Exhibit 99.1
Q3 news release
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2013
|
Calgary, October 31, 2013
Imperial Oil announces estimated third quarter financial and operating results
| Third quarter | Nine months | |||||||||||||||||||||||||
(millions of dollars, unless noted) | 2013 | 2012 | % | 2013 | 2012 | % | ||||||||||||||||||||
Net income (U.S. GAAP) | 647 | 1,040 | (38) | 1,772 | 2,690 | (34) | ||||||||||||||||||||
Net income per common share | 0.76 | 1.22 | (38) | 2.08 | 3.16 | (34) | ||||||||||||||||||||
Capital and exploration expenditures | 1,840 | 1,409 | 31 | 6,453 | 3,890 | 66 | ||||||||||||||||||||
Rich Kruger, Chairman, President and Chief Executive Officer of Imperial Oil, commented:
During the quarter, Imperial Oil maintained focus on the operational performance of its base businesses while continuing to advance major upstream growth projects. All three proprietary paraffinic froth treatment trains are operational at our world-class Kearl oil sands mining project and diluted bitumen is being successfully processed at Imperial and ExxonMobil refineries. Production continues to ramp-up as we further synchronize facilities and address ongoing improvements in equipment reliability in advance of our first season of winter operation. We expect to achieve production levels of 110,000 barrels per day (78,000 Imperial’s share) by the end of the year.
Earnings in the third quarter were $647 million compared to $1,040 million for the same period in 2012.
Gross production averaged 288,000 oil-equivalent barrels per day (88 percent liquids), up 3,000 barrels versus the same period in 2012. Planned maintenance at Syncrude reduced volumes in the quarter by an estimated 21,000 barrels per day. Refinery throughput averaged 451,000 barrels per day, essentially flat with the third quarter in 2012.
Third quarter capital and exploration expenditures totalled $1,840 million. Investments were focused on upstream growth projects, most notably Kearl’s expansion and Cold Lake’s Nabiye, which were 58 and 59 percent complete, respectively, at the end of the quarter and our $206 million acquisition of the Clyden oil sands lease.
Key actions were taken in the third quarter to enhance asset profitability. As previously planned, refining operations were discontinued at Dartmouth and steps were taken to progress its conversion to a fuels terminal. In addition, we initiated the marketing of three mature, conventional oil and gas producing properties in western Canada.
Our overriding objective remains to deliver superior, long-term shareholder value. Our priorities will continue to focus on maximizing the value of our assets through value chain integration, synergies, disciplined investment and cost management. Above all, our commitment to safety, operational integrity and responsible growth will be unwavering.
Imperial Oil is one of Canada’s largest corporations and a leading member of the country’s petroleum industry. The company is a major producer of crude oil and natural gas, Canada’s largest petroleum refiner, a key petrochemical producer and a leading marketer with coast-to-coast supply and retail service station networks.
1
Third quarter highlights
| • | Net income of $647 million or $0.76 per share on a diluted basis,compared with $1,040 million or $1.22 per share for the third quarter of 2012. The earnings decrease was driven primarily by significantly lower industry refining margins. |
| • | Production averaged 288,000 gross oil-equivalent barrels per day, up slightly from 2012, with production from the Kearl project start-up and Celtic (XTO Energy Canada) acquisition more than offsetting planned maintenance impacts at Syncrude and natural decline at conventional properties. |
| • | Refinery throughput averaged 451,000 barrels per day in the third quarter, essentially unchanged from the same period in 2012. |
| • | Capital investments of $1,840 million were directed at the Kearl expansion and Cold Lake Nabiye upstream growth projects, as well as the acquisition of the Clyden oil sands lease. |
| • | Kearl bitumen production continued to ramp up,averaging 33,000 barrels per day gross in the quarter. Gross production averaged 11,000, 43,000 and 45,000 barrels per day in July, August and September, respectively. From September 22 through October 8, the plant was shut down to address ongoing improvements in equipment reliability and prepare for potential weather-related challenges in our first winter season of operation. Post restart, rates have averaged 80,000 barrels per day with current production of 100,000 barrels per day. All three paraffinic froth treatment trains are operational and have been tested at design capacity. Diluted bitumen has been successfully run in three Imperial and ExxonMobil refineries and, in the fourth quarter, sales to unrelated parties commenced. We expect to achieve production levels of 110,000 barrels per day (78,000 Imperial’s share) by the end of the year. |
