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Canadian Oil Sands Trust announces 2008 first quarter results and a quarterly distribution increase to $1.00 per Trust unit
(Canada Newswire English Via Acquire Media NewsEdge) Attention Business/Financial Editors
All financial figures are unaudited and in Canadian dollars unless
otherwise noted.
TSX - COS.UN
CALGARY, April 28 /CNW/ - Canadian Oil Sands Trust ("Canadian Oil Sands", the "Trust" or "we") today announced first quarter 2008 results and a 33 per cent increase in the Trust's quarterly distribution to $1.00 per Trust unit ("Unit") for Unitholders of record on May 16, 2008, payable on May 30, 2008. First quarter 2008 cash from operating activities more than doubled to $441?million ($0.92 per Unit), compared to the first quarter of 2007. Net income in the first quarter of 2008 increased to $298 million ($0.62 per Unit) from $262?million ($0.55 per Unit) last year.
The increase in both cash from operating activities and net income is largely attributable to a 46 per cent increase in the net realized selling price for our Synthetic crude oil during the first quarter of 2008 compared with the same period of 2007. Daily average sales volumes declined about nine per cent quarter-over-quarter, averaging about 99,200 barrels per day in 2008. Also reducing the positive contribution of higher crude oil prices were increases in operating costs and Crown royalties in the first quarter of 2008 over the same period of 2007.
"We have further increased our distribution, reflecting higher crude oil prices, lower capital spending between our expansion projects and our objective to recalibrate our capital structure," said Marcel Coutu, President and Chief Executive Officer. "Over time, we also expect to benefit from production increasing to Stage 3 design capacity, notwithstanding the operational challenges of this past quarter and the heavy maintenance schedule this year. Canadian Oil Sands is well positioned with our distributions until trust taxation becomes effective in 2011; however, our Unitholders must now appreciate that with our unhedged production, our cash from operating activities is very sensitive to oil prices, increasing the potential variability of distributions going forward."
During the first quarter of 2008, Syncrude operations were negatively impacted by a weather-related outage and lower than anticipated production following the outage. As well, reliability challenges in bitumen production limited feed to the upgrader. Reflecting the loss of production volumes in the first quarter and moderated expectations for the remainder of the year, Canadian Oil Sands reduced its Outlook for annual Syncrude production to 108 million barrels with a range of 105 to 112 million barrels (net to the Trust, equivalent to 40 million barrels with a range of 39 to 41 million barrels). More information on the Trust's Outlook is provided in the MD&A section of its first quarter report and the April 28, 2008 guidance document, which is available on the Trust's web site at www.cos-trust.com under "investor information".
Effective April 28, 2008Ms. Susan Evans will retire from Canadian Oil Sands' board of directors. Ms. Evans has demonstrated dedication and leadership in the governance of the Trust over her 12 year tenure as a board member, being one of the original board members of Athabasca Oil Sands Trust (the predecessor of today's Trust). Her contribution and commitment to the Trust is deeply appreciated and will be missed by the board and management of Canadian Oil Sands.
Canadian Oil Sands Trust's Annual and Special Meeting of Unitholders will be held on April 28, 2008 at 2:30 p.m. Mountain Standard Time in The Metropolitan Conference Centre, The Grand Lecture Theatre, 333 Fourth Avenue SW, Calgary, Alberta. A live audio Web cast of the meeting will be available on our Web site at http://www.cos-trust.com/investor/invPresent.aspx. An archive of the Web cast will be available approximately one hour following the meeting.
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CANADIAN OIL SANDS TRUST
Highlights
Three Months Ended
March 31
(millions of Canadian dollars, except Trust unit
and volume amounts) 2008 2007
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Net Income $ 298 $ 262
Per Trust unit - Basic $ 0.62 $ 0.55
Per Trust unit - Diluted $ 0.62 $ 0.54
Cash from Operating Activities $ 441 $ 202
Per Trust unit $ 0.92 $ 0.42
Unitholder Distributions $ 360 $ 144
Per Trust unit $ 0.75 $ 0.30
Sales Volumes (1)
Total (MMbbls) 9.0 9.8
Daily average (bbls) 99,181 108,981
Operating Costs per barrel $ 35.93 $ 23.56
Net Realized SCO Selling Price per barrel
Realized SCO selling price before hedging $ 100.31 $ 68.47
Currency hedging gains 0.10 0.22
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Net realized SCO selling price $ 100.41 $ 68.69
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West Texas Intermediate (average $US per barrel)(2) $ 97.82 $ 58.23
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(1) The Trust's sales volumes differ from its production volumes due to
changes in inventory, which are primarily in-transit pipeline
volumes, and are net of purchased crude oil volumes.
(2) Pricing obtained from Bloomberg.
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MANAGEMENT'S DISCUSSION AND ANALYSIS
The following Management's Discussion and Analysis ("MD&A") was prepared as of April 28, 2008 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, 2008 and March 31, 2007, as well as the audited consolidated financial statements and MD&A of the Trust for the year ended December 31, 2007.
