CALGARY, April 25 /PRNewswire-FirstCall/ -- Canadian Oil Sands Trust ("Canadian Oil Sands" or the "Trust" or "we") (TSX - COS.UN) today announced first quarter 2007 results and a 33 per cent increase in the Trust's quarterly distribution to $0.40 per Trust unit ("Unit") for Unitholders of record on May 8, 2007, payable on May 31, 2007. Net income in the first quarter of 2007 increased to $262 million, or $0.55 per Unit, from $91 million, or $0.20 per Unit, during the previous year's same period. First quarter 2007 cash from operating activities was $202 million, or $0.42 per Unit, compared to $187 million, or $0.40 per Unit, in 2006. Non-cash operating working capital requirements, primarily a result of higher accounts receivable, reduced first quarter 2007 cash from operating activities by $94 million.
Net income and cash from operating activities reflect higher revenues as a result of incremental Stage 3 production, less turnaround and maintenance activity compared to the prior year, and a larger Syncrude working interest. As well, net income and cash from operating activities benefited from a 41 per cent reduction in per barrel operating costs quarter-over-quarter, offset somewhat by a higher Crown royalty expense.
Crown royalties increased to $9.58 per barrel in 2007 from $0.67 per barrel in 2006 with the shift to the higher royalty rate of 25 per cent of net revenues from the minimum one per cent of gross revenue, which occurred in the second quarter of 2006. In the first quarter of 2007 Syncrude paid royalties totaling $256 million to the Province of Alberta. The Syncrude project began paying the higher rate at roughly the same time as the Stage 3 expansion was completed as a result of robust crude oil prices, which increased revenues from the base plant and accelerated project payout.
"Reflecting our constructive view of our free cash flow over the next several quarters and our intention to move to fuller payout of that free cash flow, we are very pleased to announce our third distribution increase since our Stage 3 project funding began to diminish," said Marcel Coutu, President and Chief Executive Officer. "Reduced capital spending, growing volumes from our recently expanded facilities and a renewed focus on costs and operational reliability are cornerstones of our current operation. These form the foundation upon which our next growth stages will be launched."
First Quarter Highlights
The Trust's 2007 financial results reflect a 36.74 per cent working interest in the Syncrude Joint Venture, which represents the Trust's increased ownership following its previously announced acquisition of a 1.25 per cent Syncrude interest from Talisman Energy Inc. ("Talisman") on January 2, 2007. Prior year comparative information is based on the Trust's previous ownership of 35.49 per cent.
- Sales volumes increased 46 per cent, averaging about 109,000 barrels per day, in the first quarter of 2007 compared to the same 2006 period. The Trust's larger Syncrude ownership, incremental production from Stage 3, and less turnaround and maintenance activity quarter-over-quarter contributed to higher volumes in 2007. - Operating costs averaged $23.56 per barrel in 2007, down from $40.26 per barrel in 2006 as a result of lower turnaround and maintenance activity, a decrease in the value of Syncrude's long- term incentive plan, and lower purchased energy costs in 2007 compared to 2006. - Quarterly capital expenditures in 2007 declined to $33 million from $137 million in 2006 with the completion of the Stage 3 project in August 2006. - Net debt to book capitalization of 25 per cent at the end of the first quarter of 2007 remained the same as at 2006 year end. - The Trust is maintaining its single point estimate for 2007 production of 110 million barrels, or 40.4 million barrels net to the Trust. On March 13, 2007, the Trust announced a reduction to the upper end of its production range by five million barrels with the current range now between 105 to 115 million barrels, or 39 to 42 million barrels net to the Trust. The change reflects constrained production rates from Coker 8-3 since late 2006. Syncrude plans to perform maintenance on Coker 8-3 during the second quarter of 2007 to restore production throughput. - The Syncrude Joint Venture owners have approved the recommendations of an Opportunity Assessment Team as part of the Management Services Agreement between Syncrude Canada Ltd. and Imperial Oil Resources Ltd., previously announced on November 1, 2006. Implementation of the recommendations will be led by Mr. Tom Katinas, who has been appointed to the consolidated role of President and Chief Executive Officer of Syncrude Canada effective May 1, 2007.
Effective April 25, 2007, Mr. Walter O'Donoghue will be retiring from Canadian Oil Sands' board of directors. Commencing as chairman in 1995 of Athabasca Oil Sands Trust, one of the predecessors of Canadian Oil Sands Trust, Mr. O'Donoghue has served as a board member since the Trust's inception. We want to thank him for providing his knowledge and insight in helping to create and develop the Trust into the successful entity that it is today. We wish him the best in his retirement.
The following Management's Discussion and Analysis ("MD&A") was prepared as of April 25, 2007 and should be read in conjunction with the unaudited interim consolidated financial statements of Canadian Oil Sands Trust ("Canadian Oil Sands" or the "Trust") for the three months ended March 31, 2007 and March 31, 2006, as well as the audited consolidated financial statements and MD&A of the Trust for the year ended December 31, 2006.
