IMO Imperial Oil Limited

• Upstream production up 26 percent, highest quarterly total in more than a decade
• Cost management activities deliver year-to-date savings of $1.1 billion
• Cash generation exceeds capital requirements and dividends by more than $300 million

CALGARY, Oct. 30, 2015 /CNW/ -

Imperial's third quarter performance reflects our priorities: focusing on base business operating fundamentals, realizing the full value of recent upstream growth investments, and delivering significant cost reductions in a challenging business environment.

"Results highlight our ability to successfully execute our long-term upstream growth strategy while also being responsive to the current commodity price environment," said Rich Kruger, chairman, president and chief executive officer. "This year is about delivering unprecedented upstream growth that will add value for decades to come. At the same time, we have reduced operating and capital costs by more than one billion dollars, relative to earlier plans, to strengthen our business and improve resiliency in the current business environment."

The company is achieving these cost reductions through increased selectivity in new capital investments, sharpened scrutiny of all operating expenditures and ongoing engagement with suppliers and contractors to improve efficiency and productivity.

"Most notably, upstream unit cash costs in the quarter were nearly 25 percent lower than our 2014 annual average," Kruger said.

Additional highlights in the quarter include, production averaging 386,000 gross oil-equivalent barrels per day, up 12 percent, or 42,000 barrels per day from the second quarter of 2015 and up 26 percent, or 79,000 barrels per day, from the third quarter of 2014. Earnings in the quarter were $479 million, or $0.56 per share, a decrease of 49 percent compared with the corresponding period in 2014, driven by lower global crude prices. Strong downstream and chemical financial performance continues to underscore the value of Imperial's integrated business model. Cash flow from operating activities was $1,104 million, or $1.30 per share, and exceeded capital requirements and dividend outlays by more than $300 million.

Third quarter highlights

• Net income totaled $479 million or $0.56 per share on a diluted basis, down 49 percent from $936 million or $1.10 per share in the third quarter of 2014, driven by lower global crude prices.
  
  
• Production averaged 386,000 gross oil-equivalent barrels per day, up 26 percent versus 307,000 barrels in the third quarter of 2014. Production was at its highest level in more than a decade.
  
  
• Refinery throughput averaged 390,000 barrels per day, compared to 409,000 barrels per day in the third quarter of 2014. Capacity utilization averaged 93 percent, with planned maintenance conducted throughout the quarter.
  
  
• Petroleum product sales were 495,000 barrels per day, compared to 502,000 barrels per day in the third quarter of 2014. The company continues to hold a leading market share in all product segments nationwide.
  
  
• Capital and exploration expenditures totaled $1,142 million, a decrease of $292 million from the third quarter of 2014. Expenditures were primarily directed at the completion of upstream growth projects and the Woodland pipeline capital lease addition of approximately $480 million.
  
  
• Cash generated from operating activities was $1,104 million or $1.30 per share, a decrease of $126 million from the third quarter of 2014. Cash generated exceeded capital requirements and dividend outlays by more than $300 million in the quarter.
  
  
• Kearl bitumen production averaged 181,000 barrels per day in the quarter (128,000 barrels Imperial's share) including the impact of major maintenance performed in September. Production was up 103,000 barrels (73,000 barrels Imperial's share) from the third quarter of 2014, and up 51,000 barrels (36,000 barrels Imperial's share) from the second quarter of 2015. The increase was largely due to the first full quarter of operation of the expansion project.
  
  
• Cold Lake bitumen production averaged 166,000 barrels per day in the quarter, up from 149,000 barrels in the same quarter of 2014. Nabiye production continues to ramp-up following start-up late in the first quarter of 2015.
  
  
• The company's share of Syncrude production averaged 59,000 barrels per day in the third quarter, compared to 61,000 barrels per day in the same period 2014. Syncrude executed a phased recovery following a process incident that occurred in late August. The incident was the result of a piping failure at the Mildred Lake facility and operations resumed in early October.
  
  
• Woodland pipeline, a joint venture with Enbridge, was completed as planned. The nearly 530 kilometre pipeline transports Kearl blended bitumen to Edmonton at an initial capacity of 400,000 barrels per day, alleviating potential capacity constraints on Kearl production and supporting access to high-value markets for equity crude.
  
