Fourth-quarter earnings were $614 million or $0.74 per common share, more than triple the $182 million or $0.22 per common share for the corresponding period in 2004.
Cash flow from operations reached a record $3,056 million in 2005, up over 40 per cent from $2,129 million in 2004.
Capital, exploration and predevelopment expenditures reached $1,715 million compared with $951 million for 2004 due to higher investment in all three of the Company's businesses.
"Shell Canada achieved record production in 2005, which enabled it to take advantage of strong commodity prices and deliver record earnings and cash flow. Breaking through the $2 billion barrier was a tremendous achievement," said Clive Mather, President and Chief Executive Officer, Shell Canada Limited. "There were many exciting milestones including sustained Oil Sands production above design rates and launching our new unconventional gas business. The company also laid the foundations for long-term growth with major land acquisitions, and record graduate and experienced hires."
Earnings ($ millions) Q4 04 Q1 05 Q2 05 Q3 05 Q4 05 182 417 526 457 614 Cash Flow ($ millions) Q4 04 Q1 05 Q2 05 Q3 05 Q4 05 437 637 803 686 930 Capital Expenditures ($ millions) Q4 04 Q1 05 Q2 05 Q3 05 Q4 05 325 269 327 410 709
MANAGEMENT'S DISCUSSION AND ANALYSIS Total Company
Shell Canada Limited earnings for 2005 were $2,014 million compared with $1,286 million for 2004. Record volumes supported by strong commodity prices and refining margins more than offset higher costs. The impact of the Company's Long Term Incentive Plan (LTIP) resulted in a $173 million charge to earnings due to strong appreciation in the share price during the year. The use of non-capital losses increased earnings by $164 million in 2005 and, along with higher proceeds from insurance settlements, outweighed the effect of the higher LTIP charge.
Earnings for the fourth quarter of 2005 were $614 million, up $432 million from $182 million for the corresponding period in 2004. Higher volumes and continuing strong commodity prices and refining margins contributed to the results. Fourth-quarter results included a favourable adjustment of $65 million related to the use of non-capital losses from the acquisition of an affiliated company, and a $27 million charge relating to the LTIP.
Total investment in 2005 was $1,715 million, up from $951 million in 2004. Investments included more than $350 million in new land purchases at Crown land sales to acquire more than 250,000 net acres in key strategic areas of Western Canada. Total hydrocarbon production surpassed all previous years and reached a record 228,700 barrels of oil equivalent per day (boe/d), up from 219,700 boe/d in 2004.
Exploration & Production
In 2005, Exploration & Production (E&P) delivered record earnings of $665 million, up $216 million from $449 million for 2004. The positive impact of strong commodity prices was partially offset by increased expenses, and lower volumes due to natural field decline, plant turnarounds, and adverse weather conditions. Results in 2005 reflected positive tax adjustments of $39 million and an insurance settlement of $12 million, offset by a charge of $50 million related to the LTIP. Exploration and predevelopment expenses in 2005 were below those of 2004, with lower dry hole expenses partially offsetting higher exploration expenses. During 2005, the Company's E&P investment included the acquisition of almost 200,000 net acres at Crown land sales in Alberta and British Columbia. These purchases were in addition to the previously announced 20 per cent interest the Company acquired in eight exploration licenses in the Orphan Basin earlier in the year.
E&P earnings in the fourth quarter of 2005 were $263 million, up $190 million from $73 million for the corresponding period in 2004. Gains from strong commodity prices combined with lower exploration and lower LTIP charges were partially offset by higher operating costs. A $32 million charge due to predevelopment expenses on the Mackenzie Gas Project negatively impacted fourth-quarter results in 2004. Fourth-quarter results in 2005 included LTIP charges of $8 million compared with $24 million in 2004.
Total natural gas production for the fourth quarter of 2005 was on par with the same period of 2004, despite plant turnaround activities that extended into October. Increased fourth-quarter production from the Sable Offshore Energy Project (SOEP) along with new production from Tay River and basin-centered gas (BCG) more than offset natural field decline. As a result, gas production was higher at year-end 2005 than at year-end 2004.