ADVISORY- in the interest of providing the Trust's Unitholders and potential investors with information regarding the Trust, including management's assessment of the Trust's future production and cost estimates, plans and operations, certain statements throughout this MD&A contain "forward-looking statements" under applicable securities law. Forward-looking statements in this M&DA include, but are not limited to, statements with respect to: the expectation that Coker 8-3 will achieve its productive capacity after undergoing maintenance in the second quarter; the expected realized selling price, which includes the anticipated differential to WTI, to be received in 2007 for Canadian Oil Sands' product; the expected reserves and the impact of such reserves estimates on the D&D rate; the potential amount payable in respect of any future income tax liability; the expected impact on the Trust from the announced changes to the federal government's taxation of income trusts; the expectation that the net debt level will allow the Trust to remain unhedged while providing the capacity to fund growth opportunities; the belief that the Trust will not be restricted by its net debt to total capitalization financial covenant; the expected increased reliability and other benefits from the management services agreement between Syncrude Canada Ltd. and Imperial Oil Resources; the anticipated timing to reach full production rates from Coker 8-3 and to modify the FGD unit and hydrogen plant; the expected impact that increased supplies of synthetic crude oil will have on the net realized selling price that Canadian Oil Sands receives for its product; the level of energy consumption in 2007 and beyond; the timing to start and complete the turnaround of Coker 8-3; capital expenditures for 2007; the anticipated cost and completion date for the SER project; the expectation not to enter into crude oil hedges in the future; the level of natural gas consumption in 2007 and beyond; the expected timing to produce SSP; the expected price for crude oil and natural gas in 2007, the expected production, revenues and operating costs for 2007; the net sales proceeds of the disposition of the remainder of Canadian Arctic Gas Ltd.'s conventional assets; the anticipated impact that certain factors such as natural gas and oil prices, foreign exchange and operating costs have on the Trust's cash from operating activities and net income; and the expected impact of any future environmental legislation or changes to the Crown royalties regime. You are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur. Although the Trust believes that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Some of the risks and other factors which could cause results to differ materially from those expressed in the forward-looking statements contained in this MD&A include, but are not limited to: the impact of technology on operations and processes and how new complex technology may not perform as expected, labour shortages and the productivity achieved from labour in the Fort McMurray area, the supply and demand metrics for oil and natural gas, the impact that pipeline capacity and refinery demand have on prices for our products, the variances of stock market activities generally, normal risks associated with litigation, general economic, business and market conditions, regulatory changes, and such other risks and uncertainties described from time to time in the reports and filings made with securities regulatory authorities by the Trust. You are cautioned that the foregoing list of important factors is not exhaustive. The discussion on proposed tax changes in trust tax legislation is based solely on the general information found in the background paper issued by Finance at the time of the October 31, 2006 announcement (which is not legislation), the guidelines issued by Finance on December 15, 2006, and the draft amendments to the Tax Act released on December 21, 2006. No assurance can be given that the final legislation implementing the 2006 proposed tax changes will be consistent with the foregoing or that Canadian federal income tax law respecting income trusts and other flow-through entities will not be further changed in a manner which adversely affects the Trust and its Unitholders. To the extent that changes, including the 2006 proposed tax changes, are implemented, such changes could result in the income tax considerations described in this MD&A being materially different in certain respects. Furthermore, the forward-looking statements contained in this MD&A are made as of the date of this MD&A, and unless required by law, the Trust does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this MD&A are expressly qualified by this cautionary statement.
REVIEW OF SYNCRUDE OPERATIONS
During the first quarter of 2007, the Syncrude Joint Venture ("Syncrude") oil production totalled 26.6 million barrels, or an average of 296,000 barrels per day, compared to 18.4 million barrels, or 205,000 barrels per day, during the same period of 2006. First quarter 2007 production was slightly under the 27 million barrel estimate provided in our January 29, 2007 Guidance Document. Net to the Trust, production totalled 9.8 million barrels in the first quarter of 2007 based on our 36.74 per cent working interest compared to 6.5 million barrels in 2006 based on a 35.49 per cent interest.
Production in the first quarter of 2007 was primarily affected by unplanned maintenance on Coker 8-2, which began in late 2006 and extended into late January, combined with constrained production rates from the new Coker 8 - 3. Comparatively, production in the first quarter of 2006 was affected by an extensive maintenance schedule with turnarounds of several units including an extended turnaround of Coker 8-1. As well, the increase in the Trust's share of Syncrude's production in 2007 reflects the Trust's higher 36.74 per cent ownership interest.
Coker 8-3 has been producing at about 70 per cent of its capacity since late 2006. During March, lower volumes from Coker 8-3 were offset by higher output from Cokers 8-1 and 8-2 with production averaging 356,000 barrels per day during the month. To bring Coker 8-3 closer to its design rate, Syncrude plans to perform maintenance starting in May of 2007 to remove coke residue build-up within the vessel. While maintenance on Coker 8-3 was not scheduled to occur this early in its run length, we did anticipate encountering various performance issues associated with bringing a new, complex expansion such as Stage 3 into operation.
Canadian Oil Sands' operating costs declined to $23.56 per barrel in the first quarter of 2007 compared with $40.26 per barrel in the same quarter last year. There was less turnaround and maintenance activity quarter-over-quarter, thereby increasing production and reducing per barrel costs. First quarter 2007 operating costs also reflect lower purchased energy and Syncrude incentive compensation costs compared to the same quarter of 2006 (see "Operating Costs" section of this MD&A for further discussion).
Syncrude's post-Stage 3 facilities have the design capability to produce approximately 375,000 barrels per day when operating at full capacity under optimal conditions and with no downtime for maintenance or turnarounds. This daily production capacity is referred to as "barrels per stream day". However, under normal operating conditions, scheduled downtime is required for maintenance and turnaround activities and unscheduled downtime will occur as a result of mechanical problems, unanticipated repairs and other slowdowns. When allowances for such downtime are included, the daily design productive capacity of Syncrude's post-Stage 3 facilities is approximately 350,000 barrels per day on average and is referred to as "barrels per calendar day". All references to Syncrude's productive capacity in the following discussions refer to barrels per calendar day, unless stated otherwise.
The Trust's production volumes differ from its sales volumes due to changes in inventory, which are primarily in-transit pipeline volumes. These in-transit volumes vary with current production. The growth in Syncrude(TM) Sweet Blend ("SSB") volumes from the Stage 3 facilities also has required Canadian Oil Sands to access more distant markets to sell its volumes, which generally increases in-transit pipeline volumes. The impact of Syncrude's first quarter operations on Canadian Oil Sands' financial results is more fully discussed later in this MD&A.