| • | Kearl’s expansion project progressing per plan. The project progressed to 58 percent complete, remains on schedule for a 2015 start-up and is expected to ultimately produce 110,000 barrels per day gross (78,000 Imperial’s share). Lessons learned from initial development are being proactively applied to all aspects of the expansion project. |
| • | Cold Lake’s Nabiye project remains on schedule. The project was 59 percent complete at the end of the quarter, remains on target for a late 2014 start-up and is expected to produce 40,000 barrels per day. |
| • | Clyden oil sands lease acquired for $206 million. On August 16, Imperial Oil (27.5 percent) and ExxonMobil Canada (72.5 percent) acquired ConocoPhillips’ interest in the Clyden oil sands lease, 150 kilometres south of Fort McMurray, Alberta. The 226,000 gross acre lease is near Imperial’s Corner lease holdings and is amenable to in-situ recovery techniques. |
| • | Dartmouth refinery operations were discontinued on September 16, as planned. This successfully completed the first step in the transition to a fuels terminal. Imperial continues to supply this market with petroleum products. |
| • | Marketing commenced on three mature, conventional producing properties.The assets include Boundary Lake, Pembina and Rocky Mountain House. Combined production totalled approximately 15,000 oil-equivalent barrels per day in the first half of 2013, split evenly between oil and gas. |
| • | Beaufort exploration project (25 percent Imperial) description filed by the joint-venture partners with the Inuvialuit Environmental Impact Screening Committee and National Energy Board, initiating the formal regulatory review of the project. No investment decisions have been made at this time. |
| • | Imperial Oil Foundation donates $150,000 to the Vancouver General Hospital’s Aboriginal Patient Navigator Program. The contribution will provide improved access to healthcare services for Aboriginal communities as well as help overcome cultural differences and language barriers. |
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Third quarter 2013 vs. third quarter 2012
The company’s net income for the third quarter of 2013 was $647 million or $0.76 per share on a diluted basis, compared with $1,040 million or $1.22 per share for the same period last year.
Upstream net income in the third quarter was $604 million, $106 million higher than the same period of 2012. Earnings increased primarily due to higher liquids realizations of about $350 million. This was partially offset by lower volumes and higher costs at Syncrude, mainly as a result of planned maintenance activities, totalling about $150 million and higher royalty costs of about $85 million.
The price differential between Brent crude oil, the benchmark for Atlantic basin markets, and West Texas Intermediate (WTI), a common benchmark for mid-continent North American oil markets, narrowed to $4.54 per barrel in U.S. dollars in the third quarter of 2013, compared to $17.37 per barrel in the corresponding period last year. As discounts for WTI crude oil decreased, the company’s average realizations in Canadian dollars on sales of conventional and synthetic crude oils increased about 21 and 26 percent, respectively. The company’s average bitumen realizations in Canadian dollars in the third quarter of 2013 also increased by about 36 percent to $81.21 per barrel as the price spread between light crude oil and bitumen narrowed. The company’s average realizations on natural gas sales of $2.66 per thousand cubic feet in the third quarter of 2013 were higher by about $0.48 per thousand cubic feet versus the same period in 2012. The significant narrowing of the price differential between Brent and WTI also adversely impacted industry refining margins and Downstream earnings.
Gross production of Cold Lake bitumen averaged 147,000 barrels per day versus 152,000 barrels in the same period last year. Lower volumes were primarily due to the cyclic nature of steaming and associated production at Cold Lake.
The company’s share of Syncrude’s gross production in the third quarter was 57,000 barrels per day, down from 78,000 barrels in the third quarter of 2012. The planned maintenance activities were completed, and the impacted coker unit returned to normal operations in the quarter.