In the Foothills region, installation of an additional unit to increase sulphur recovery at the Jumping Pound facility was completed in October. Re-tubing of the Tay River well was also completed in October and the result has exceeded expectations with sustained total production rates (raw gas) of more than 95 million cubic feet per day (mmcf/d). Foothills natural gas production for both November and December exceeded 2004 rates for the same months.
At SOEP, strong gas production from the Alma and South Venture fields largely offset natural field decline in 2005 and SOEP production in the second half was higher than in the same period of 2004. Production from a new well in the Venture field began late December and a third well in the Alma field will be drilled in the first quarter of 2006. In addition, a compression project is expected to come on-stream in the fourth quarter of 2006.
BCG production began in November 2005 from four wells. Because of a lack of processing infrastructure, production was limited to 17 mmcf/d. Land acquisitions of over 140,000 net acres in 2005 more than tripled the Company's BCG landholdings and, together with encouraging drilling results, provide the basis for a substantial future expansion of drilling and production operations. The BCG drilling program will employ four dedicated rigs throughout 2006. Evaluation of infrastructure options continues, including a possible new gas plant, to accommodate anticipated production increases over the next five years.
Significant progress was made during the second half of 2005 regarding clarity of the Mackenzie Gas Project (MGP) regulatory process, the negotiation of benefits and access agreements with northern aboriginal groups, and fiscal framework discussions with governments. The MGP public hearings will start in the first quarter of 2006.
Peace River bitumen volumes for the fourth quarter of 2005 were up from the corresponding period of 2004, mainly due to steam cycle phasing. Drilling of two additional well pads continues and the resulting new production is expected to come on stream in late 2006. Effective January 1, 2006, the Peace River business was transferred from E&P to the Oil Sands business unit.
Oil Sands generated record earnings of $790 million in 2005, more than double the $378 million in 2004 due to higher volumes and prices. The earnings increase also reflects higher proceeds from insurance settlements in 2005, offset by higher LTIP charges and reduced contributions from tax adjustments. Total LTIP charges were $29 million in 2005.
Oil Sands earnings in the fourth quarter of 2005 were $196 million, up significantly from $13 million in the fourth quarter of 2004 when planned and unplanned maintenance activities impacted operations. The increase was due to higher volumes, higher prices and lower unit costs. Fourth-quarter earnings included charges of $5 million related to the LTIP in 2005 compared to $11 million in 2004.
The Company's share of bitumen production in the fourth quarter of 2005 averaged 106,800 barrels per day (bbls/d) compared with 65,900 bbls/d for the same period in 2004 when operations were restricted to a single train. Total bitumen production reached a new record in the fourth quarter of 2005, averaging 178,000 bbls/d, and the Scotford Upgrader also achieved new production records. For the full year 2005, total bitumen production was 159,900 bbls/d, above the 155,000 bbls/d design rate. High bitumen production during the fourth quarter at times prompted the blending and sale of additional heavy synthetic product at the upgrader.
In the fourth quarter of 2005, commodity prices and the average synthetic crude oil price were down somewhat from the preceding quarter, but considerably higher than in the fourth quarter of 2004. Heavy oil market differentials widened during the fourth quarter and were higher than in the same period of 2004. As a result, the average synthetic crude oil price differential relative to Edmonton light crude was wider than in both the third quarter of 2005 and the fourth quarter of 2004. Compared with the prior year, Edmonton light crude prices were up 31 per cent, heavy oil market differentials increased by more than 50 per cent and the average synthetic crude oil price rose by 29 per cent.
Unit cash operating costs in the fourth quarter of 2005 were $23.87 per barrel. This was down $0.38 per barrel from the preceding quarter, and down significantly from the fourth quarter of 2004 when high maintenance costs and low volumes heavily influenced unit costs. Unit cash operating costs for 2005 averaged $23.16 per barrel, down slightly versus 2004. Improved reliability and production offset increased costs for energy, materials and services in the high commodity price environment.