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 MD&A include, but are not limited to, statements with respect to: the expected tax rate by the federal government on the Trust in 2011; the expected structure to be assumed given the Federal government's tax changes effective in 2011; the expected timeframe that current tax pools will allow Canadian Oil Sands to shelter income post-2010; the plan to move to fuller payout of cash from operating activities; the belief that distributions will exceed net income at times over the next several years; expectations regarding future distribution levels; the cost estimate for the SER project and the expectation that the SER project will significantly reduce total sulphur dioxide and other emissions; the expected impact on the Trust from announced changes by the Alberta government regarding its royalty regime; any expectations regarding the enforceability of legal rights; the expected impact of any current and future environmental legislation or changes to the Crown royalties regime; the expectation that there will not be any material funding increases relative to Syncrude's future reclamation costs or pension funding for the next several years; the belief that the Trust will not be restricted by its net debt to total capitalization financial covenant; the expectation that no crude oil hedges will be entered into in the future; the expected realized selling price, which includes the anticipated differential to WTI, to be received in 2008 for Canadian Oil Sands' product; the potential amount payable in respect of any future income tax liability; the plans regarding future expansions of the Syncrude project and in particular all plans regarding Stage 4 development; the level of energy consumption in 2008 and beyond; capital expenditures for 2008; and the anticipated cost and completion date for the SER project; the level of natural gas consumption in 2008 and beyond; the expected price for crude oil and natural gas in 2008; the expected production, revenues and operating costs for 2008; and 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. 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 impacts of regulatory changes especially as such relate to royalties, taxation, and environmental charges; 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. No assurance can be given that the final legislation implementing the federal tax changes regarding income trusts will not be further changed in a manner which adversely affects the Trust and its Unitholders. 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 2008, crude oil production from the Syncrude Joint Venture ("Syncrude") totalled 24.3 million barrels, or an average of about 266,800 barrels per day, compared with 26.6 million barrels, or approximately 296,000 barrels per day, during the same period of 2007. Net to the Trust, production totalled 8.9 million barrels in the first quarter of 2008 based on our 36.74 per cent working interest compared with 9.8 million barrels in 2007.
Production during the first quarter of 2008 was about five million barrels less than the 29 million barrels anticipated for the quarter in the outlook Canadian Oil Sands provided on January 30, 2008. Production was halted for a few days following disruption of several operating units, primarily due to extremely cold weather conditions early in the quarter. Syncrude's efforts over the remainder of the quarter were focused on re-establishing normal operations with volumes recovering only gradually over the period. Bitumen production and extraction also were constrained by the cold weather, unplanned outages and maintenance activity. In comparison, first quarter 2007 production was reduced by unplanned maintenance on Coker 8-2 and constrained production rates from Coker 8-3.
Operating costs increased to $35.93 per barrel in the first quarter of 2008, up $12.37 per barrel from the same quarter last year (see the "Operating costs" section of this MD&A for further discussion).
Syncrude's facilities have the design capability to produce approximately 375,000 barrels per day when operating at full capacity under optimal conditions and with no downtime for maintenance or turnarounds. This daily production capacity is referred to as "barrels per stream day". However, under normal operating conditions, scheduled downtime is required for maintenance and turnaround activities and unscheduled downtime will occur as a result of operational and mechanical problems, unanticipated repairs and other slowdowns. When allowances for such downtime are included, the daily design productive capacity of Syncrude's facilities is approximately 350,000 barrels per day on average and is referred to as "barrels per calendar day". All references to Syncrude's productive capacity in this report refer to barrels per calendar day, unless stated otherwise.
The Trust's production volumes differ from its sales volumes due to changes in inventory, which are primarily in-transit pipeline volumes. These in-transit volumes vary with current production. The impact of Syncrude's 2008 operations on Canadian Oil Sands' financial results is more fully discussed later in this MD&A.
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SUMMARY OF QUARTERLY RESULTS
($ millions, except
per Trust Unit and 2008 2007
volume amounts) Q1 Q4 Q3 Q2 Q1
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Revenues(1) $ 907 $ 950 $ 936 $ 690 $ 674
Net income (loss) $ 298 $ 515 $ 361 $ (395) $ 262
Per Trust Unit,
Basic $ 0.62 $ 1.07 $ 0.75 $ (0.82) $ 0.55
Per Trust Unit,
Diluted $ 0.62 $ 1.07 $ 0.75 $ (0.82) $ 0.54
Cash from operating
activities $ 441 $ 367 $ 484 $ 324 $ 202
Per Trust Unit $ 0.92 $ 0.77 $ 1.01 $ 0.68 $ 0.42
Unitholder
distributions $ 360 $ 264 $ 192 $ 191 $ 144
Per Trust Unit $ 0.75 $ 0.55 $ 0.40 $ 0.40 $ 0.30
Daily average sales
volumes (bbls) 99,181 116,368 124,904 98,720 108,981
Net realized SCO
selling price
($/bbl)(2) $ 100.41 $ 88.73 $ 81.48 $ 76.81 $ 68.69
Operating costs
($/bbl) $ 35.93 $ 27.38 $ 20.84 $ 30.13 $ 23.56
Purchased natural gas
price ($/GJ) $ 7.30 $ 5.84 $ 4.99 $ 6.78 $ 6.99
West Texas
Intermediate
(avg. US$/bbl)(3) $ 97.82 $ 90.50 $ 75.15 $ 65.02 $ 58.23
Foreign exchange rates
(US$/Cdn$):
Average $ 1.00 $ 1.02 $ 0.96 $ 0.91 $ 0.85
Quarter-end $ 0.97 $ 1.01 $ 1.00 $ 0.94 $ 0.87
($ millions, except
per Trust Unit and 2006
volume amounts) Q4 Q3 Q2
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Revenues(1) $ 646 $ 689 $ 624
Net income (loss) $ 128 $ 278 $ 337
Per Trust Unit,
Basic $ 0.27 $ 0.60 $ 0.72
Per Trust Unit,
Diluted $ 0.27 $ 0.59 $ 0.72
Cash from operating
activities $ 412 $ 334 $ 209
Per Trust Unit $ 0.88 $ 0.72 $ 0.45
Unitholder
distributions $ 140 $ 140 $ 139
Per Trust Unit $ 0.30 $ 0.30 $ 0.30
Daily average sales
volumes (bbls) 110,185 95,438 86,394
Net realized SCO
selling price
($/bbl)(2) $ 63.71 $ 78.43 $ 79.35
Operating costs
($/bbl) $ 23.60 $ 19.68 $ 28.48
Purchased natural gas
price ($/GJ) $ 6.51 $ 5.42 $ 5.72
West Texas
Intermediate
(avg. US$/bbl)(3) $ 60.16 $ 70.60 $ 70.72
Foreign exchange rates
(US$/Cdn$):
Average $ 0.88 $ 0.89 $ 0.89
Quarter-end $ 0.86 $ 0.90 $ 0.90
(1) Revenues after crude oil purchases and transportation expense.