The company’s share of gross production from the Kearl initial development contributed 23,000 barrels per day. Throughout the quarter we continued to address ongoing improvements in equipment reliability. Production ramp-up continues and is expected to reach 110,000 barrels per day gross by the end of the year. As previously announced, diluted bitumen sales began in the third quarter, and Kearl diluted bitumen has been run at the company’s and ExxonMobil’s refineries and is performing as expected.
Gross production of conventional crude oil averaged 22,000 barrels per day in the third quarter, versus 19,000 barrels in the corresponding period in 2012.
Gross production of natural gas during the third quarter of 2013 was 211 million cubic feet per day, up from 188 million cubic feet in the same period last year. The higher production volume reflected the contributions from the Celtic acquisition earlier in the year and the Horn River pilot which more than offset normal field decline.
Downstream net income was $46 million in the third quarter, $490 million lower than the third quarter of 2012. Earnings decreased primarily due to significantly lower industry refining margins of about $565 million. This was partially offset by favourable impacts of improved refinery operations and an increase in marketing margins.
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Third quarter 2013 vs. third quarter 2012 (continued)
Chemical net income was $39 million in the third quarter, in line with $37 million in the same quarter last year.
Net income effects from Corporate and Other were negative $42 million in the third quarter, versus negative $31 million in the same period of 2012 due to changes in share-based compensation charges.
Cash flow generated from operating activities was $298 million in the third quarter, versus $669 million in the corresponding period in 2012. Lower cash flow was primarily attributable to lower earnings. Third quarter 2013 cash flow was lower than earnings primarily due to the timing of income tax payments.
Investing activities used net cash of $1,804 million in the third quarter, compared with $1,318 million in the same period of 2012. Additions to property, plant and equipment were $1,810 million in the third quarter, compared with $1,388 million during the same quarter 2012. Expenditures during the quarter were primarily directed towards the advancement of Kearl expansion and Nabiye projects. The Kearl expansion is expected to bring on additional gross production of 110,000 barrels of bitumen per day, before royalties, of which the company’s share would be about 78,000 barrels. Start-up is expected by late 2015. The Nabiye expansion at Cold Lake is expected to bring on additional production of 40,000 barrels of bitumen per day, before royalties. Start-up is expected by late 2014.
Cash from financing activities was $1,040 million in the third quarter, compared with $122 million in the third quarter of 2012. In the third quarter, the company increased its long-term debt level by $819 million by drawing on an existing facility and issued additional commercial paper which increased short-term debt by $325 million.
The above factors led to a decrease in the company’s cash balance to $76 million at September 30, 2013, from $482 million at the end of 2012.
4
Nine months highlights
| — | Net income of $1,772 million, down from $2,690 million in 2012. |
| — | Net income per common share of $2.08 compared to $3.16 in 2012. |
| — | Cash generated from operations of $1,633 million, versus $3,033 million in 2012. |
| — | Gross oil-equivalent barrels of production averaged 283,000 barrels per day, up from 281,000 barrels in 2012. |
| — | Refinery throughput averaged 439,000 barrels per day, up 15,000 barrels from the same period last year. |
| — | Per-share dividends declared in the year totalled $0.36, unchanged from 2012. |
Nine months 2013 vs. nine months 2012
Net income in the first nine months of 2013 was $1,772 million or $2.08 per share on a diluted basis, versus $2,690 million or $3.16 per share for the first three quarters of 2012.
Earnings decreased primarily due to significantly lower industry refining margins of about $720 million, higher Kearl start-up and operating costs of about $175 million, and lower production and higher maintenance costs at Syncrude totalling about $150 million. First nine months earnings in 2013 also included an after tax charge of $264 million associated with the conversion of the Dartmouth refinery to a terminal. These factors were partially offset by higher liquids realizations of about $210 million, improved refinery operations and lower refinery maintenance activities totalling about $115 million and lower royalty costs of about $110 million due to higher cost recovery for capital investments.
