Murphy Oil Corporation — Q2 2018 Form 10-Q
Reporting period: Three and six months ended June 30, 2018. Murphy Oil is an international oil and gas producer operating in the U.S., Canada and Malaysia. Amounts below are in U.S. dollars; financial statement amounts are converted from thousands to millions unless otherwise indicated.
Financial performance and key metrics
| Metric | Q2 2018 | Q2 2017 | Six months 2018 | Six months 2017 |
|---|---|---|---|---|
| Revenue from customer sales | $655.2 million | $477.6 million | $1,262.1 million | $986.6 million |
| Total revenue, including crude contract gains/losses and other items | $618.2 million | $508.3 million | $1,203.8 million | $1,184.9 million |
| Operating income | $142.1 million | $61.6 million | $269.1 million | $277.3 million |
| Net income (loss) | $45.5 million | $(17.6) million | $213.8 million | $40.9 million |
| Diluted earnings (loss) per share | $0.26 | $(0.10) | $1.22 | $0.24 |
Calculated operating margin, using total revenue, was approximately 23.0% in Q2 2018 versus 12.1% in Q2 2017, and 22.4% for the first half of 2018 versus 23.4% in the prior-year period. No gross margin measure is reported in the filing.
- Production: Q2 production averaged 171,000 barrels of oil equivalent per day (boe/d), up 5% year over year; first-half production averaged 169,300 boe/d, up 2%. Q2 oil and condensate production was nearly flat year over year; higher Canadian gas volumes contributed to growth.
- Prices and mix: Average realized crude oil and condensate prices were $68.03/barrel in Q2 and $65.85/barrel for the first half, up 42% and 35%, respectively, year over year. Company natural gas prices declined to $1.92/MCF in Q2 and $2.04/MCF in the first half.
- Cash flow and investment: First-half cash from continuing operating activities was $624.5 million versus $591.5 million. Property additions and dry-hole spending used $615.1 million; accrual-basis capital expenditures were $601.1 million, versus $415.0 million in the prior-year first half. Cash dividends paid were $86.5 million.
- Liquidity and debt: Cash and equivalents were $901.3 million at June 30, 2018, down from $965.0 million at year-end 2017. Working capital was $411.8 million, down $125.6 million. Long-term debt was $2,897.3 million, down $9.2 million from year-end; including current maturities, reported debt was approximately $2,907.0 million. The company had no borrowings under its $1.1 billion credit facility and $27.9 million of letters of credit; it reported compliance with facility covenants.
Material changes versus the prior comparable period
- Q2 net income improved from a loss to a profit, as higher realized oil prices and sales volumes lifted E&P results. These gains were partly offset by higher lease operating expenses and a $37.6 million Q2 loss on crude contracts, compared with a $26.9 million gain in Q2 2017.
- First-half net income rose to $213.8 million, but included a $120.0 million income-tax benefit tied to IRS guidance interpreting the 2017 Tax Act. Higher oil prices and volumes also helped results. First-half 2017 included a $132.4 million pretax gain on the Seal field sale; excluding that sale gain, management said Canadian operating results improved in 2018.
- Higher capital spending, principally for development drilling in Eagle Ford and Kaybob Duvernay, contributed to a $63.7 million decline in cash during the first half. Cash from operations exceeded property additions and dry-hole costs by only about $9.4 million on a cash basis.
- Accumulated other comprehensive loss increased to $575.1 million from $462.2 million at year-end, largely reflecting foreign currency translation losses.
Outlook, commentary, risks and unusual items
- Outlook: Management expected Q3 2018 production of 166,500–168,500 boe/d and full-year 2018 capital expenditures of approximately $1.18 billion. July crude prices had improved from the Q2 average; North American natural gas prices were relatively unchanged.
- Management expected to fund remaining 2018 capital spending primarily from operating cash flow, with credit-facility borrowings available if needed. It cautioned that weaker oil or gas prices could reduce cash flow and require spending cuts or additional borrowing.
- Price-risk positions at June 30 included U.S. WTI crude swaps covering 21,000 barrels/day through year-end at an average $54.88/barrel, and Canadian gas forward sales of 59 MMcf/day through December 2020 at C$2.81/MCF. The crude contracts had a recorded net liability of $68.9 million; the filing estimates a 10% benchmark-price increase would increase that payable by about $27.3 million.
- Tax item: IRS guidance allowed Murphy to preserve its 2017 tax net operating loss carryforward. The company recorded a $156 million first-quarter deferred tax benefit and a $36 million tax payable related to the deemed repatriation; it expects to pay the latter over eight years. The reported first-half tax benefit materially boosted earnings.
- Environmental contingency: For the Seal field condensate pipeline leak, Murphy recorded an additional $3.8 million expense in Q1 2018, had spent $41.5 million through June 30, and reported a remaining accrued liability of $6.3 million. It received $15.0 million of insurance proceeds in Q1; further insurance claims were pending. Management said ultimate remediation costs could exceed the accrual, while not expecting known or currently unidentified remediation costs to materially affect future results, cash flows or liquidity.
- Murphy drilled a successful appraisal well at the Samurai field in the U.S. Gulf of Mexico and expected further delineation in the second half of 2018. It had $206.4 million of capitalized exploratory well costs pending proved-reserve determination, including $171.6 million capitalized for more than one year.
- The filing identifies commodity-price volatility, exploration success, production and reserve replacement, foreign exchange, political and regulatory instability, capital-market conditions and natural hazards as risks. It reported no newly identified risk factors and stated disclosure controls were effective.
Important facts for investors to verify
- How much of first-half earnings growth is attributable to the nonrecurring $120.0 million tax benefit, and what tax attributes remain available.
- Whether planned capital spending can be funded by operating cash flow if commodity prices weaken, and whether borrowing or capital reductions become necessary.
- The expected persistence of crude-contract losses and the resulting exposure relative to realized production prices.
- Production trends by region, particularly Malaysia field decline and growth in Canada, alongside the Q3 production range.
- The final cost and insurance recovery for the Seal leak remediation, and the status of the aged exploratory well costs and related project decisions.