(2) Net realized SCO selling price after foreign currency hedging.
(3) Pricing obtained from Bloomberg.
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The following significant changes have occurred over the last eight
quarters that have impacted the Trust's financial results:
- The substantive enactment in June 2007 of Bill C-52 Budget
Implementation Act, 2007 ("Bill C-52" or "trust taxation") resulted
in the recording of a future income tax expense of $701 million in
the second quarter of 2007. In addition, corporate tax rate
reductions enacted in the fourth and second quarters of 2007 and in
the second quarter of 2006 resulted in future income tax recoveries
of $153 million, $38 million and $29 million in each quarter,
respectively. Future income tax is a non-cash item with no impact on
the Trust's cash from operating activities.
- Syncrude's Stage 3 expansion came on-line at the end of August 2006,
increasing Syncrude's productive capacity by approximately 100,000
barrels per day with a corresponding pro-rata impact on the Trust's
revenues, operating costs, and depletion, depreciation and accretion
("DD&A") expense.
- In 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.
Information presented for 2006 is based on the Trust's previous
ownership of 35.49 per cent.
- U.S. to Canadian dollar exchange rate fluctuations over the last
eight quarters have impacted commodity pricing and have resulted in
significant unrealized foreign exchange gains and losses on a
quarterly basis on the revaluation of U.S. dollar denominated debt.
The unrealized foreign exchange gains and losses are non-cash items
with no impact on the Trust's cash from operating activities.
- U.S. dollar West Texas Intermediate ("WTI") prices, which our sales
are priced relative to, have increased significantly over the last
five quarters, reaching a high of approximately $110 per barrel
during the first quarter of 2008.
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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, per barrel 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 avoid the winter months; however, the exact timing of unit shutdowns cannot be precisely scheduled, and unplanned outages may occur. Accordingly, production levels 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. 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.
REVIEW OF FINANCIAL RESULTS
In the first quarter of 2008, net income of $298 million, or $0.62 per Trust unit ("Unit"), exceeded net income of $262 million, or $0.55 per Unit, recorded in the comparable quarter in 2007, primarily as a result of higher revenues offset by increases in operating costs, Crown royalties, and DD&A expenses. Revenues net of crude oil purchases and transportation expense totalled $907 million, an increase of $233 million, in the first quarter of 2008 relative to the first quarter of 2007. Operating costs increased to $324?million from $231 million in the first quarter of 2007 as a result of additional mining material moved in the quarter, a higher Syncrude cost structure, and costs associated with the weather-related outage and resumption of Syncrude operations during the quarter. Additional information on revenues, operating costs, Crown royalties and DD&A expenses is provided later in this MD&A.
Cash from operating activities increased by $239 million quarter-over-quarter and totalled $441 million in the first quarter of 2008. Excluding the non-cash impacts of unrealized foreign exchange gains and losses, DD&A expense and future income tax recoveries, cash from operating activities was affected by the same variables that impacted net income, as described above. In addition, in the first quarter of 2008, non-cash operating working capital increased cash from operating activities by $26 million, primarily as a result of higher accounts payable relative to December 31, 2007. In the first quarter of 2007, non-cash working capital requirements reduced cash from operating activities by $94 million, primarily as a result of higher accounts receivable at March 31, 2007 relative to December 31, 2006.
Given the nature of the oil and gas industry whereby accounts receivable from customers are typically settled in the following month, working capital can fluctuate significantly as a result of: volume and price changes relative to each period end; inventory can fluctuate on a month-to-month basis depending on the timing of product shipments and deliveries; and changes in Canadian Oil Sands' accounts payable balance, which can reflect the timing of significant accruals and payments, such as Crown royalties, operating costs, and interest payments on long-term debt.
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Net Income per Barrel
Three Months Ended
March 31
($ per bbl) 2008 2007 Variance
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Revenues after crude oil purchases and
transportation expense 100.49 68.69 31.80
Operating costs (35.93) (23.56) (12.37)
Crown royalties (14.57) (9.58) (4.99)
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Netback 49.99 35.55 14.44
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Non-production costs (1.87) (1.78) (0.09)
Administration and insurance (0.73) (0.65) (0.08)
Interest, net (1.83) (2.48) 0.65
Depletion, depreciation and accretion (11.33) (8.49) (2.84)
Foreign exchange gain (loss) (2.83) 0.79 (3.62)
Future income tax recovery and other 1.55 3.74 (2.19)
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(17.04) (8.87) (8.17)
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Net income per barrel 32.95 26.68 6.27
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Sales volumes (MMbbls) 9.0 9.8 (0.8)
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Non-GAAP Financial Measures
In this MD&A we refer to the Canadian generally accepted accounting principles ("GAAP") measure of cash from operating activities, which is derived from our Consolidated Statements of Cash Flows. We also refer to the Trust's cash from operating activities on a per Unit basis, which does not have any standardized meaning under Canadian GAAP. Cash from operating activities per Unit is derived from cash from operating activities reported on the Trust's Consolidated Statements of Cash Flows divided by the weighted-average number of Units outstanding in the period, as used in the Trust's net income per Unit calculations. Cash from operating activities on a per Unit basis reflects the Trust's capacity to fund distributions, capital expenditures, and other investing activities without incremental financing. The Trust also refers to various per barrel figures, such as net realized selling prices, operating costs and Crown royalties, which also are considered non-GAAP measures, but provide meaningful information on the operational performance of the Trust. We derive per barrel figures by dividing the relevant revenue or cost figure by our sales net of purchased crude oil volumes in a period. Cash from operating activities per Unit and per barrel figures may not be directly comparable to similar measures presented by other companies or trusts.
