Murphy Oil Corporation — Q2 2012 Form 10-Q
Business context and period. Unaudited results for the three and six months ended June 30, 2012, compared with 2011. Murphy reported exploration and production (E&P) and refining and marketing (R&M) operations. The Superior and Meraux U.S. refineries had been sold in 2011 and are shown as discontinued operations in comparative periods; U.K. downstream assets remained in continuing operations while offered for sale.
Key financial results
| Metric | Q2 2012 | Q2 2011 | Six months 2012 | Six months 2011 |
|---|---|---|---|---|
| Total revenue | $7.190bn | $7.416bn | $14.185bn | $13.688bn |
| Income from continuing operations | $295.4m | $280.0m | $585.5m | $518.5m |
| Net income | $295.4m | $311.6m | $585.5m | $580.5m |
| Diluted EPS | $1.52 | $1.60 | $3.01 | $2.98 |
| Operating cash flow | Six-month comparison | $1.347bn | $917.9m |
- Quarterly continuing income rose about 5.5%, although total revenue fell about 3.0%. Net income and diluted EPS were lower than the prior-year quarter, which included $31.6m of income from discontinued operations.
- Six-month continuing income increased about 12.9%; revenue increased about 3.6%. Prior-year net income included $62.0m from discontinued operations.
- Q2 segment income: E&P $230.1m versus $243.3m; R&M $80.5m versus $60.1m. Six-month E&P income was $551.7m versus $503.7m; R&M was $76.3m versus $60.4m.
- Six-month worldwide production averaged 191,836 barrels of oil equivalent per day, up from 176,272. Q2 averaged 188,575, up from 170,457. Six-month crude oil, condensate and liquids price averaged $97.21/barrel versus $93.04; North American natural gas averaged $2.36/MCF versus $4.30.
- Six-month property additions and dry-hole costs were $1.337bn cash basis; accrual-basis capital expenditures were $1.649bn, up from $1.317bn. Cash dividends paid were $106.8m.
Financial position and liquidity
- At June 30, cash and cash equivalents were $671.6m and Canadian government securities were $470.8m. Current assets were $3.444bn and current liabilities $2.551bn; reported working capital was $893.2m.
- Long-term debt was $791.5m, versus $249.6m at year-end 2011; current maturities were negligible. Stockholders’ equity was $9.305bn. The company had a $1.5bn committed credit facility expiring in 2016; facility availability is not specified in the provided filing text.
- In May, Murphy issued $500m of 4.00% notes due 2022. It repaid $350m of notes that matured in May using borrowings from existing credit facilities; proceeds from the new notes repaid those borrowings and funded general corporate purposes.
- Cash from operations exceeded investing cash outflow of $1.277bn; financing provided $87.5m. Cash increased $157.8m during the half. Operating cash flow benefited from lower working-capital cash use than in 2011.
Changes, outlook, and risks
- Management attributed the first-half earnings improvement mainly to higher realized crude prices, higher crude sales volumes, lower exploration expense and improved U.K. downstream results. Lower North American gas prices were a significant offset. In Q2, E&P earnings were pressured by lower oil and North American gas prices; U.K. R&M margins improved.
- Q2 U.S. E&P recorded a $1.2m loss, including unsuccessful Deep Blue Gulf of Mexico drilling. Canada earnings declined, including from Terra Nova’s 150-day turnaround and Syncrude maintenance. Malaysia earnings rose with higher gas prices and volumes and Kikeh oil volumes. Azurite produced no oil sales in Q2; management expected the next sale in Q4 2012.
- Management expected Q3 2012 production to average about 183,000 barrels of oil equivalent per day and full-year capital expenditures of approximately $4.1bn. July crude prices were somewhat below Q2 averages; U.S. retail margins had fallen significantly and ethanol margins remained weak. July North American gas prices were very weak; prolonged weakness or further declines could impair gas-property investments.
- Murphy was evaluating separating its U.S. downstream business into a separately traded company, but gave no decision or timing. It continued marketing its U.K. refinery and related downstream assets; timing and sale terms were uncertain, and management noted a possible loss on sale under current market conditions.
- Exploratory well costs pending proved-reserve determinations totaled $567.6m, including $293.5m aged three years or more. Actual outcomes may differ from management’s estimates, and unsuccessful exploration may result in charges.
- Other exposures include foreign-exchange, commodity and interest-rate risks; $164.7m of outstanding letters of credit (draws considered remote); environmental and legal contingencies; and a U.K. greenhouse-gas allowance penalty notice of about $1.7m. Management stated known environmental and legal matters were not expected to materially affect results, financial condition or liquidity.
- A U.K. tax-law change enacted in July 2012 was expected to increase tax expense by approximately $7m when recorded in Q3, principally reflecting reduced tax relief on decommissioning costs. The filing provides no specific earnings guidance beyond the production and capital-spending outlook above.
Most important facts to verify
- Whether production, prices and operating performance—especially North American gas and Malaysia—track the outlook and explain earnings changes.
- Progress and economics of the proposed U.S. downstream separation and the U.K. asset sale, including any impairment or disposal loss.
- Execution of the approximately $4.1bn 2012 capital program and its funding against operating cash flow, debt and liquidity.
- Resolution or change in exposure from aged exploratory well costs, environmental matters, letters of credit and the U.K. penalty notice.
- Effects of the U.K. tax change and any sustained weakness in North American natural-gas prices on tax expense and asset valuations.