SUMMARY OF QUARTERLY RESULTS ($ millions, except per Trust Unit and 2007 2006 volume amounts) Q1 Q4 Q3 Q2 Q1 ------------------------------------------------------------------------- Revenues(1) $ 674 $ 646 $ 689 $ 624 $ 473 Net income $ 262 $ 128 $ 278 $ 337 $ 91 Per Trust Unit, Basic(2) $ 0.55 $ 0.27 $ 0.60 $ 0.72 $ 0.20 Per Trust Unit, Diluted(2) $ 0.55 $ 0.27 $ 0.59 $ 0.72 $ 0.20 Cash from operating activities $ 202 $ 412 $ 334 $ 209 $ 187 Per Trust Unit(2) $ 0.42 $ 0.88 $ 0.72 $ 0.45 $ 0.40 Daily average sales volumes (bbls) 108,891 110,185 95,438 86,394 74,929 Net realized selling price ($/bbl) $ 68.69 $ 63.71 $ 78.43 $ 79.35 $ 70.24 Operating costs ($/bbl) $ 23.56 $ 23.60 $ 19.68 $ 28.48 $ 40.26 Purchased natural gas price ($/GJ) $ 6.99 $ 6.51 $ 5.42 $ 5.72 $ 7.42 ($ millions, except per Trust Unit and 2005 volume amounts) Q4 Q3 Q2 -------------------------------------------------- Revenues(1) $ 519 $ 612 $ 492 Net income $ 174 $ 380 $ 218 Per Trust Unit, Basic(2) $ 0.38 $ 0.83 $ 0.48 Per Trust Unit, Diluted(2) $ 0.37 $ 0.83 $ 0.48 Cash from operating activities $ 281 $ 364 $ 199 Per Trust Unit(2) $ 0.61 $ 0.79 $ 0.43 Daily average sales volumes (bbls) 78,318 85,942 79,506 Net realized selling price ($/bbl) $ 72.07 $ 77.43 $ 68.03 Operating costs ($/bbl) $ 25.54 $ 23.61 $ 21.35 Purchased natural gas price ($/GJ) $ 10.73 $ 8.31 $ 6.94 (1) Revenues after crude oil purchases and transportation expense. (2) Trust Unit information has been adjusted to reflect the 5:1 Unit split that occurred on May 3, 2006. ------------------------------------------------------------------------
Quarterly variances in revenues, net income, and cash from operating activities are caused mainly by fluctuations in crude oil prices, production and sales volumes, operating costs and natural gas prices. Net income is also impacted by non-cash foreign exchange gains and losses caused by fluctuations in foreign exchange rates on our U.S. dollar denominated debt and by future income tax changes. A large proportion of operating costs are fixed and, as such, unit operating costs are highly variable to production volumes. While the supply/demand balance for crude oil affects selling prices, the impact of this equation is difficult to predict and quantify and has not displayed significant seasonality. Maintenance and turnaround activities are typically scheduled to occur in the first or second quarter. However, the exact timing of unit shutdowns cannot be precisely scheduled, and unplanned outages will occur. As a result, production levels also may not display reliable seasonality patterns or trends. Maintenance and turnaround costs are expensed in the period incurred and can lead to significant increases in operating costs and reductions in production in those periods, as demonstrated by the particularly high per barrel operating costs in the first quarter of 2006. Natural gas prices are typically higher in winter months as heating demand rises, but this seasonality is significantly influenced by weather conditions and North American natural gas inventory levels.
Three significant changes have occurred over the last eight quarters that have impacted the Trust's financial results:
- Syncrude's Stage 3 expansion came on-line at the end of August 2006, increasing Syncrude's productive capacity by about 100,000 barrels per day with a corresponding impact on the Trust's revenues. - During the second quarter of 2006, Crown royalties shifted to the higher rate of 25 per cent of net revenue, compared to the one per cent of gross revenue rate that had applied since January 1, 2002, increasing Crown royalties expense and somewhat offsetting the revenue increases to net income and cash from operating activities in the latter half of 2006 and the first quarter of 2007. - Starting in the first quarter of 2007, the Trust's financial results reflect a 36.74 per cent working interest in Syncrude, which represents its increased ownership following the acquisition of Talisman Energy Inc.'s ("Talisman") 1.25 per cent working interest on January 2, 2007. Prior year comparative information is based on the Trust's previous ownership of 35.49 per cent. REVIEW OF FINANCIAL RESULTS
Net income in the first quarter of 2007 increased by $171 million to total $262 million, or $0.55 per Trust Unit ("Unit"), from the same period of last year. Cash from operating activities was $202 million, or $0.42 per Unit, in the first quarter of 2007 compared to $187 million, or $0.40 per Unit, in 2006. The increase in cash from operating activities quarter-over-quarter was not as significant as the change in net income, mainly due to changes in operating non-cash working capital. In the first quarter of 2007, non-cash operating working capital requirements reduced cash from operating activities by $94 million, primarily a result of higher accounts receivable. An increase in March sales volumes and the average realized selling price resulted in a higher accounts receivable balance relative to December 31, 2006. Comparatively in the first quarter of 2006, cash from operating activities increased by $46 million from changes in non-cash working capital, mainly due to lower accounts receivable at quarter-end relative to December 31, 2005.
Three Months Ended March 31 ($ per bbl) 2007 2006 $ Change ------------------------------------------------------------------------- Net realized selling price 68.69 70.24 (1.55) Operating costs (23.56) (40.26) 16.70 Crown royalties (9.58) (0.67) (8.91) ------------------------------------------------------------------------- Netback 35.55 29.31 6.24 Non-production costs (1.78) (3.76) 1.98 Administration and insurance (0.65) (1.07) 0.42 Interest, net (2.48) (3.69) 1.21 Depletion, depreciation and accretion (8.49) (7.46) (1.03) Foreign exchange gain (loss) 0.79 (0.25) 1.04 Current and future income tax recovery (expense) 3.74 0.41 3.33 ------------------------------------------------------------------------- (8.87) (15.82) 6.95 ------------------------------------------------------------------------- Net income per barrel 26.68 13.49 13.19 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Sales volumes (MMbbls) 9.8 6.7 3.1 -------------------------------------------------------------------------
Incremental Stage 3 production, less turnaround and maintenance activity, and a larger Syncrude working interest in the first quarter relative to the prior year contributed to a $201 million increase in revenues (after crude oil purchases and transportation expense) to $674 million in 2007 compared to 2006. Net income and cash from operating activities also benefited from a $40 million reduction in operating costs quarter-over-quarter. Operating costs were $23.56 per barrel in the first quarter of 2007, a decrease of $16.70 per barrel compared to the same period in 2006; however, partially offsetting the increase in revenues and reduction in operating costs was an $89 million increase to Crown royalties expense relative to the same quarter of 2006. Crown royalties amounted to $94 million, or $9.58 per barrel, in the first quarter of 2007, compared to $5 million, or $0.67 per barrel, in the same period of 2006. The higher royalties reflect both the higher Crown royalty rate and the increase in net revenue in the current year.