Upstream net income for the first nine months of 2013 was $1,301 million versus $1,400 million in 2012. Earnings decreased primarily due to higher Kearl costs of about $175 million as third quarter production contribution was more than offset by year-to-date start-up and operating costs, lower volumes and higher maintenance costs at Syncrude totalling about $150 million, and lower bitumen production and higher maintenance costs at Cold Lake totalling about $85 million. These factors were partially offset by higher liquids realizations of about $210 million and lower royalty costs of about $110 million due to higher cost recovery for capital investments.
The price differential between Brent crude oil, the benchmark for Atlantic basin markets, and West Texas Intermediate (WTI), a common benchmark for mid-continent North American oil markets, narrowed to $10.20 per barrel in U.S. dollars in the first nine months of 2013, compared to $15.91 per barrel in the corresponding period last year. As discounts for WTI crude oil decreased, the company’s average realizations in Canadian dollars on sales of conventional and synthetic crude oils increased about eight and 11 percent, respectively. The company’s average bitumen realizations in Canadian dollars in the first nine months of 2013 also increased by about five percent to $63.86 per barrel. The company’s average realizations on natural gas sales of $3.21 per thousand cubic feet in the first three quarters of 2013 were higher by $1.09 per thousand cubic feet versus the same period in 2012.
Gross production of Cold Lake bitumen was 152,000 barrels per day, compared with 154,000 barrels in the same period of 2012. Lower volumes were primarily due to the cyclic nature of steaming and associated production at Cold Lake.
During the first nine months of the year, the company’s share of gross production from Syncrude averaged 63,000 barrels per day, down from 70,000 barrels in 2012. Planned maintenance activities in the third quarter of 2013 were the main contributor to the lower volumes.
The company’s share of gross production of Kearl initial development was 9,000 barrels per day on a 2013 year-to-date basis.
Gross production of conventional crude oil averaged 21,000 barrels per day in the first nine months of the year, versus 20,000 barrels in the corresponding period in 2012.
5
Nine months 2013 vs. nine months 2012 (continued)
Gross production of natural gas during the first nine months of 2013 was 201 million cubic feet per day, up from 194 million cubic feet in the same period in 2012. The higher production volumes reflected the contributions from the Celtic acquisition and the Horn River pilot, which more than offset normal field decline.
Downstream net income was $427 million, versus $1,223 million over the same period in 2012. Earnings were negatively impacted by significantly lower industry refining margins of about $720 million resulting from the narrowing pricing differential between Brent and WTI crude oils. Earnings in the first nine months of 2013 also included an after tax charge of $264 million associated with the conversion of the Dartmouth refinery to a fuels terminal. These factors were partially offset by the favourable impacts of about $115 million associated with improved refinery operations and lower refinery maintenance activities.
Chemical net income was $116 million, versus $121 million in 2012.
For the first nine months of 2013, net income effects from Corporate and Other were negative $72 million, versus negative $54 million last year.
Key financial and operating data follow.
Forward-Looking Statements
Statements of future events or conditions in this report, including projections, targets, expectations, estimates, and business plans are forward-looking statements. Actual future results, including demand growth and energy source mix; production growth and mix; project plans, dates, costs and capacities; production rates and resource recoveries; cost savings; product sales; financing sources; and capital and environmental expenditures could differ materially depending on a number of factors, such as changes in the price, supply of and demand for crude oil, natural gas, and petroleum and petrochemical products; political or regulatory events; project schedules; commercial negotiations; the receipt, in a timely manner, of regulatory and third-party approvals; unanticipated operational disruptions; unexpected technological developments; and other factors discussed in this report and Item 1A of Imperial’s most recent Form 10-K. Forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to Imperial. Imperial’s actual results may differ materially from those expressed or implied by its forward-looking statements and readers are cautioned not to place undue reliance on them.
The term “project” as used in this release can refer to a variety of different activities and does not necessarily have the same meaning as under government payment transparency reports.