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Revenues after Crude Oil Purchases and Transportation Expense
Three Months Ended
March 31
($ millions) 2008 2007 Variance
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Sales revenue(1) $ 1,025 $ 781 $ 244
Crude oil purchases (109) (99) (10)
Transportation expense (10) (10) -
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906 672 234
Currency hedging gains(1) 1 2 (1)
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$ 907 $ 674 $ 233
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Sales volumes (MMbbls)(2) 9.0 9.8 (0.8)
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(1) The sum of sales revenue and currency hedging gains equals Revenues
on the Trust's Consolidated Statements of Income and Comprehensive
Income. Sales revenue includes revenue from the sale of purchased
crude oil and sulphur revenue.
(2) Sales volumes, net of purchased crude oil volumes.
($ per barrel)
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Realized SCO selling price
before hedging(3) $ 100.31 $ 68.47 $ 31.84
Currency hedging gains 0.10 0.22 (0.12)
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Net realized SCO selling price $ 100.41 $ 68.69 $ 31.72
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(3) SCO sales revenue after crude oil purchases and transportation
expense divided by sales volumes, net of purchased crude oil volumes.
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Sales revenue after crude oil purchases and transportation expense in the first quarter of 2008 primarily reflects a significantly higher realized selling price for our synthetic crude oil ("SCO") relative to the same period in 2007 offset by a decline in sales volumes in the first quarter of 2008 relative to 2007.
Our average realized SCO selling price before currency hedging of $100.31 per barrel in the first quarter of 2008 was $31.84 per barrel higher than the comparable period in 2007. WTI prices, which our SCO pricing has historically followed, averaged US$97.82 per barrel in the first quarter of 2008, an increase of 68 per cent, or US$39.59 per barrel, compared to the same quarter of 2007. The increase in WTI was tempered by a stronger Canadian dollar, which averaged $1.00 US/Cdn in the first quarter of 2008 compared to $0.85 US/Cdn in the first quarter of 2007.
Also contributing to the higher realized SCO selling price quarter-over-quarter was a $1.80 per barrel improvement in our pricing differential relative to Canadian dollar WTI (the "differential"). In the first quarter of 2008, our SCO realized a weighted-average premium of $1.72 per barrel compared to the average Canadian dollar WTI price versus a discount of $0.08 per barrel in the same period in 2007. We believe that the improvement in the 2008 first quarter differential relative to the same period in 2007 was due to a tighter supply/demand balance as a result of continuing operational issues and turnarounds experienced during 2008 by various synthetic crude oil producers, including Syncrude. The shift in differentials from discounts to premiums can happen quickly depending on the short-term supply/demand dynamics in the marketplace and pipeline availability for transporting the crude oil.
The Trust's sales volumes for the first quarter of 2008 averaged about 99,200 barrels per day versus an average of 109,000 barrels per day in the first quarter of 2007. Sales volumes in the first quarter of 2008 were reduced by the suspension and gradual recovery of Syncrude production, as well as challenges in the reliability of bitumen production and extraction.
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Operating costs
Three Months Ended
March 31
2008 2007
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$/bbl $/bbl $/bbl $/bbl
Bitumen SCO Bitumen SCO
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Bitumen Costs(1)
Bitumen production(2) 15.63 10.15
Purchased energy(2),(4) 3.34 2.72
Purchased bitumen 1.33 -
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20.30 24.35 12.87 15.39
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Upgrading Costs(3)
Bitumen processing and
upgrading(2) 5.45 4.81
Turnaround and catalysts 0.64 1.02
Purchased energy(4) 3.95 2.87
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10.04 8.70
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Other and research(2) 1.32 0.04
Change in treated and
untreated inventory 0.19 (0.55)
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Total Syncrude operating costs 35.90 23.58
Canadian Oil Sands adjustments(5) 0.03 (0.02)
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Total operating costs 35.93 23.56
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(thousands of barrels per day) Bitumen SCO Bitumen SCO
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Syncrude production volumes(6) 320 267 354 296
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(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 SCO based on the effective yield of
SCO from the processing and upgrading of bitumen.
(2) Prior year information has been restated for comparative purposes to
conform to a revised presentation of costs.
(3) Upgrading costs include the production and ongoing maintenance costs
associated with processing and upgrading of bitumen to SCO. It also
includes the costs of major refining equipment turnarounds and
catalyst replacement, all of which are expensed as incurred.
(4) Natural gas prices averaged $7.30/GJ and $6.99/GJ in the first
quarter of 2008 and 2007, respectively.
(5) Canadian Oil Sands' adjustments mainly pertain to Syncrude-related
pension costs, as well as the inventory impact of moving from
production to sales as Syncrude reports per barrel costs based on
production volumes and the Trust reports based on sales volumes.