During the fourth quarter, the Company's investment in Oil Sands continued with the acquisition of three additional Athabasca oil sands leases with mining potential. In 2005, the Company acquired seven leases with a combined area of about 69,000 acres through Alberta Crown land sales. Core hole drilling will be required to determine the resource potential of these lands and its impact on the long-term growth of the Oil Sands business.
The first major planned turnaround of the Athabasca Oil Sands Project (AOSP) is scheduled to start in the second quarter of 2006. Both trains at the Muskeg River Mine and the Scotford Upgrader will be down for maintenance. It is expected that operations will be interrupted for approximately eight weeks before returning to normal at mid-year.
The use of tax pools created during construction of the AOSP has resulted in no cash taxes being payable on operating income thus far. The Company expects that these tax pools will be exhausted during the first quarter of 2006, at which time Oil Sands operations will become cash taxable.
Additions to gross proved natural gas reserves essentially replaced production in 2005. After production of 187 billion cubic feet (bcf), gross proved natural gas reserves were 1,592 bcf for 2005 compared with 1,595 bcf for 2004. Reserve additions of 184 bcf from extensions and discoveries, and an acquisition of 9 bcf in the Burmis region, were partially offset by net downward technical and economic revisions of 9 bcf that resulted from the annual review process. Extensions and discoveries included an additional 74 bcf for Tay River and a booking of 52 bcf for the Company's early investment position in BCG. After 2005 production of 14 million barrels, gross proved natural gas liquids reserves decreased by just 7 million barrels from 2004 mainly as a result of net positive technical and economic revisions.
In 2005, 28 million gross proved barrels of Peace River bitumen reserves were re-booked. In 2004, adherence to United States Securities and Exchange Commission reserve reporting rules and related guidance prescribing the use of constant year-end pricing and costs for proved reserves determination resulted in the Company de-booking all proved Peace River bitumen reserves.
Over 2005, Shell Canada developed a new strategy for development of the Peace River lease, which includes plans for a proposed expansion project. The 28 million barrels re-booked for 2005 is solely the reserve portion attributable to the existing and currently-drilling wells, and existing facilities. Progression of the engineering and regulatory work for the expansion will continue over the next two years before reaching a final investment decision. Once this key project milestone is reached, the Company expects that the expansion project will incorporate the booking of further reserves to the asset.
In 2005, the Company's gross proved mineable bitumen reserves increased to 808 million barrels from 621 million barrels in 2004. Core-hole drilling activity resulted in the reclassification of 222 million barrels from the probable to proved category, partially offset by production of 35 million barrels of bitumen. Total gross proved and probable mineable bitumen reserves decreased by the 35 million barrels produced, from 971 million barrels in 2004 to 936 million barrels for 2005.
Shell Canada's 2005 Annual Report will provide full gross and net reserves information.
Oil Products 2005 annual earnings were $438 million, down slightly from record earnings of $451 million for 2004. Strong refining margins and improved refinery light oil yields contributed to earnings but were more than offset by lower refinery utilization and higher expenses. Expenses increased in 2005 versus 2004 due to higher refinery maintenance costs, high costs for purchased product and higher LTIP charges. However, the increase over 2004 was partially offset by a charge in 2004 relating to a provision for the AIR MILES(R) reward miles program. LTIP charges in 2005 were $51 million. Planned maintenance work at the Scotford Refinery and unplanned maintenance at the Montreal East Refinery (MER) resulted in reduced utilization during the second half of the year. High spot prices for purchased products compounded the impact of these maintenance activities. Periods within the year were marked by supply disruptions and fuel price volatility in North America following the hurricane activity. However, the Company was able to maintain a reliable supply to customers at competitive prices throughout.
Oil Products earnings in the fourth quarter were $106 million compared with $109 million for the same period in 2004. Stronger refining and marketing margins were offset by lower prices for benzene, lower refinery utilization and higher expenses. Higher maintenance and insurance costs, project related expenses and commodity price-related costs were offset by lower LTIP charges of $6 million in 2005, compared to $30 million in 2004. Fourth-quarter results were further reduced by a negative tax adjustment of $8 million.