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Attachment I
IMPERIAL OIL LIMITED
THIRD QUARTER 2013
| Third Quarter | Nine Months | |||||||||||||||
| millions of Canadian dollars, unless noted | 2013 | 2012 | 2013 | 2012 | ||||||||||||
Net Income (U.S. GAAP) | ||||||||||||||||
Total revenues and other income | 8,594 | 8,336 | 24,566 | 23,384 | ||||||||||||
Total expenses | 7,737 | 6,949 | 22,207 | 19,805 | ||||||||||||
Income before income taxes | 857 | 1,387 | 2,359 | 3,579 | ||||||||||||
Income taxes | 210 | 347 | 587 | 889 | ||||||||||||
Net income | 647 | 1,040 | 1,772 | 2,690 | ||||||||||||
Net income per common share (dollars) | 0.76 | 1.22 | 2.09 | 3.17 | ||||||||||||
Net income per common share - assuming dilution (dollars) | 0.76 | 1.22 | 2.08 | 3.16 | ||||||||||||
Other Financial Data | ||||||||||||||||
Federal excise tax included in operating revenues | 385 | 355 | 1,041 | 1,011 | ||||||||||||
Gain/(loss) on asset sales, after tax | 5 | 1 | 46 | 67 | ||||||||||||
Total assets at September 30 | 36,081 | 28,471 | ||||||||||||||
Total debt at September 30 | 6,214 | 1,429 | ||||||||||||||
Interest coverage ratio - earnings basis | 71.4 | 255.9 | ||||||||||||||
Other long-term obligations at September 30 | 4,095 | 3,748 | ||||||||||||||
Shareholders’ equity at September 30 | 17,896 | 15,652 | ||||||||||||||
Capital employed at September 30 | 24,132 | 17,106 | ||||||||||||||
Return on average capital employed (a) | 13.3 | 23.5 | ||||||||||||||
Dividends declared on common stock | ||||||||||||||||
Total | 102 | 102 | 306 | 306 | ||||||||||||
Per common share (dollars) | 0.12 | 0.12 | 0.36 | 0.36 | ||||||||||||
Millions of common shares outstanding | ||||||||||||||||
At September 30 | 847.6 | 847.6 | ||||||||||||||
Average - assuming dilution | 851.0 | 851.4 | 850.8 | 851.4 | ||||||||||||
| (a) | Return on capital employed is net income excluding after-tax cost of financing divided by the average rolling four quarters’ capital employed. |
7
Attachment II
IMPERIAL OIL LIMITED
THIRD QUARTER 2013
| Third Quarter | Nine Months | |||||||||||||||
| millions of Canadian dollars | 2013 | 2012 | 2013 | 2012 | ||||||||||||
Total cash and cash equivalents at period end | 76 | 469 | 76 | 469 | ||||||||||||
Net income | 647 | 1,040 | 1,772 | 2,690 | ||||||||||||
Adjustment for non-cash items: | ||||||||||||||||
Depreciation and depletion | 223 | 183 | 860 | 551 | ||||||||||||
(Gain)/loss on asset sales | (5 | ) | (2 | ) | (60 | ) | (86 | ) | ||||||||
Deferred income taxes and other | 106 | 72 | 276 | 289 | ||||||||||||
Changes in operating assets and liabilities | (673 | ) | (624 | ) | (1,215 | ) | (411 | ) | ||||||||
Cash flows from (used in) operating activities | 298 | 669 | 1,633 | 3,033 | ||||||||||||
Cash flows from (used in) investing activities | (1,804 | ) | (1,318 | ) | (6,301 | ) | (3,606 | ) | ||||||||
Proceeds from asset sales | 6 | 70 | 68 | 209 | ||||||||||||
Cash flows from (used in) financing activities | 1,040 | 122 | 4,262 | (160 | ) | |||||||||||
8
Attachment III
IMPERIAL OIL LIMITED
THIRD QUARTER 2013
| Third Quarter | Nine Months | |||||||||||||||