(6) Syncrude production volumes include purchased bitumen volumes.
Three Months Ended
March 31
($/bbl of SCO) 2008 2007
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Production costs 27.97 17.43
Purchased energy 7.96 6.13
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Total operating costs 35.93 23.56
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(GJs/bbl of SCO)
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Purchased energy consumption 1.09 0.88
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In the first quarter of 2008, operating costs rose to $324 million,
averaging $35.93 per barrel, an increase of $93 million, or $12.37 per barrel
over the first quarter of 2007, primarily as a result of the following:
- Additional mining material and oil sands volumes were moved during
the first quarter of 2008 versus 2007. As well, Syncrude increased
its use of contractors supplementing its own material movement
activities with contracted equipment and operators to increase
exposed mineable ore and to meet operational requirements.
- Increased costs for contractors and salaries and wages of Syncrude
staff as a result of inflationary pressures and contract settlements.
- Additional costs associated with resuming shipments at Syncrude
following the disruption of operations early in the quarter.
- Higher energy usage on a per barrel basis as a result of operational
difficulties.
- The purchase of incremental bitumen, which was used to support
production during times of internal bitumen supply shortfalls.
- An increase in the value of Syncrude's long term incentive plan in
2008 versus 2007. A portion of Syncrude's long-term incentive plans
is based on the market return performance of several Syncrude
owners' shares/units, the market performance of which was stronger in
the first quarter of 2008 relative to the same period in 2007.
>>
On a per barrel basis, operating costs have also increased as a result of the reduced production during the first quarter of 2008 versus the first quarter of 2007. A significant portion of Syncrude's operating costs are fixed and as such, any change in production impacts per unit operating costs.
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 under way and the status of the projects. Non-production costs were virtually unchanged totalling $17 million and $18 million in the first quarters of 2008 and 2007 respectively.
Crown Royalties
Under Alberta's current 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 $37 million to $131 million, or $14.57 per barrel, in the first quarter of 2008 from $94 million, or $9.58 per barrel, in the comparable 2007 quarter. The increase in royalties in the first quarter of 2008 versus the first quarter of 2007 was primarily due to increased revenues offset by higher operating costs. Potential changes to Crown royalty terms by the Alberta government are discussed later in this MD&A.
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Interest, Net
Three Months Ended
March 31
2008 2007
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Interest expense on long-term debt $ 20 $ 25
Interest income and other (3) (1)
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Interest expense, net $ 17 $ 24
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The Trust's net interest expense recorded in the quarter ended March 31,
2008 decreased relative to the comparable period in 2007, due to reduced
average net debt outstanding.
Depreciation, depletion and accretion expense
Three Months Ended
March 31
($ millions) 2008 2007
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Depreciation and depletion expense $ 99 $ 80
Accretion expense 3 2
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$ 102 $ 82
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Depreciation and depletion ("D&D") expense for the first quarter of 2008 rose by $19 million compared to the same period of 2007, primarily as a result of a higher per barrel D&D rate somewhat offset by lower production volumes. In 2008 our D&D rate increased to $11.07 per barrel from approximately $8.30 per barrel in the prior year as a result of higher projected capital cost estimates provided for in the Trust's December 31, 2007 independent reserves report.
The Trust's December 31, 2007 reserve report is summarized in our Annual Information Form dated March 15, 2008 and can be found at www.sedar.com, or on our website at http://www.cos-trust.com/files/investor/pdf/2008/AIF-_FINAL.pdf.
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Foreign exchange loss (gain)
Three Months Ended
March 31
($ millions) 2008 2007
-------------------------------------------------------------------------
Unrealized foreign exchange loss (gain) $ 34 $ (11)
Realized foreign exchange loss (gain) (8) 4
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Total foreign exchange loss (gain) $ 26 $ (7)
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Foreign exchange ("FX") gains/losses are primarily the result of revaluations of U.S. dollar denominated long-term debt caused by fluctuations in U.S. and Canadian dollar exchange rates. The resulting unrealized FX gains/losses impact net income but do not affect cash from operating activities as they are non-cash items. Other FX gains/losses are created through the revaluation of cash, accounts receivable and accounts payable balances denominated in U.S. dollars, which impact both net income and cash from operating activities as these gains/losses are considered realized. Realized FX gains/losses also result from repayment of U.S. dollar denominated balances, such as long-term debt, in which case the resulting FX impacts are included in financing activities on the Trust's Consolidated Statements of Cash Flows.
In the first quarter of 2008, Canadian Oil Sands' FX losses mainly related to the revaluation of our U.S. dollar denominated debt, resulting in an unrealized FX loss of $34 million. The FX loss was due to the weakening of the Canadian dollar relative to the U.S. dollar from $1.01 US/Cdn at December?31, 2007 to $0.97 US/Cdn on March 31, 2008. By comparison, the value of the Canadian dollar relative to the U.S. dollar strengthened to $0.87?US/Cdn on March 31, 2007 relative to $0.86 US/Cdn at December 31, 2006, resulting in an unrealized FX gain of $11 million in the first quarter of 2007.
Future Income Tax and other
Canadian Oil Sands' future income taxes on its Consolidated Balance Sheets represent the net difference between tax values and accounting values, referred to as temporary differences, tax-effected at substantively enacted tax rates expected to apply when the differences reverse. A $14 million future income tax recovery was recorded in the first quarter of 2008 and a $38?million future income tax recovery was recorded in the first quarter of 2007 on the reduction of temporary differences.
