oct. 25 to vote on the amalgamation, which will enable Canadian Oil Sands to take up the remaining common shares.
Canadian Oil Sands is in the process of disposing Canada Southern's conventional natural gas assets and expects to conclude this process by the end of the year, after which point Canadian Oil Sands would continue to hold only the natural gas interests in the Arctic Islands.
Brant Sangster appointed director
Mr. Sangster was appointed as a director of Canadian Oil Sands Ltd., a wholly owned subsidiary of the trust, effective Sept. 6, 2006. Mr. Sangster brings to Canadian Oil Sands' board nearly 40 years of operations experience in the energy industry, most recently focused in the oil sands sector. On Aug. 31, 2006, he retired as senior vice-president, oil sands, with Petro-Canada, where he was responsible for managing the company's oil sands businesses, including its 12-per-cent interest in the Syncrude joint venture and participation in the Fort Hills mining and upgrading project. In addition to his 25-year career as a senior executive with Petro-Canada, Mr. Sangster held various strategic planning and operating positions with Imperial Oil Ltd. for 13 years. He holds a BSc in chemical engineering from Dalhousie University.
Distribution reinvestment plan (DRIP)
Eligible unitholders who wish to participate in the trust's current DRIP must file their election form, in the case of registered unitholders, with Computershare Trust Co. of Canada at the number or address noted on the enrolment forms before the Nov. 3, 2006, record date. Unitholders who hold their units in the name of a broker should contact their broker to ensure that the proper election forms are completed and sent in before Nov. 3, 2006. Information on the plan and enrolment forms are available on the trust's website or by calling investor relations.
The trust intends to suspend the DRIP once it reaches its net debt target of $1.2-billion, which based on the trust's outlook as at Oct. 24, 2006, and the current crude oil price environment, it now expects to occur in the latter half of 2007. The trust had previously indicated its intention to modify the DRIP's terms to provide unitholders with the ability to reinvest quarterly distributions at the volume-weighted average price (VWAP), however, the trust has since decided to suspend the DRIP entirely to reduce administrative burden and costs, and to allow for an easier possible reinstatement of the DRIP in its current form if required in the future to finance new investing activities.
Foreign ownership update
Based on information from the statutory declarations by unitholders, the trust estimates that, as of Aug. 4, 2006, approximately 43 per cent of its unitholders are non-Canadian residents with the remaining 57 per cent being Canadian residents. The current foreign ownership level has increased considerably from the last declaration date of May 8, 2006, which was approximately 36 per cent at that time as disclosed in the trust's July 25, 2006, second quarter report. Canadian Oil Sands' trust indenture provides that not more than 49 per cent of its units can be held by non-Canadian residents.
The trust continues to monitor its foreign ownership levels on a regular basis through declarations from unitholders. The next declarations to be requested will be as of Nov. 3, 2006.
Outlook for 2006
Canadian Oil Sands has revised its outlook for 2006, highlights of which are as follows:
* Syncrude production to range between 90 million and 98 million barrels, or 32 million to 35 million barrels net to the trust based on the trust's 35.49-per-cent interest, with a single-point estimate of 95 million barrels, or 33.5 million barrels net to the trust;
* funds from operations totalling $1.1-billion, or $2.32 per unit, based on: annual average WTI crude oil price of $65.00 (U.S.) per barrel, a foreign exchange rate of 89 U.S. cent per one Canadian cent; an average SSB-to-WTI discount of $3.00 per barrel for the year and the higher production levels;
* operating costs of $881-million, or $26.29 per barrel, which includes $6.51 per barrel of purchased energy at an estimated $6.50 per gigajoule (GJ) natural gas price;
* capital expenditures totalling $315-million;
* based on the trust's expectation of being successful in its offer to acquire all of the outstanding shares of Canada Southern at a price of $13.10 (U.S.) per share, the trust expects a cost for the acquisition of about $165-million, net of disposal proceeds for the conventional natural gas properties, acquisition and disposition costs, and liquidation of working capital;
* based on the trust's 2006 outlook and extension of the current crude oil price environment, the trust expects to reach its net debt target of $1.2-billion in the latter half of 2007. Once it has achieved its net debt target, unless capital investment growth opportunities exist that it believes would offer unitholders better value, the trust intends to approach full payout of its free cash flow (funds from operations less capital expenditures and reclamation trust contributions); and
* approximately 95 per cent of the distributions pertaining to 2006 will be taxable as other income with the remainder classified as a tax-deferred return of capital. The actual taxability of the distributions will be determined and reported to unitholders prior to the end of the first quarter of 2007.
FINANCIAL AND OPERATING HIGHLIGHTS
(in millions of dollars)
Three months ended Nine months ended
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2006 2005 2006 2005
Net income $ 278 $ 380 $ 706 $ 657
Per trust unit -- basic $ 0.60 $ 0.83 $ 1.52 $ 1.43
Per trust unit -- diluted $ 0.59 $ 0.83 $ 1.51 $ 1.43
Funds from operations $ 359 $ 364 $ 824 $ 741
Per trust unit $ 0.77 $ 0.79 $ 1.77 $ 1.61
Unitholder distributions $ 140 $ 92 $ 372 $ 184
Per trust unit $ 0.30 $ 0.20 $ 0.80 $ 0.40
Syncrude sweet blend sales volumes (*)
Total (mmbbl) 8.8 7.9 23.4 20.5
Daily average (bbl) 95,438 85,942 85,662 75,210
Per trust unit (bbl per unit) - - 0.1 -
Operating costs per barrel $ 19.68 $ 23.61 $ 28.57 $ 26.63
Net realized selling price per barrel
Realized selling price before hedging $ 78.14 $ 76.67 $ 75.61 $ 69.71
Currency hedging gains (losses) $ 0.29 $ 0.76 $ 0.76 $ 0.80
-------- -------- -------- --------
Net realized selling price $ 78.43 $ 77.43 $ 76.37 $ 70.51
======== ======== ======== ========
WTI ($U.S. per barrel) $ 70.60 $ 63.31 $ 68.29 $ 55.61
(*) The trust's sales volumes may differ from its production volumes due to
changes in inventory, which are primarily in-transit pipeline volumes.
We seek Safe Harbor.
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