Also reducing net income in the first quarter of 2007 relative to the same period of 2006 was a $32 million increase to depreciation, depletion and accretion expense. An increase in the per barrel depreciation and depletion ("D&D") rate, combined with higher production volumes, resulted in the quarter-over-quarter increase in this non-cash expense; however, offsetting this decrease to net income was a $33 million increase to future income tax recovery mainly as a result of changes in temporary differences of the Trust's subsidiary in the first quarter of 2007.
Non-GAAP Financial Measures
In this report, we may refer to the Trust's free cash flow as well as cash from operating activities per Unit, which are measures that do not have any standardized meaning under Canadian generally accepted accounting principles ("GAAP"). Free cash flow is derived from cash from operating activities reported on the Trust's Consolidated Statement of Cash Flows, less capital expenditures and reclamation trust contributions in the period. In management's opinion, free cash flow is a key indicator of the Trust's ability to repay debt and pay distributions to its Unitholders. Free cash flow may not be directly comparable to similar measures presented by other companies or trusts.
Revenues after Crude Oil Purchases and Transportation Expense Three Months Ended March 31 ($ millions) 2007 2006 Variance ------------------------------------------------------------------------- Sales revenue(1) $ 781 $ 509 $ 272 Crude oil purchases (99) (34) (65) Transportation expense (10) (9) (1) ------------------------------------------------------------------------- 672 466 206 Currency hedging gains(1) 2 7 (5) ------------------------------------------------------------------------- $ 674 $ 473 $ 201 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Sales volumes (MMbbls) 9.8 6.7 3.1 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) The sum of sales revenue and currency hedging gains equals Revenues on the Trust's Consolidated Statement of Income and Comprehensive Income. ($ per barrel) ------------------------------------------------------------------------- Realized selling price before hedging(2) $ 68.47 $ 69.17 $ (0.70) Currency hedging gains 0.22 1.07 (0.85) ------------------------------------------------------------------------- Net realized selling price $ 68.69 $ 70.24 $ (1.55) ------------------------------------------------------------------------- ------------------------------------------------------------------------- (2) Sales revenue, after and transportation expense divided by SSB sales volumes, net of purchased crude oil volumes.
Sales revenue after crude oil purchases and transportation expense and before currency hedging in the first quarter of 2007 relative to the comparable quarter of 2006 reflects the 46 per cent increase in sales volumes quarter-over-quarter. The Trust's larger Syncrude ownership and incremental production from the Stage 3 facilities during the first quarter of 2007, together with the lower production in the prior year's quarter due to extensive turnaround and maintenance activity, resulted in the higher 2007 sales volumes.
While volumes increased significantly relative to 2006, the increase to revenues was partially reduced by a decrease in our realized SSB selling price, which averaged $68.47 per barrel, before currency hedging gains, in the first quarter of 2007, compared to $69.17 per barrel in the same period of 2006. While our average realized selling price did not change significantly from the prior year, the underlying elements of the prices varied more significantly quarter-over-quarter. West Texas Intermediate ("WTI") prices, which our SSB product pricing tends to follow, averaged approximately US$58 per barrel in 2007, a decrease of over $5 per barrel compared to the same quarter of 2006. This decrease was offset by a weakening of the Canadian dollar relative to the U.S. dollar, which averaged $0.85 US/Cdn in the first quarter of 2007 compared to $0.87 US/Cdn in the same quarter of 2006, and a significant improvement in our pricing differentials relative to WTI. Our SSB product realized a weighted-average discount of $0.08 per barrel compared to average Canadian dollar WTI in the first quarter of 2007 versus a discount of $4.39 per barrel in the same period in 2006. The improvement in differential quarter-over-quarter highlights the relatively weak differential reported in the first quarter of 2006. The large discount realized in that period was driven by both reduced product demand as a result of refinery outages, and increased supply of light crude oil resulting from a pipeline reconfiguration. As well, pipeline restrictions limited access to extended markets placing downward pressure on SSB prices in the first quarter of 2006. By comparison, the first quarter of 2007 reflected a tighter supply/demand balance as a result of lower than anticipated supply and new demand. The differential can change quickly between a premium or a discount depending on the synthetic supply/demand dynamics in the marketplace and pipeline availability for transporting the crude oil.