On February 26, 2008 the Minister of Finance announced the federal government's intention to adjust the tax rate on distributions from income and royalty trusts that is expected to apply to the Trust commencing in 2011. Specifically, the proposed change is to adjust the deemed provincial component of the tax, currently 13 per cent, to the tax rate of the provinces in which the Trust has a permanent establishment. Substantially all of Canadian Oil Sands' activities are in Alberta and, as such, the provincial component of the tax could be reduced from 13 per cent to 10 per cent. As of April 28, 2008 the proposal had not been enacted by the federal government. If the proposal becomes enacted we expect to record a future income tax recovery based on the temporary differences at that time; however, as the amount of the recovery is dependent upon items such as future distributions and future net income the amount of any such recovery cannot be presently estimated.
CHANGES IN ACCOUNTING POLICIES
In its audited consolidated financial statements for the year ended December 31, 2007 ("Audited 2007 financial statements"), Canadian Oil Sands adopted the requirements of the Canadian Institute of Chartered Accountants ("CICA") Section 3862 Financial Instruments - Disclosures, Section 3863 Financial Instruments - Presentation, and Section 1535 Capital Disclosures. The standards were effective January 1, 2008, however early adoption was encouraged by the CICA. Additional disclosures required as a result of adopting the standards can be found in the Trust's Audited 2007 financial statements.
In June 2007, the CICA issued a new accounting standard - Section 3031 Inventories, which replaces the existing standard for inventories, Section 3030. The main features of the new Section are as follows:
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- Measurement of inventories at the lower of cost and net realizable
value.
- Consistent use of either first-in, first-out or a weighted average
cost formula to measure cost.
- Reversal of previous write-downs to net realizable value when there
is a subsequent increase to the value of inventories.
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The new inventory standard is effective for the Trust beginning January?1, 2008. Application of the new Section did not have an impact on the Trust's financial statements for the quarter ended March 31, 2008.
NEW ACCOUNTING PRONOUNCEMENTS
In February 2008, the CICA issued a new accounting standard - Section 3064 Goodwill and intangible assets, which replaces Section 3062 Goodwill and other intangible assets, and Section 3450 Research and development costs. The new section establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. The section is effective for the Trust beginning January 1, 2009. Application of the new section is not expected to have a material impact on the Trust's financial statements.
On February 13, 2008 the CICA Accounting Standards Board announced that Canadian public reporting issuers will be required to report under International Financial Reporting Standards ("IFRS") starting in 2011. The intention is to bring more transparency and a higher degree of international financial reporting comparability as IFRS is currently applied in more than 100 countries. Although Canadian Oil Sands will not be required to report under IFRS until 2011, we have started to assess the impact on our business of adopting IFRS and are preparing for the transition accordingly.
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LIQUIDITY AND CAPITAL RESOURCES
March December
($ millions) 31 2008 31 2007
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Long-term debt $ 1,238 $ 1,218
Cash and cash equivalents (285) (268)
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Net debt $ 953 $ 950
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Unitholders' equity $ 4,109 $ 4,172
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Total capitalization(1) $ 5,062 $ 5,122
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(1) Net debt plus Unitholders' equity
Net debt to total capitalization (%) 19 19
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As at March 31, 2008, the Trust's unutilized credit facilities amounted to $846 million, net of letters of credit issued against its $40 million revolving term facility and an additional $67 million line of credit. On April?9, 2008 the Trust repaid $150 million of maturing medium term notes with existing cash.
Canadian Oil Sands has set a long-term net debt target of $1.6 billion by 2010, which generally reduces our cost of capital and conserves our tax pools during the transition period to trust taxation. The Trust believes this net debt target will allow the Trust to maintain its strong balance sheet, remain unhedged on its crude oil price exposure, provide the capacity to fund growth opportunities, and maintain an investment grade credit rating. The Trust's actual net debt will fluctuate around this level as factors such as crude oil prices, FX rates, Syncrude's operational performance and the timing of distribution amounts vary from our assumptions.
On a year-to-date basis, Unitholders' equity was increased by net income of $298 million and reduced by Unitholder distributions of $360 million.
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UNITHOLDER DISTRIBUTIONS
Three Months Ended
March 31
($ millions) 2008 2007
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Cash from operating activities $ 441 $ 202
Net income $ 298 $ 262
Unitholder distributions $ 360 $ 144
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Excess of cash from operating activities
over Unitholder distributions $ 81 $ 58
Excess (shortfall) of net income over Unitholder
distributions $ (62) $ 118
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For the quarter ended March 31, 2008, cash from operating activities exceeded Unitholder distributions of $360 million by $81 million. This excess amount was sufficient to pay the Trust's $47 million of capital expenditures, reclamation funding of $1 million and debt repayments totaling $16 million. Capital expenditures are discussed more fully in the "Capital Expenditures" section of this MD&A.
Distributions in the first quarter of 2008 exceeded net income by $62?million, primarily as a result of DD&A. As DD&A is a non-cash item, it does not affect the Trust's cash from operating activities, balance sheet strength or ability to pay distributions over the next several years. Therefore, the Trust paid the distribution despite the lower net income and is anticipating quarterly distributions may exceed net income at times over the next several years.
On April 28, 2008 the Trust declared a quarterly distribution of $1.00 per Unit in respect of the second quarter of 2008 for total distributions of $479 million. The distribution will be paid on May 30, 2008 to holders of record on May 16, 2008.
The 33 per cent increase in the distribution over the previous quarter reflects the Trust's financial plan of efficiently managing its capital structure in anticipation of trust taxation in 2011. The Trust is planning to provide fuller payout of cash from operating activities unless capital investment or acquisition opportunities arise that we believe offer Unitholders enhanced value. The Trust's financial plan also targets a long-term net debt target of about $1.6 billion by the end of 2010 under current market conditions. We believe this net debt target will help conserve tax deductions prior to trust taxation. The target is based on Syncrude's existing productive capacity and we will reconsider this target in light of future Syncrude growth and other acquisition opportunities, which may increase productive capacity.