At the Montreal East and Scotford Refineries, construction has been completed on two new diesel hydrotreater units that will produce ultra-low- sulphur diesel (ULSD). The $400 million investment is on schedule and budget and will be commissioned in the first quarter, ahead of legislative requirements that are currently scheduled to take effect June 1, 2006.
Oil Products will be making arrangements to purchase other feedstock for the Scotford Refinery to replace supplies that will not be available in the second quarter of 2006 due to planned maintenance at the Scotford Upgrader. The Sarnia refinery also has a major turnaround planned for late in the third quarter of 2006.
(R) Trademark of AIR MILES International Trading B.V. Used under license by Loyalty Management Group Canada Inc. and Shell Canada Products.
Corporate earnings for 2005 were $121 million compared with earnings of $8 million for 2004. Results were improved by $164 million due to the use of non-capital losses and were reduced by $43 million due to the LTIP charge.
Corporate earnings for the fourth quarter of 2005 were $49 million compared with negative earnings of $13 million for the corresponding period in 2004. The increase was mainly due to the use of non-capital losses available to the Company resulting from the acquisition of an affiliated company, Coral Resources Canada ULC, in the fourth quarter of 2004. Fourth-quarter earnings also include an $8 million charge related to the LTIP, compared to $6 million in 2004.
Cash Flow and Financing
In 2005, cash flow from operations was a record $3,056 million, up from $2,129 million in 2004. Cash flow from operations was $930 million for the fourth quarter of 2005, up from $437 million for the same quarter last year. These increases are largely attributable to higher volumes and prices.
The Consolidated Statement of Cash Flows reflects certain items, primarily exploration expense and pension contributions, as reductions of cash from operating activities. These items were reflected in 2004 as investing activities. The reclassification of these 2004 items reflects exploration costs of $70 million (Q4 - $16 million) in earnings from continuing operations, and a pension contribution of $68 million (Q4 - $77 million) as a movement in working capital. In addition, the Company reclassified certain LTIP expenses of $151 million in 2004 (Q4 - $151 million) as a reduction of cash flow from operations offset by a change in working capital.
Capital, exploration and predevelopment expenditures were $1,715 million for 2005 and $709 million for the fourth quarter. This compares with $951 million and $325 million for the same periods in 2004 respectively. The main reasons for the increases were investments in land, drilling, and the ULSD projects at the refineries.
During 2005, the Company paid off all remaining long-term borrowings and terminated its accounts receivable securitization program. The combined reduction of long-term debt and accounts receivable sales in 2005 amounted to $285 million. Corporate debt on the balance sheet is now limited to $210 million for the mobile equipment lease. Continued strong cash flows during the fourth quarter further strengthened Shell's financial position and helped to build up a substantial year-end cash balance. The year-end cash balance of $1,083 million has been invested in short-term money market investments.
Shell Canada's normal course issuer bid, which began May 4, 2004, and expired May 3, 2005, was used to counter dilution resulting from the issuance of common shares under the LTIP. A total of 3,557,241 common shares (adjusted for the share split) had been repurchased and cancelled at market prices for a cost of $88 million, which included $34 million of shares purchased in 2005.
The Company paid $302 million in dividends on its common shares in 2005. Dividends paid in the fourth quarter were $0.11 per common share totaling $91 million. This reflected a 22 per cent increase over the dividend per share paid in the third quarter and an increase of 32 per cent over the dividend paid in the fourth quarter of 2004.
At January 15, 2006, the Company had 825,107,812 common shares and 100 preference shares outstanding (October 15, 2005 - 825,074,112 common shares and 100 preference shares) and there were 20,833,983 employee stock options outstanding, of which 9,512,120 were exercisable or could be surrendered to exercise an attached share appreciation right (October 15, 2005 - 21,544,416 outstanding and 10,163,103 exercisable).
Additional information relating to Shell Canada Limited filed with Canadian and U.S. securities regulatory authorities, including the Annual Information Form and Form 40-F, can be found online under the Company's profile at www.sedar.com and www.sec.gov.
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