Imperial Oil Limited — Q3 2015 Form 10-Q
Reporting period: Quarter and nine months ended September 30, 2015. Unaudited consolidated financial statements prepared under U.S. GAAP. Amounts are Canadian dollars unless otherwise noted.
Financial results and liquidity
| Metric | Q3 2015 | Q3 2014 | Nine months 2015 | Nine months 2014 |
|---|---|---|---|---|
| Operating revenue | $7,111 million | $9,641 million | $20,553 million | $28,237 million |
| Net income | $479 million | $936 million | $1,020 million | $3,114 million |
| Diluted earnings per share | $0.56 | $1.10 | $1.20 | $3.66 |
| Cash from operating activities | $1,104 million | $1,230 million | $1,762 million | $3,314 million |
| Cash additions to property, plant and equipment | $647 million | $1,351 million | $2,431 million | $3,852 million |
- Nine-month operating revenue declined about 27% and net income about 67% year over year. Q3 revenue declined about 26% and net income about 49%.
- At September 30, cash was $366 million; current assets were $4,113 million and current liabilities $5,770 million. The resulting current ratio was approximately 0.71.
- Notes and loans payable were $1,953 million and long-term debt was $6,473 million, for total reported borrowings of $8,426 million, versus $6,891 million at December 31, 2014. Cash less these borrowings was approximately $8,060 million net debt. Long-term debt included $621 million of capital leases.
- Operating cash flow less cash property additions was negative $669 million for the nine months. The company paid $330 million in dividends during that period.
- Q3 net income margin was approximately 6.7%; nine-month net income margin was approximately 5.0%, calculated as net income divided by operating revenue.
Material changes and operating performance
- Upstream: Q3 net loss was $52 million, compared with $532 million net income a year earlier; the nine-month loss was $415 million, versus $1,841 million income. Lower crude and gas realizations were the major headwind. Higher depreciation also reduced earnings.
- Management cited Q3 upstream earnings impacts of approximately $1,250 million from lower realizations and $80 million from higher depreciation, partly offset by higher Kearl and Cold Lake volumes ($280 million), a weaker Canadian dollar ($270 million), and lower royalties ($230 million). WTI was down 52% year over year for the quarter.
- Q3 synthetic crude and bitumen realizations fell about 40% and 56%, respectively, to $61.21 and $32.61 per barrel. Cold Lake and Kearl production rose, reflecting the Nabiye ramp-up and Kearl expansion; conventional crude and natural gas production declined.
- Downstream: Q3 net income rose to $454 million from $343 million; nine-month income was $1,234 million, up from $1,197 million. A weaker Canadian dollar supported results, partly offset by refinery maintenance and operating costs. Management also cited lower nine-month refining margins.
- Chemical: Q3 net income was a record $78 million, up from $66 million; nine-month income was $213 million, compared with $166 million.
- Nine-month results included a largely noncash $320 million charge associated with Alberta’s enacted corporate tax-rate increase. The comparable 2014 period included a $478 million gain on conventional upstream asset divestitures.
- Investment and other income was $106 million for the nine months, compared with $696 million in 2014, principally reflecting lower asset-sale gains: $80 million before tax in 2015 versus $664 million in 2014.
Cash, financing, outlook and risks
- Nine-month operating cash flow fell to $1,762 million from $3,314 million, primarily reflecting lower earnings. Investing activities used $2,345 million; financing activities provided $734 million, including $1,106 million of long-term debt issued.
- The company increased its affiliated-company floating-rate loan facility capacity from $6.25 billion to $7.75 billion in July 2015. It also entered into an approximately $480 million long-term capital lease for the Woodland pipeline. A $500 million committed short-term bank facility was extended to March 2016 and remained undrawn.
- No specific earnings or production guidance is provided in the supplied filing text. Management stated that nine-month results are not necessarily indicative of full-year results.
- Management identified market conditions, legal or policy changes, operating conditions and costs, project schedules and performance, oil and gas demand, commercial negotiations, and technical or economic factors as risks that could cause actual results to differ materially from forward-looking statements.
- After-tax net-income sensitivity to a U.S. $4-per-barrel change in crude prices was reported as approximately $314 million, with sensitivity increased from Q2 mainly because lower crude prices reduce royalties.
- Disclosure controls were assessed as effective, with no material change in internal control over financial reporting during the quarter. The company was evaluating a new revenue-recognition standard expected to be adopted beginning January 1, 2018.
Important facts for investors to verify
- Reconcile the Q3 per-share dividend figures: the income statement reports dividends per common share of $0.14, while MD&A describes $0.13 per share paid in the quarter.
- Review the drivers and persistence of upstream losses, especially crude and gas realizations, differentials, royalties, and the ramp-up and reliability of Kearl and Cold Lake projects.
- Assess debt and liquidity exposure, including affiliated-company borrowing, variable-rate financing, the Woodland pipeline lease, and the gap between current assets and current liabilities.
- Confirm the effects of the Alberta tax-rate increase and employee-retirement and environmental obligations on future cash requirements.
- Evaluate the sustainability of cash flows and capital spending against dividends, given negative nine-month operating cash flow after cash property additions.