Murphy Oil Corporation — Q3 2012 Form 10-Q
Reporting period: Three and nine months ended September 30, 2012. Interim financial statements are unaudited. Murphy’s continuing businesses included exploration and production (E&P) and refining and marketing (R&M); U.K. upstream operations and previously sold U.S. refineries are presented as discontinued operations.
Financial performance
| Metric | Q3 2012 | Q3 2011 | Nine months 2012 | Nine months 2011 |
|---|---|---|---|---|
| Total revenues | $7.122B | $7.220B | $21.237B | $20.844B |
| Income from continuing operations | $228.9M | $347.3M | $801.7M | $847.4M |
| Net income | $226.7M | $406.1M | $812.2M | $986.6M |
| Diluted EPS | $1.16 | $2.09 | $4.17 | $5.07 |
| Operating cash flow | Not stated for quarter | Not stated for quarter | $2.101B | $1.877B |
- Q3 continuing-operations pretax income was $406.6M; income tax expense was $177.7M, an effective rate of 43.7%. Nine-month effective tax rate was 41.1%.
- Q3 segment income from continuing operations: E&P $221.1M versus $273.4M; R&M $42.8M versus $68.9M. Nine-month E&P income was $760.0M versus $758.8M, while R&M earned $119.1M versus $129.3M.
- Worldwide hydrocarbon production averaged 181,558 barrels of oil equivalent per day (boe/d) in Q3, up from 174,801; nine-month production averaged 188,385 boe/d versus 175,776. North American natural gas prices were notably weaker: Q3 average was $2.61/MCF versus $4.20, and nine-month average was $2.43 versus $4.26, as described in MD&A.
- U.S. retail fuel margin fell to $0.103 per gallon in Q3 from $0.200; U.K. refining unit margin improved to $3.44 per barrel from negative $1.66.
Cash, liquidity and capital
- At September 30, cash and cash equivalents were $816.7M, with $491.6M of Canadian government securities classified as current investments; working capital was $877.4M. The filing notes that LIFO inventory carrying values were $645.4M below FIFO value.
- Nine-month operating cash flow was $2.101B. Investing activities used $2.230B, including $2.232B for property additions and dry-hole costs; financing provided $422.7M. Cash dividends paid were $167.5M.
- Accrual-basis capital expenditures, including discontinued operations, were $2.884B for nine months, versus $2.036B a year earlier, primarily reflecting increased E&P development spending.
- Long-term debt was $1.185B, compared with $249.6M at year-end 2011; stockholders’ equity was $9.617B. Murphy issued $500M of 4.00% notes due 2022 and repaid $350M of notes that matured in May. The committed credit facility was $1.5B and expires in 2016.
Material changes and management commentary
- Q3 net income declined chiefly because of weaker North American natural gas prices, lower U.S. retail marketing margins, unfavorable foreign-exchange effects, the absence of a 2011 Malaysian tax benefit, and lower income from discontinued operations. Higher crude production and stronger U.K. refining results partly offset these effects.
- On October 16, 2012, Murphy announced plans to separate its U.S. downstream business into an independent publicly traded company, targeted for completion in 2013. That business had $1.96B of assets at September 30 and contributed $83.4M of income on $13.2B of revenue in the first nine months.
- Murphy announced a $2.50-per-share special dividend, approximately $486M, payable December 3, 2012, and a share repurchase program of up to $1B. Management expects a significant portion of these distributions to be funded with new long-term debt.
Outlook, risks and contingencies
- Management expected Q4 2012 production to average 207,000 boe/d and full-year capital expenditures to be approximately $4.4B. October crude prices had softened slightly from Q3; U.S. retail margins had improved somewhat, while U.K. downstream margins had weakened.
- The board approved a sale of U.K. E&P operations, then expected near year-end 2012. Murphy continued marketing U.K. downstream assets and said timing and terms were uncertain; a sale could result in a loss under then-current market conditions.
- Management warned that persistently weak or lower North American gas prices could lead to impairment of certain natural gas investments. Capitalized exploratory well costs pending proved-reserve determinations were $571.8M, including $284.3M aged three years or more.
- Outstanding letters of credit totaled $356.1M and were not accrued because management considered a draw unlikely. Environmental and other proceedings were described as routine or not expected to have a material adverse effect; the U.K. Environment Agency had issued a civil penalty notice of approximately $1.7M relating to greenhouse-gas allowances.
- Key risks include oil and gas price volatility, exploration success and reserve replacement, foreign-exchange movements, political and regulatory uncertainty, natural hazards, and execution, approvals, tax treatment and financing for the planned separation and capital returns.
Investor verification priorities
- Assess the sustainability of E&P earnings amid weak North American gas prices, higher development spending and regional production interruptions.
- Verify the economics, approvals, tax treatment, timing and financing of the U.S. downstream separation, special dividend and up-to-$1B buyback.
- Track debt and liquidity after planned shareholder distributions, including the location and potential repatriation costs of foreign-held cash.
- Review the status and eventual resolution of the U.K. upstream and downstream divestitures, and possible sale proceeds or losses.
- Monitor exploration costs pending reserve determination, potential gas-property impairments, and environmental or other contingent liabilities.