Operating costs Three Months Ended March 31 2007 2006 ------------------------------------------------------------------------- $/bbl $/bbl $/bbl $/bbl Bitumen SSB Bitumen SSB ------------------------------------------------------------------------- Bitumen Costs(1) Overburden removal 1.69 3.24 Bitumen production 8.46 9.47 Purchased energy(3) 2.72 3.90 ------------------------------------------------------------------------- 12.87 15.39 16.61 19.21 ------------------------------------------------------------------------- Upgrading Costs(2) Bitumen processing and upgrading 4.81 5.33 Turnaround and catalysts 1.02 7.49 Purchased energy(3) 2.87 3.99 ------------------------------------------------------------------------- 8.70 16.81 ------------------------------------------------------------------------- Other and research 0.04 3.51 Change in treated and untreated inventory (0.55) 0.93 ------------------------------------------------------------------------- Total Syncrude operating costs 23.58 40.46 ------------------------------------------------------------------------- Canadian Oil Sands adjustments(4) (0.02) (0.20) ------------------------------------------------------------------------- Total operating costs 23.56 40.26 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (thousands of barrels per day) Bitumen SSB Bitumen SSB ------------------------------------------------------------------------- Syncrude production volumes 354 296 237 205 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Bitumen costs relate to the removal of overburden, oil sands mining, bitumen extraction and tailings dyke construction and disposal costs. The costs are expressed on a per barrel of bitumen production basis and converted to a per barrel of SSB based on the yield of SSB from the processing and upgrading of bitumen. (2) Upgrading costs include the production and ongoing maintenance costs associated with processing and upgrading of bitumen to SSB. It also includes the costs of major refining equipment turnarounds and catalyst replacement. (3) Natural gas costs averaged $6.99/GJ and $7.42/GJ in the first quarters of 2007 and 2006, respectively. (4) Canadian Oil Sands' adjustments mainly pertain to Syncrude-related pension costs, property insurance costs, site restoration costs, as well as the inventory impact of moving from production to sales as Syncrude reports per barrel costs based on production volumes and we report based on sales volumes. Three Months Ended March 31 ($/bbl of SSB) 2007 2006 ------------------------------------------------------------------------- Production costs 17.43 31.76 Purchased energy 6.13 8.50 ------------------------------------------------------------------------- Total operating costs 23.56 40.26 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (GJs/bbl of SSB) ------------------------------------------------------------------------- Purchased energy consumption 0.88 1.15 -------------------------------------------------------------------------
During planned and unplanned shutdowns, Syncrude directs resources towards other activities, and thus, the operation is less efficient with lower production and higher operating costs. This is evident in the decrease in overburden removal costs and bitumen production of about $3 per barrel of SSB in the first quarter of 2007 compared to the same 2006 period. The Stage 3 project had not yet commenced production in the first quarter of 2006 and Syncrude utilized the additional Stage 3 staff and equipment that it had in place to remove additional overburden. These additional overburden removal costs were expensed as incurred, resulting in higher bitumen costs on a per barrel basis. Lower turnaround and maintenance activity in the first quarter of 2007 relative to the comparable 2006 quarter also reduced operating costs by over $6 per barrel. While there was unplanned maintenance work on Coker 8-2 and repairs to one of the hydrotreaters in the first quarter of 2007, the prior year's first quarter had more extensive turnarounds, including Coker 8-1.
Also contributing to a reduction in per barrel production costs was a decrease in the value of Syncrude's long-term incentive plan of almost $4 per barrel. A portion of Syncrude's long-term incentive compensation is based on the market return performance of several Syncrude owners' shares/units, which was not as strong in the first quarter of 2007 relative to the same period in 2006.
Purchased energy costs fell by $2.37 per barrel in the first quarter of 2007 due to lower natural gas prices and energy consumption per barrel compared to the same quarter of 2006. In the first quarters of 2007 and 2006, natural gas prices averaged $6.99 and $7.42 per gigajoule, respectively. Energy consumption per barrel decreased by 23 per cent in 2007 due to higher maintenance activity and commissioning of Stage 3 units during the 2006 first quarter. Natural gas consumption rises during periods of maintenance activity, particularly during coker turnarounds as process heat integration within the facilities declines, requiring additional natural gas purchases during unit outages. In addition, commissioning of individual Stage 3 units in 2006 raised purchased energy consumption as these units were brought into service without an offsetting increase in SSB production.
Non-production costs
Non-production costs consist primarily of development expenditures relating to capital programs, which are expensed, such as: commissioning costs, pre-feasibility engineering, technical and support services, research and development ("R&D"), and regulatory and stakeholder consultation expenditures. Accordingly, non-production costs can vary depending on the number of projects on-going and the status of the projects. In the first quarter of 2007, non-production costs totalled $18 million, a decrease of $7 million from the same quarter in 2006, mainly reflecting the completion of the Stage 3 project. Stage 3 contributed $12 million of commissioning and start-up costs in the first quarter of 2006.
Crown Royalties
Under Alberta's generic Oil Sands Royalty, the Crown royalty is calculated as the greater of one per cent of gross plant gate revenue before hedging, or 25 per cent of net revenues, calculated as gross plant gate revenue before hedging, less allowed Syncrude operating, non-production and capital costs. Crown royalties increased by $89 million to $94 million, or $9.58 per barrel, in the first quarter of 2007 from $5 million, or $0.67 per barrel, in the comparable 2006 quarter. The increase in 2007 Crown royalties reflects both the shift to the higher royalty rate, which occurred in the second quarter of 2006, and higher net revenues as a result of a larger Syncrude working interest and incremental Stage 3 production volumes. The shift to the higher rate is triggered once a project reaches payout by recovering its costs and a return allowance equal to a Government of Canada long-term bond rate. As a result of robust crude oil prices, which increased revenues from Syncrude's base plant, payout of the Stage 3 expansion was accelerated and resulted in Syncrude moving to the higher Crown royalty rate in the second quarter of 2006.
Depreciation, depletion and accretion expense Three Months Ended March 31 ($ millions) 2007 2006 ------------------------------------------------------------------------- Depreciation and depletion expense $ 80 $ 48 Accretion expense 2 2 ------------------------------------------------------------------------- $ 82 $ 50 -------------------------------------------------------------------------
D&D expense for the first quarter of 2007 rose by $32 million compared to the same quarter of 2006, reflecting an increase in production volumes and a higher per barrel D&D rate. The larger production volumes in 2007 are attributable to the larger Syncrude ownership, incremental Stage 3 production volumes, and less turnaround and maintenance activity in the quarter relative to the prior year.
We revised our per barrel D&D rate in the first quarter of 2007 to reflect the additional assets and reserves acquired in the January acquisition of a 1.25 per cent working interest, as well as the updated reserve and future development cost estimates provided for in the Trust's December 31, 2006 independent reserves report. The D&D rate for 2007 is approximately $8 per barrel, an increase of about $1 per barrel from prior year as a result of the acquisition and higher future development cost estimates, which reflect a higher cost environment relative to the prior year.