In determining the Trust's distributions, Canadian Oil Sands also 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 $11 million and $8 million in the first quarter of 2008 and 2007, respectively, and approximated the related expense for both pension and reclamation of $13 million and $10 million for each of the quarters, respectively. While our share of Syncrude's annual pension funding has increased modestly as a result of the most recent actuarial valuation and our share of Syncrude's future reclamation costs also has increased, we currently do not anticipate any material funding increases related to these items for the next few years.
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-book capitalization at an amount less than 55?per cent. With a current net debt-to-book capitalization of approximately 19 per cent, a significant increase in debt or decrease in equity would be required to negatively impact the Trust's financial flexibility.
Cash from operating activities and net income can fluctuate dramatically from period to period reflecting, among other things, variability in operational performance, WTI prices, SCO differentials to WTI and FX rates. The Trust has strived to smooth out the effect of this variability on distributions by taking a longer-term view of: our outlook for our operating and business environment, our net debt level relative to our target, and our capital expenditure and other commitments. In that regard, we may distribute more or less in a period than we generate in cash from operating activities or net income. Nonetheless, the highly variable nature of our cash from operating activities introduces risk in our ability to sustain or provide stability in distributions and any expectations regarding the stability or sustainability of distributions are unwarranted and should not be implied.
Furthermore, as the Trust executes its financial plan, investors should anticipate increased variability in distributions and understand that distribution levels may not be as sustainable once we have met the net debt target. As distributions rise to a larger percentage of cash from operating activities, the distributions will necessarily be more reflective of business performance and crude oil prices.
The Trust uses debt and equity financing to the extent that cash from operating activities is insufficient to fund distributions, capital expenditures, reclamation trust contributions, acquisitions and working capital changes from financing and investing activities. A Unitholder distributions schedule pertaining to the quarter ended March 31, 2008 is included in Note 7 to the unaudited Consolidated Financial Statements.
The taxation of income trusts commencing January 1, 2011 likely will materially alter our cash from operating activities, and consequently distribution levels. Canadian Oil Sands continues to evaluate alternatives as to the best structure for its Unitholders in the future. The federal government has confirmed that it intends to allow conversions from a trust to a corporate structure to occur on a tax-deferred basis, although the rules of such a conversion have yet to be established. Under current expectations, we most likely will convert to a corporate structure. We plan, however, to retain the flow-through advantages of a trust structure until 2011, unless circumstances arise that favour a faster transition to an alternate structure. Canadian Oil Sands continues to be a long-term value investment in the oil sands and does not rely on the tax efficiency of a flow-through trust model to sustain its business. Our long-life reserves and non-declining production profile provide a solid foundation to generate future cash from operating activities.
Quarterly distributions are approved by our board of directors after considering the current and expected economic conditions, ensuring financing capacity for Syncrude's expansion projects and/or Canadian Oil Sands acquisitions, and with the objective of maintaining an investment grade credit rating.
CAPITAL EXPENDITURES
With the completion of Syncrude's Stage 3 project in 2006, Canadian Oil Sands' expansion capital expenditures have declined significantly and, as such, capital costs for 2008 and 2007 are essentially 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. The productive capacity of Syncrude's operations was defined previously in the "Review of Syncrude Operations" section of this MD&A.
In the first quarter of 2008, capital expenditures totalled $47 million, compared to expenditures of $33 million in the same quarter of 2007. The Syncrude Emissions Reduction ("SER") project accounted for $17 million and $15?million of the capital spent in the first quarters of 2008 and 2007, respectively, with the remaining amounts in each quarter pertaining to the maintenance of Syncrude's existing plant and facilities, all of which are considered sustaining capital. Sustaining capital expenditures on a per barrel basis were approximately $5.25 and $3.50 in each of the first quarters of 2008 and 2007, respectively.
Syncrude is undertaking the SER project to retrofit technology into the operation of Syncrude's original two cokers to significantly reduce total sulphur dioxide and other emissions. While expenditures on the SER project are currently estimated at approximately $772 million ($284 million net to the Trust based on its 36.74 per cent working interest), as previously disclosed, there are indications of upward cost pressure on the project. Syncrude is currently performing a full review of the project and will provide updates to cost estimates and timing after such review has been completed. The Trust's share of the SER project expenditures incurred to date is approximately $123?million, with the remaining costs expected to be incurred in the next three years to coordinate with equipment turnaround schedules.
Our sustaining capital expenditures, including the SER project, are estimated at approximately $7 per barrel in 2008 and we expect our longer term sustaining capital expenditures to average approximately $5 per barrel. In addition to inflationary cost pressures that will continue to impact our longer-term average sustaining capital expenditures estimates, we expect to incur costs for large environmental and infrastructure projects, which are required to support the on-going operation, but do not add to production volumes. These projects include the relocation of certain mining trains and tailings systems, which are required as mining operations progress across the active leases. Tailings system projects also include initiatives to improve and supplement the effectiveness of systems used to separate water from sand and clay so that the water can be recycled back to the operation and solids can be incorporated into the final reclamation landscapes. These infrastructure projects, including SER, are expected to add about $2 to $5 per barrel annually to sustaining capital expenditures over the next few years. Our per barrel estimates are based on estimated annual Syncrude production, which increases from 108 million barrels in 2008, or 40 million barrels net to the Trust, to 128 million barrels, or 47 million barrels net to the Trust, at design capacity.