| millions of Canadian dollars | 2013 | 2012 | 2013 | 2012 | ||||||||||||
Net income (U.S. GAAP) | ||||||||||||||||
Upstream | 604 | 498 | 1,301 | 1,400 | ||||||||||||
Downstream | 46 | 536 | 427 | 1,223 | ||||||||||||
Chemical | 39 | 37 | 116 | 121 | ||||||||||||
Corporate and other | (42 | ) | (31 | ) | (72 | ) | (54 | ) | ||||||||
Net income | 647 | 1,040 | 1,772 | 2,690 | ||||||||||||
Revenues and other income | ||||||||||||||||
Upstream | 3,191 | 2,069 | 7,791 | 6,620 | ||||||||||||
Downstream | 6,893 | 7,535 | 20,762 | 20,765 | ||||||||||||
Chemical | 418 | 369 | 1,198 | 1,211 | ||||||||||||
Eliminations/Other | (1,908 | ) | (1,637 | ) | (5,185 | ) | (5,212 | ) | ||||||||
Total | 8,594 | 8,336 | 24,566 | 23,384 | ||||||||||||
Purchases of crude oil and products | ||||||||||||||||
Upstream | 1,307 | 593 | 3,030 | 2,354 | ||||||||||||
Downstream | 5,789 | 5,818 | 16,788 | 16,073 | ||||||||||||
Chemical | 295 | 254 | 826 | 850 | ||||||||||||
Eliminations | (1,907 | ) | (1,639 | ) | (5,184 | ) | (5,220 | ) | ||||||||
Purchases of crude oil and products | 5,484 | 5,026 | 15,460 | 14,057 | ||||||||||||
Production and manufacturing expenses | ||||||||||||||||
Upstream | 880 | 671 | 2,508 | 1,963 | ||||||||||||
Downstream | 396 | 357 | 1,312 | 1,197 | ||||||||||||
Chemical | 50 | 46 | 157 | 138 | ||||||||||||
Eliminations | (1 | ) | - | (3 | ) | - | ||||||||||
Production and manufacturing expenses | 1,325 | 1,074 | 3,974 | 3,298 | ||||||||||||
Capital and exploration expenditures | ||||||||||||||||
Upstream | 1,765 | 1,376 | 6,272 | 3,793 | ||||||||||||
Downstream | 51 | 27 | 128 | 80 | ||||||||||||
Chemical | 3 | 1 | 6 | 3 | ||||||||||||
Corporate and other | 21 | 5 | 47 | 14 | ||||||||||||
Capital and exploration expenditures | 1,840 | 1,409 | 6,453 | 3,890 | ||||||||||||
Exploration expenses charged to income included above | 30 | 21 | 74 | 67 | ||||||||||||
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Attachment IV
IMPERIAL OIL LIMITED
THIRD QUARTER 2013
| Operating statistics | Third Quarter | Nine Months | ||||||||||||||
| 2013 | 2012 | 2013 | 2012 | |||||||||||||
Gross crude oil and Natural Gas Liquids (NGL) production | ||||||||||||||||
(thousands of barrels per day) | ||||||||||||||||
Cold Lake | 147 | 152 | 152 | 154 | ||||||||||||
Syncrude | 57 | 78 | 63 | 70 | ||||||||||||
Conventional | 22 | 19 | 21 | 20 | ||||||||||||
Kearl | 23 | - | 9 | - | ||||||||||||
Total crude oil production | 249 | 249 | 245 | 244 | ||||||||||||
NGLs available for sale | 4 | 4 | 4 | 5 | ||||||||||||
Total crude oil and NGL production | 253 | 253 | 249 | 249 | ||||||||||||
Gross natural gas production(millions of cubic feet per day) | 211 | 188 | 201 | 194 | ||||||||||||
Gross oil-equivalent production (a) | ||||||||||||||||
(thousands of oil-equivalent barrels per day) | 288 | 285 | 283 | 281 | ||||||||||||
Net crude oil and NGL production(thousands of barrels per day) | ||||||||||||||||
Cold Lake | 115 | 126 | 126 | 120 | ||||||||||||
Syncrude | 56 | 75 | 62 | 67 | ||||||||||||
Conventional | 18 | 15 | 17 | 15 | ||||||||||||
Kearl | 21 | - | 8 | - | ||||||||||||
Total crude oil production | 210 | 216 | 213 | 202 | ||||||||||||