Foreign exchange
Foreign exchange gains/losses are primarily the result of revaluations of our U.S. dollar denominated long-term debt caused by fluctuations in U.S. and Canadian dollar exchange rates. In addition, other foreign exchange gains/losses are created through the revaluation of cash, accounts receivable and payable balances denominated in U.S. dollars.
In the first quarter of 2007, Canadian Oil Sands recorded a $7 million foreign exchange gain compared to a $2 million loss in the same quarter of 2006. The revaluation of our U.S. dollar denominated debt resulted in a non-cash foreign exchange gain of $11 million, reflecting a strengthening of the Canadian dollar to $0.87 US/Cdn on March 31, 2007 from $0.86 US/Cdn at December 31, 2006. By comparison, the Canadian dollar weakened slightly on March 31, 2006 compared with December 31, 2005, resulting in an unrealized foreign exchange loss of $1 million in the first quarter of 2006.
Future Income Tax
In the first quarter of 2007, Canadian Oil Sands reported a future income tax recovery of $38 million, which was an increase of $33 million from the same period in 2006. The larger recovery primarily reflects decreases to temporary differences between the book and tax basis of the Trust's subsidiary's assets and liabilities.
Also in the first quarter of 2007, Canadian Oil Sands recorded an additional future income tax liability on its Consolidated Balance Sheet totalling $327 million, with a corresponding increase to property, plant and equipment, as a result of the 1.25 per cent working interest acquisition on January 2 and the subsequent dissolution of the partnership in which the working interest was held. The future income tax liability represents the temporary differences between the book values of the net assets and the related tax pools acquired, tax-effected at the substantively enacted rates expected to be in effect when such temporary differences reverse. Details of the acquisition and related future income tax adjustments are included in Note 4 to the unaudited Consolidated Financial Statements for the quarter ending March 31, 2007.
As of the date of this MD&A, the proposed taxation of income trusts as originally announced by the federal government late in 2006 is not yet legislation. As such, Canadian Oil Sands has not recorded future income taxes related to the Trust. As stated in the Trust's 2006 annual report, we anticipate recording a future income tax expense and corresponding increase to future income tax liability of approximately $0.6 billion related to the Trust's taxable temporary differences if and when the new trust tax rules are substantively enacted.
Capital expenditures
With the completion of Syncrude's Stage 3 project in 2006, Canadian Oil Sands' expansion capital expenditures have been reduced significantly and, as such, current capital costs are essentially all related to sustaining capital. The Trust defines expansion capital expenditures as the costs incurred to grow the productive capacity of the operation, such as the Stage 3 project, while sustaining capital is effectively all other capital and includes the costs required to maintain the current productive capacity of Syncrude's mines and upgraders. Sustaining capital may fluctuate considerably year-to-year due to timing of equipment replacement and other factors.
In the first quarter of 2007, capital expenditures totalled $33 million, a reduction of $104 million from the same quarter of 2006. In 2007, approximately $15 million related to the Syncrude Emissions Reduction ("SER") project with the remaining $18 million pertaining to the maintenance of Syncrude's existing plant and facilities, all of which are considered sustaining capital. Comparatively, in the same period of 2006, approximately 71 per cent of capital expenditures pertained to the Stage 3 expansion. Sustaining capital expenditures on a per barrel basis were approximately $3.50 and $6 in the first quarters of 2007 and 2006, respectively.
The SER project is being undertaken to retrofit technology into the operation of Syncrude's original two cokers to significantly reduce total sulphur dioxide and other emissions. Expenditures on the SER project are expected to total approximately $772 million, or $284 million net to the Trust based on its 36.74 per cent working interest. The Trust's share of the SER project expenditures incurred to date, including amounts expensed, is approximately $51 million, with the remaining costs to be incurred in the next four years to coordinate with equipment turnaround schedules.
We estimate sustaining capital expenditures will average $6 per barrel, including the SER project, over the next four years. Excluding major sustaining capital expenditure projects which occur from time to time, such as the SER project, we anticipate average sustaining capital expenditures of approximately $5 per barrel, or $240 million annually, net to the Trust, based on annual Syncrude productive capacity of 128 million barrels, or 47 million barrels net to the Trust.
Canadian Oil Sands is in the process of selling the remaining conventional properties it acquired in 2006 from Canadian Arctic Gas Ltd. The properties are reflected on the Trust's Consolidated Balance Sheet under the heading "Assets held for sale". The conventional properties which the Trust still owned at March 31, 2007 did not generate material income in the first quarter of 2007.
CHANGE IN ACCOUNTING POLICIES
Effective January 1, 2007, the Trust prospectively adopted the Canadian Institute of Chartered Accountant's ("CICA") Handbook Section 3855, Financial Instruments - Recognition and Measurement; Section 3865, Hedges; Section 1530, Comprehensive Income and Section 3861, Financial Instruments - Disclosure and Presentation. The impacts of adopting the new standards are reflected in the Trust's current quarter results, and prior year comparative financial statements have not been restated. While the new rules resulted in changes to how the Trust accounts for its financial instruments, there were no material impacts on the Trust's current quarter financial results. For a description of the new accounting rules and the impact on the Trust's financial statements of adopting such rules, including the impact on the Trust's deferred financing charges, long-term debt, and deferred currency hedging gains, see Note 2 to the unaudited Consolidated Financial Statements for the quarter ending March 31, 2007.