  
• Regulatory application for Aspen amended to use SA-SAGD technology. The regulatory application to the Alberta Energy Regulator (AER) was amended to develop a bitumen resource of 1.2 billion barrels using an industry first application of Solvent-Assisted, Steam-Assisted Gravity Drainage (SA-SAGD) technology. The technology significantly improves capital efficiency and lowers greenhouse gas intensity versus existing SAGD technologies. Proposed to be executed in two phases of 75,000 barrels per day of production each, development timing is subject to regulatory approvals and market conditions. A final investment decision could be made as early as 2017.
  
  
• Mackenzie gas project permit extension request submitted to National Energy Board (NEB). Imperial applied to the NEB for an extension of the pipeline construction permit. An extension would allow joint venture participants to assess the impact of changes in the North American natural gas market, including the potential impact of proposed LNG projects.
  
  
• Imperial and Husky Energy to create national truck transport fuel network of about 160 sites across Canada, approximately twice the size of either individual network today. Under the agreement, Husky will assume management of dealer relationships and network growth as an Esso-branded wholesaler while Imperial will supply fuel and marketing programs to the consolidated network. The agreement is subject to approval by Canada's Competition Bureau and closing conditions.

Third quarter 2015 vs. third quarter 2014

The company's net income for the third quarter of 2015 was $479 million or $0.56 per share on a diluted basis compared with $936 million or $1.10 per share for the same period last year.

Upstream recorded a net loss in the third quarter of $52 million, compared to net income of $532 million in the same period of 2014. Earnings in the third quarter of 2015 reflected lower crude oil and gas realizations of about $1,250 million and higher depreciation expense of about $80 million. These factors were partially offset by higher Kearl and Cold Lake volumes of about $280 million, the favourable impact of a weaker Canadian dollar of about $270 million and lower royalties of about $230 million.

West Texas Intermediate (WTI), the main U.S. dollar benchmark crude for North America, decreased by 52 percent compared to the same quarter in 2014. The company's average Canadian dollar realizations for synthetic crude oil and bitumen decreased about 40 and 56 percent in the third quarter of 2015 to $61.21 and $32.61 per barrel respectively, as the decline in the benchmark crude and increased light-heavy differentials were partially offset by the weaker Canadian dollar. The company's average realizations on sales of natural gas of $1.75 per thousand cubic feet in the third quarter of 2015, were lower by $1.83 per thousand cubic feet, versus the same period in 2014.

Gross production of Cold Lake bitumen averaged 166,000 barrels per day in the third quarter, up from 149,000 barrels in the same period last year, primarily due to the continued ramp-up of Nabiye production.

Gross production of Kearl bitumen averaged 181,000 barrels per day in the third quarter (128,000 barrels Imperial's share) up from 78,000 barrels per day (55,000 barrels Imperial's share) during the third quarter of 2014, reflecting the strong start-up of the Kearl expansion project.

The company's share of gross production from Syncrude averaged 59,000 barrels per day, compared to 61,000 barrels in the third quarter of 2014.

Gross production of conventional crude oil averaged 12,000 barrels per day in the third quarter, down from 16,000 barrels in the corresponding period in 2014. The lower production volume was primarily due to planned maintenance activity and natural reservoir decline.

Gross production of natural gas during the third quarter of 2015 was 116 million cubic feet per day, down from 149 million cubic feet in the same period last year.

Downstream net income was $454 million in the third quarter, $111 million higher than the third quarter of 2014. Earnings increased mainly due to the favourable impact of a weaker Canadian dollar of about $160 million, partially offset by higher refinery planned maintenance and operating costs, mainly associated with the Edmonton Rail Terminal, of about $70 million.

Chemical net income was $78 million in the third quarter, the highest quarterly earnings on record, up 18 percent from $66 million in the same quarter in 2014.

Net income effects from Corporate and Other were negative $1 million in the third quarter, compared to negative $5 million in the same period of 2014.

The company's cash balance was $366 million as at September 30, 2015, versus $43 million at the end of the third quarter of 2014.

Cash flow generated from operating activities was $1,104 million in the third quarter, $126 million lower than the corresponding period in 2014. Lower cash flow was due to lower earnings and was partially offset by favourable working capital effects.

Investing activities used net cash of $619 million in the third quarter, compared with $1,379 million in the same period of 2014, reflecting the decline in additions to property, plant and equipment to $647 million during the third quarter, compared with $1,351 million during the same quarter in 2014. Expenditures during the quarter were primarily in support of completion of upstream growth projects.

Cash used in financing activities was $147 million in the third quarter, compared with cash from financing activities of $21 million in the third quarter of 2014. Dividends paid in the third quarter of 2015 were $110 million. Per-share dividend paid in the third quarter was $0.13, consistent with the same period of 2014.