Syncrude's next significant growth stage is anticipated to be the Stage 3 debottleneck. We estimate the project will increase Syncrude productive capacity by 30,000 to 50,000 barrels per day. Based on the current business environment, incremental production is expected to be achieved around 2012. Following the Stage 3 debottleneck, the Stage 4 expansion is planned to grow Syncrude capacity by a further 100,000 barrels per day, resulting in total productive capacity of approximately 500,000 barrels per day post-2016. Spending on each of these respective projects is expected to commence several years prior to the incremental production coming on-stream. Based on independent reserves and resources estimates as of December 31, 2007, future expansion plans are currently being re-evaluated to increase production beyond 500,000 barrels per day in order to maintain an appropriate resource life. The Stage 3 debottleneck and subsequent expansion plans are being developed and are therefore not approved by Canadian Oil Sands or the other Syncrude owners. No cost estimates have been provided for these projects as they are still in the early planning stages.
UNITHOLDERS' CAPITAL AND UNIT TRADING ACTIVITY
The Trust's Units trade on the Toronto Stock Exchange under the symbol COS.UN. The Trust had a market capitalization of approximately $20 billion with 479 million Units outstanding and a closing price of $41.50 per Unit on March 31, 2008.
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Canadian Oil Sands Trust - Trading Activity
First
Quarter March February January
2008 2008 2008 2008
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Unit price
High $ 45.48 $ 45.48 $ 43.20 $ 39.92
Low $ 31.65 $ 37.50 $ 36.00 $ 31.65
Close $ 41.50 $ 41.50 $ 41.70 $ 38.00
Volume of Trust units traded
(millions) 97.6 35.1 30.1 32.4
Weighted average Trust units
outstanding (millions) 479.4 479.4 479.4 479.4
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CONTRACTUAL OBLIGATIONS AND COMMITMENTS
As of April 28, 2008 there have been no significant changes to the Trust's contractual obligations and commitments in 2008 from our 2007 year-end disclosure, other than the repayment of approximately $150 million in maturing notes payable on April 9, 2008.
FINANCIAL RISK MANAGEMENT
The Trust did not have any financial derivatives outstanding at March 31, 2008.
Crude Oil Price Risk
As Canadian Oil Sands did not have any crude oil price hedges during the first quarter of 2008 and 2007, revenues were not impacted by crude oil hedging gains or losses and the Trust benefited from strong WTI prices. As at March 31, 2008 the Trust remains unhedged on its crude oil price exposure and we do not intend to introduce any crude oil hedge positions. However, the Trust may hedge its crude oil production in the future as part of our growth financing strategies.
Foreign Currency Hedging
As at March 31, 2008, we do not have any foreign currency hedges in place. At the present time, we do not intend to introduce any 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, 2008 we did not have any debt outstanding which bears interest at floating market-based rates.
FOREIGN OWNERSHIP
Based on information from the statutory declarations by Unitholders, we estimate that, as of February 12, 2008, approximately 32 per cent of our Unitholders are non-Canadian residents with the remaining 68 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.
The Trust regularly monitors its foreign ownership levels through declarations from Unitholders, and the next declarations will be requested as of May 16, 2008. The Trust posts its foreign ownership levels and describes its steps for managing these levels on its web site (www.cos-trust.com under "investor information", "frequently asked questions"). These steps are also described in the Trust's Annual Information Form dated March 15, 2008.
CROWN ROYALTY CHANGES
In 2007 the Alberta government announced new Crown royalty terms, effective January 1, 2009. For oil sands projects, the new terms are based on a sliding scale royalty rate ranging from one to nine per cent pre-payout and 25 to 40 per cent post-payout that responds to Canadian dollar equivalent WTI ("C$-WTI") price levels. The pre-payout rate is proposed to start at one per cent of revenue and increase for every dollar oil is priced above $55 C$-WTI per barrel, to a maximum of nine per cent of revenue at $120 C$-WTI per barrel or higher. The net royalty applied post-payout will start at 25 per cent of net revenue and rises for every dollar of C$-WTI increase above $55 C$-WTI per barrel up to a maximum of 40 per cent of net revenue at $120 C$-WTI per barrel or higher.
The Syncrude Joint Venture owners have a Crown Agreement with the Alberta government that codifies the current royalty terms of 25 per cent of net SCO revenues to December 31, 2015. The Agreement also provides Syncrude with the option to convert to a bitumen-based royalty, consistent with the rest of the industry, prior to 2010. Canadian Oil Sands, as one of the Syncrude owners, is currently in discussions with the Alberta government regarding both the conversion to a bitumen-based royalty and an equitable solution to offset Syncrude's transition to the higher generic royalty rate prior to 2016. Canadian Oil Sands is of the view that any transition to the new generic royalty terms must recognize our legal rights to the embedded value in Syncrude's contract with the government.
SUSTAINABLE DEVELOPMENT
Greenhouse Gas Emissions Reduction Requirements
On March 31, 2008 Syncrude submitted its compliance report on greenhouse gas ("GHG") emissions to the Alberta government. The report is subject to the review of the director of Alberta Environment. The submission of the compliance report meets the regulatory deadline specified by the Alberta government as part of its Bill 3 legislation introduced in 2007 to reduce GHG emission intensity. Bill 3 states that facilities emitting more than 100,000?tonnes of GHGs a year ("Large Emitters") must reduce their emissions intensity (emissions per unit of production) by 12 per cent over the average emissions intensity levels of 2003, 2004 and 2005. If they are unable to do so, these facilities will be required to pay $15 per tonne for eve | | |
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