LIQUIDITY AND CAPITAL RESOURCES March 31 December 31 ($ millions) 2007 2006 ------------------------------------------------------------------------- Long-term debt $ 1,543 $ 1,644 Cash and cash equivalents (65) (353) ------------------------------------------------------------------------- Net debt $ 1,478 $ 1,291 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Unitholders' equity $ 4,339 $ 3,956 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Total capitalization(1) $ 5,817 $ 5,247 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Net debt plus Unitholders' equity Net debt to total capitalization (%) 25 25 ------------------------------------------------------------------------- -------------------------------------------------------------------------
In the first quarter of 2007, Canadian Oil Sands made a $237.5 million cash payment and issued 8.2 million Units for $237.5 million to Talisman as consideration for the purchase of Talisman's 1.25 per cent indirect Syncrude working interest. The Trust had built cash at the end of December 2006 in anticipation of paying Talisman on January 2, 2007. The acquisition was followed by the maturity of $195 million of medium term notes on January 15, 2007, which the Trust refinanced by drawing on its $800 million operating credit facility. During the quarter, Canadian Oil Sands paid down $75 million of the amounts drawn on the facility, leaving $120 million drawn at March 31, 2007. As discussed in Note 2 to the unaudited Consolidated Financial Statements, the Trust recorded a $16 million reduction to its long-term debt as a result of adopting the new financial instruments accounting standards. The reduction reflected the reclassification of deferred financing charges against long-term debt, which were previously recorded in other assets on the Trust's Consolidated Balance Sheet. Overall, including an unrealized foreign exchange gain of $11 million, the Trusts' long-term debt decreased by $101 million to $1.5 billion at quarter-end, while net debt increased $187 million to $1.5 billion reflecting the reduced cash balance. As at March 31, 2007, the Trust's unutilized credit facilities amounted to $704 million, including amounts drawn on its $40 million revolving term facility.
The Units issued from treasury increased Unitholders' equity. However, as the Units were issued directly to Talisman, there was no cash impact. The investing section of the Trust's cash flow statement, therefore only reflects the cash paid to Talisman for the additional working interest less cash balances acquired. The remaining growth in Unitholders' equity is primarily attributable to net income of $262 million exceeding distributions of $144 million paid in the quarter.
The $202 million of cash generated by the Trust's operating activities in the first quarter of 2007 was more than adequate to pay distributions of $144 million, or $0.30 per Unit, on February 28 and to fund $40 million of investing activities, excluding the acquisition of Talisman's Syncrude interest. As previously indicated, the Trust suspended its Premium Distribution, Distribution Reinvestment and Optional Unit Purchase Plan ("DRIP") as of January 31, 2007 and, as such, the DRIP did not provide additional equity financing in the quarter. In the same quarter of 2006, cash from operating activities of $187 million was insufficient to fund distributions of $93 million, or $0.20 per Unit, and investing activities of $165 million.
The Trust's free cash flow rose $119 million to total $168 million, or $0.35 per Unit, in the first quarter of 2007 compared to the same period of 2006. The increase primarily reflects the reduction in the Trust's capital expenditures in 2007 with the completion of Stage 3 in 2006.
A Unitholder distribution schedule pertaining to the quarter ended March 31 is included in Note 10 to the unaudited Consolidated Financial Statements. The Trust historically has used debt and equity financing to the extent that cash from operating activities was insufficient to fund distributions, capital expenditures, mining reclamation trust contributions, acquisitions and working capital changes from financing and investing activities.
On April 25, 2007, the Trust declared a distribution of $0.40 per Unit for total distributions of $192 million. The distribution will be paid on May 31, 2007 to Unitholders of record on May 8, 2007. Canadian Oil Sands' Board approved a 33 per cent increase to the Trust's second quarter distribution based on our current outlook, as outlined later in this MD&A, and net debt slightly lower than our target of $1.6 billion. The Trust had previously indicated it intends to move to fuller payout of its free cash flow while targeting a net debt level of about $1.6 billion. The Trust believes this net debt target maintains its strong balance sheet allowing it to remain unhedged on crude oil production, and providing the capacity to fund growth opportunities. The Trust's actual net debt will fluctuate around this level as factors such as crude oil prices and Syncrude operational performance, vary from our assumptions.
Debt covenants do not specifically limit the Trust's ability to pay distributions and are not expected to influence the Trust's liquidity in the foreseeable future. Aside from the typical covenants relating to restrictions on Canadian Oil Sands' ability to sell all or substantially all of its assets or to change the nature of its business, the most restrictive financial covenant limits total debt-to-total book capitalization at an amount less than 0.55 to 1.0. With a current net debt book capitalization of approximately 25 per cent, a significant increase in debt or decrease in equity would be required to negatively impact the Trust's financial flexibility, and at the current time, we do not anticipate such changes.
In determining the Trust's distributions, Canadian Oil Sands considers funding for its significant operating obligations, which are included in cash from operating activities. Such obligations include the Trust's share of Syncrude's pension and reclamation funding, which amounted to approximately $8 million in each of the first quarters of 2007 and 2006 and approximated the related expense for both pension and reclamation of $10 million in each of the same quarters. We are anticipating an increase of $5 million in each of the next five years in the Trust's funding requirements related to its share of Syncrude's pension plan funding. The increase is based on preliminary estimates from Syncrude's December 31, 2006 actuarial valuation, which will be completed during the second quarter of 2007. With regards to reclamation, we do not anticipate incurring significant increases in reclamation funding requirements for many years given the long reserve life of the Syncrude resource. We do not expect a significant difference in our actual reclamation funding in 2007 over amounts paid in 2006, which totalled approximately $7 million, including amounts contributed to our mining reclamation trust account.
UNITHOLDERS' CAPITAL AND UNIT TRADING ACTIVITY
Canadian Oil Sands Units trade on the Toronto Stock Exchange under the symbol COS.UN. The Trust had a market capitalization of approximately $14 billion with 479 million Units outstanding and a closing price of $28.26 per Unit on March 31, 2007.
First Canadian Oil Sands Trust - Quarter March February January Trading Activity 2007 2007 2007 2007 ------------------------------------------------------------------------- Unit price High $ 33.00 $ 29.20 $ 30.39 $ 33.00 Low $ 25.09 $ 25.09 $ 26.72 $ 26.67 Close $ 28.26 $ 28.26 $ 27.30 $ 30.07 Volume of Trust units traded (millions) 101.3 34.6 32.6 34.1 Weighted average Trust units outstanding (millions) 479.0 479.1 479.1 478.8 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Contractual Obligations and Commitments
As of March 31, 2007, the Trust's share of Syncrude's capital expenditure commitments increased by $42 million, which are to be incurred over the next two years. As discussed previously, Syncrude's pension plan actuarial valuation for December 31, 2006 is to be completed in the second quarter of 2007, at which time the updated pension funding commitments will be provided. There have been no other significant changes to the Trust's contractual obligations and commitments from our 2006 year-end disclosure, other than reductions to the capital expenditure and various payment obligation commitments as a result of expenditures incurred in the first quarter and changes in long-term debt.