NGLs available for sale | 3 | 3 | 3 | 3 | ||||||||||||
Total crude oil and NGL production | 213 | 219 | 216 | 205 | ||||||||||||
Net natural gas production(millions of cubic feet per day) | 201 | 182 | 188 | 197 | ||||||||||||
Net oil-equivalent production (a) | ||||||||||||||||
(thousands of oil-equivalent barrels per day) | 246 | 249 | 247 | 238 | ||||||||||||
Cold Lake blend sales(thousands of barrels per day) | 201 | 191 | 201 | 200 | ||||||||||||
Kearl blend sales(thousands of barrels per day) | 15 | - | 5 | - | ||||||||||||
NGL sales(thousands of barrels per day) | 9 | 5 | 9 | 8 | ||||||||||||
Natural gas sales(millions of cubic feet per day) | 178 | 185 | 168 | 183 | ||||||||||||
Average realizations(Canadian dollars) | ||||||||||||||||
Conventional crude oil realizations (per barrel) | 93.48 | 77.25 | 83.57 | 77.43 | ||||||||||||
NGL realizations (per barrel) | 41.91 | 38.43 | 36.19 | 43.76 | ||||||||||||
Natural gas realizations (per thousand cubic feet) | 2.66 | 2.18 | 3.21 | 2.12 | ||||||||||||
Synthetic oil realizations (per barrel) | 113.63 | 90.25 | 102.98 | 93.04 | ||||||||||||
Bitumen realizations (per barrel) | 81.21 | 59.86 | 63.86 | 61.07 | ||||||||||||
Refinery throughput(thousands of barrels per day) | 451 | 449 | 439 | 424 | ||||||||||||
Refinery capacity utilization(percent) | 89 | 89 | 87 | 84 | ||||||||||||
Petroleum product sales(thousands of barrels per day) | ||||||||||||||||
Gasolines (Mogas) | 231 | 240 | 221 | 220 | ||||||||||||
Heating, diesel and jet fuels (Distillates) | 159 | 161 | 156 | 148 | ||||||||||||
Heavy fuel oils (HFO) | 29 | 34 | 31 | 30 | ||||||||||||
Lube oils and other products (Other) | 48 | 58 | 43 | 42 | ||||||||||||
Net petroleum products sales | 467 | 493 | 451 | 440 | ||||||||||||
Petrochemical sales(thousands of tonnes)
|
| 242
|
|
| 252
|
|
| 725
|
|
| 780
|
| ||||
| (a) | Gas converted to oil-equivalent at 6 million cubic feet = 1 thousand barrels |
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Attachment V
IMPERIAL OIL LIMITED
THIRD QUARTER 2013
| Net income | ||||||||
| Net income (U.S. GAAP) | per common share | |||||||
(millions of Canadian dollars)
| (dollars)
| |||||||
2009 | ||||||||
First Quarter | 289 | 0.34 | ||||||
Second Quarter | 209 | 0.25 | ||||||
Third Quarter | 547 | 0.64 | ||||||
Fourth Quarter | 534 | 0.63 | ||||||
Year | 1,579 | 1.86 | ||||||
2010 | ||||||||
First Quarter | 476 | 0.56 | ||||||
Second Quarter | 517 | 0.61 | ||||||
Third Quarter | 418 | 0.49 | ||||||
Fourth Quarter | 799 | 0.95 | ||||||
Year | 2,210 | 2.61 | ||||||
2011 | ||||||||
First Quarter | 781 | 0.92 | ||||||
Second Quarter | 726 | 0.86 | ||||||
Third Quarter | 859 | 1.01 | ||||||
Fourth Quarter | 1,005 | 1.19 | ||||||
Year | 3,371 | 3.98 | ||||||
2012 | ||||||||
First Quarter | 1,015 | 1.20 | ||||||
Second Quarter | 635 | 0.75 | ||||||
Third Quarter | 1,040 | 1.22 | ||||||
Fourth Quarter | 1,076 | 1.27 | ||||||
Year | 3,766 | 4.44 | ||||||
2013 | ||||||||
First Quarter | 798 | 0.94 | ||||||
Second Quarter | 327 | 0.39 | ||||||
Third Quarter | 647 | 0.76 | ||||||
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