Nine months highlights

• Net income totaled $1,020 million, down from $3,114 million in the prior year.
  
  
• Net income per common share on a diluted basis was $1.20 compared to $3.66 in 2014.
  
  
• Cash flow generated from operating activities was $1,762 million, versus $3,314 million in 2014.
  
  
• Cash used in investing activities of $2,345 million was down $772 million, versus the same period in 2014, mainly reflecting the decline in additions to property, plant and equipment.
  
  
• Gross oil-equivalent barrels of production averaged 355,000 barrels per day, up 15 percent from 308,000 barrels from the same period in 2014.
  
  
• Refinery throughput averaged 385,000 barrels per day, compared to 402,000 barrels in the same period in 2014.
  
  
• Per-share dividends declared during the year totaled $0.40, up $0.01 per share from 2014.

Nine months 2015 vs. nine months 2014

Net income in the first nine months of 2015 was $1,020 million, or $1.20 per share on a diluted basis and reflected a net charge, largely non-cash, of $320 million associated with the enacted Alberta corporate income tax rate increase, versus $3,114 million or $3.66 per share for the first nine months of 2014, which included a $478 million gain on the sale of conventional upstream producing assets.

Upstream recorded a net loss of $415 million for the first nine months of 2015, compared to net income of $1,841 million in the same period of 2014. Earnings in 2015 reflected lower crude oil and gas realizations of about $3,000 million, a net charge of $327 million associated with increased Alberta corporate income taxes and higher depreciation expense of about $130 million. Earnings in 2014 included a gain of $478 million from the divestment of conventional upstream producing assets. These factors were partially offset by the favourable impact of a weaker Canadian dollar of about $590 million, lower royalties of about $560 million, higher liquid volumes of about $490 million, primarily Kearl and Cold Lake, and lower energy costs of about $90 million.

WTI, the main U.S. dollar benchmark crude for North America, decreased by 49 percent compared to the same period in 2014. The company's average Canadian dollar realizations for synthetic crude oil and bitumen decreased about 41 and 49 percent in the first nine months of 2015 to $63.03 and $36.48 per barrel respectively, as the decline in benchmark crude and increased light-heavy differentials were partially offset by the weaker Canadian dollar. The company's average realizations on sales of natural gas of $2.44 per thousand cubic feet in 2015, were lower by $2.53 per thousand cubic feet, versus the same period in 2014.

Gross production of Cold Lake bitumen averaged 160,000 barrels per day in the first nine months, up from 145,000 barrels from the same period last year, primarily due to Nabiye production.

Gross production of Kearl bitumen averaged 136,000 barrels per day in the first nine months of 2015 (96,000 barrels Imperial's share) up from 73,000 barrels per day (52,000 barrels Imperial's share), reflecting early start-up of the Kearl expansion project and improved reliability of the initial development.

During the first nine months of 2015, the company's share of gross production from Syncrude averaged 61,000 barrels per day, compared to 62,000 barrels from the same period of 2014.

Gross production of conventional crude oil averaged 14,000 barrels per day in the first nine months of 2015, compared to 18,000 barrels during the same period of 2014. The lower production volume was primarily due to the impact of properties divested during the first half of 2014.

Gross production of natural gas during the first nine months of 2015 was 132 million cubic feet per day, down from 171 million cubic feet in the same period last year, reflecting the impact of divested properties.

Downstream net income was $1,234 million, up $37 million in the same period of 2014. Earnings increased due to the favourable impact of a weaker Canadian dollar of about $360 million, higher fuels marketing margins and volumes of about $70 million, lower energy costs of $70 million and a 2015 gain of $17 million from the sale of assets. These factors were partially offset by the impacts of lower refining margins of about $280 million, higher refinery planned maintenance and operating costs, mainly associated with the Edmonton Rail Terminal, of about $220 million.

Chemical net income was $213 million for the first nine months of 2015, an increase of $47 million over the same period in 2014.

For the first nine months of 2015, net income effects from Corporate & Other were negative $12 million, compared to negative $90 million in 2014, primarily due to lower share-based compensation charges and the impact of the Alberta corporate income tax rate increase.

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 in any government payment transparency reports.

After more than a century, Imperial continues to be an industry leader in applying technology and innovation to responsibly develop Canada's energy resources. As Canada's largest petroleum refiner, a major producer of crude oil and natural gas, a key petrochemical producer and a leading fuels marketer from coast to coast, our company remains committed to high standards across all areas of our business.

SOURCE Imperial Oil Limited