Regarding the Management Services Agreement previously announced on November 1, 2006, the Syncrude Joint Venture owners have approved the recommendations of an Opportunity Assessment Team ("OAT"). Since late 2006, the OAT comprised of experts from Syncrude, Imperial, ExxonMobil and the other Joint Venture owners has been examining possibilities for improvement at Syncrude. In April, the OAT presented their specific recommendations, which were approved by the Syncrude owners. Such approval was required to proceed with implementation of the Management Services Agreement.
The implementation phase will involve the secondment of Imperial and ExxonMobil personnel and perhaps personnel from other owner companies to Syncrude. The secondees will work closely with Syncrude management and staff to assist in the implementation of the Opportunity Assessment Team's recommendations and Imperial/ExxonMobil's global best practices and systems. To lead this effort, Mr. Tom Katinas has been appointed to the role of President and Chief Executive Officer of Syncrude Canada effective May 1, 2007. Mr. Katinas succeeds current CEO, Charles Ruigrok. Mr. Ruigrok will work with Mr. Katinas to ensure a smooth transition of responsibilities.
FINANCIAL RISK MANAGEMENT Crude Oil Price Risk
As Canadian Oil Sands did not have any crude oil price hedges in 2007 and 2006, revenues were not impacted by crude oil hedging gains or losses and benefited fully from strong WTI prices. As at March 31, 2007 and, based on current expectations, the Trust remains unhedged on its crude oil price exposure.
However, it may hedge its crude oil production in the future as part of growth financing strategies.
Foreign Currency Hedging
As at March 31, 2007, we had $15 million of U.S. dollars hedged at an average U.S. dollar exchange rate of $0.69 US/Cdn. At the present time, we do not intend to increase our currency hedge positions. However, the Trust may hedge foreign exchange rates in the future, depending on the business environment and growth opportunities.
Interest Rate Risk
Canadian Oil Sands' net income and cash from operating activities are impacted by interest rate changes based on the amount of floating rate debt outstanding. At March 31, 2007, we had $120 million drawn on our credit facilities that bear interest at a floating rate based on bankers' acceptances plus a credit spread. The Trust's other floating rate debt was repaid in January.
With the adoption of the new financial instrument accounting rules and the decision to no longer apply hedge accounting, all of the Trust's financial risk management activities are now recorded on its Consolidated Balance Sheet at fair value. The Trust did not have any significant positions outstanding at March 31, 2007.
FOREIGN OWNERSHIP
Based on information from the statutory declarations by Unitholders, we estimate that, as of February 8, 2007, approximately 33 per cent of our Unitholders are non-Canadian residents with the remaining 67 per cent being Canadian residents. Canadian Oil Sands' Trust Indenture provides that not more than 49 per cent of its Units can be held by non-Canadian residents.
ANNOUNCED CHANGES TO ACCELERATED CAPITAL COST ALLOWANCE RULES
On March 19, 2007, the federal government announced, as part of its 2007 budget, plans to phase out accelerated capital cost allowance ("ACCA") for oil sands projects. The ACCA phase-out does not affect the deductibility of costs for oil sands projects but does affect the timing of the deductibility. Currently, most machinery, equipment and structures used to produce income from an oil sands project are eligible for the Class 41 capital cost allowance ("CCA") at a rate of 25 per cent per annum on a declining balance basis. In addition to this regular deduction, an acceleration of the CCA up to income from an oil sands project was available for eligible assets acquired before the beginning of commercial production for major expansions (i.e. greater than 25 per cent) or for the portion of investment expenditures in excess of five per cent of the gross revenue for the year from the project. The acceleration remains available for our existing eligible pools, which amount to approximately 80 per cent of our tax carry forward balances at December 31, 2006. However, acceleration on new Class 41 costs will be phased out gradually over the 2011 to 2015 period. As the proposed phase-out of ACCA will effectively delay the timing of deductibility of future capital costs for income tax purposes, it has a negative impact on the economics of new projects or major expansions.
ALBERTA ANNOUNCES LEGISLATION TO REDUCE GREENHOUSE GAS EMISSIONS
On March 8, 2007, the Alberta government introduced legislation to reduce greenhouse gas emission intensity. Bill 3 states that facilities emitting more than 100,000 tonnes of greenhouse gases a year must reduce their emissions intensity by 12 per cent over the average emissions levels of 2003, 2004 and 2005; if they are not able to do so, these facilities will be required to pay $15 per tonne for every tonne above the 12 per cent target, beginning July 1, 2007. The payments will be deposited into an Alberta-based technology fund that will be used to develop infrastructure to reduce emissions or to support research into innovative climate change solutions. Large emitters also have the option of investing in projects outside of their operations that reduce or offset emissions on their behalf, providing these projects are Alberta-based and verified by a third party that the emission reductions are real.
The new legislation will apply to the Syncrude project but until all of the specifics regarding its implementation are provided it is difficult to provide an estimate of the cost impact. The federal government also is anticipated to announce legislation to reduce greenhouse gas emissions; however, at this time no information has been provided regarding the specifics of such legislation.
REVIEW OF ALBERTA OIL SANDS ROYALTY
As previously indicated, the Government of Alberta is examining Alberta's royalty and tax regime. In February 2007, the Alberta government appointed an independent panel of experts to conduct a review focusing on all aspects of the royalty system, including oil sands, conventional oil and gas, and coalbed methane. A final report with recommendations will be presented to the Minister of Finance by August 31, 2007. Canadian Oil Sands intends to participate in the process by making a formal presentation at the Royalty Review Panel's public meeting in Fort McMurray on June 4, 2007. At this time, Canadian Oil Sands cannot determine the potential impact of any changes to the royalty rate on its operations.
2007 OUTLOOK
Our single point e
