ConocoPhillips — Q3 2014 Form 10-Q
Reporting period: Three and nine months ended September 30, 2014. The interim financial statements are unaudited. Unless stated otherwise, amounts are in U.S. dollars.
Business context
ConocoPhillips is a global exploration and production company operating in 27 countries. It reported six operating segments and continued to prioritize higher-margin oil, condensate and LNG projects. Results for Nigeria, Algeria and Kashagan are presented as discontinued operations; the Nigeria upstream sale closed in July 2014.
Financial performance
| Metric | Q3 2014 | Q3 2013 | Nine months 2014 | Nine months 2013 |
|---|---|---|---|---|
| Sales and operating revenues | $12.080bn | $13.643bn | $41.316bn | $41.159bn |
| Income from continuing operations | $1.649bn | $2.439bn | $5.831bn | $6.529bn |
| Net income attributable to ConocoPhillips | $2.704bn | $2.480bn | $6.908bn | $6.669bn |
| Diluted EPS, continuing operations | $1.31 | $1.95 | $4.63 | $5.23 |
| Diluted EPS, total | $2.17 | $2.00 | $5.54 | $5.38 |
| Dividends per share | $0.73 | $0.69 | $2.11 | $2.01 |
Q3 continuing-operations earnings fell 32%; nine-month earnings fell 11%. Total net income rose, principally because discontinued operations included the Nigeria sale gain. The filing does not provide a single consolidated operating-margin measure.
- Production: Q3 total production was 1,481 thousand barrels of oil equivalent per day (MBOED), including discontinued operations. Continuing-operations production excluding Libya was 1,473 MBOED; adjusted for Libya and downtime, it was up 4% year over year. Eagle Ford and Bakken combined production rose 33%.
- Prices: Q3 total realized price was $64.78 per BOE, down 7% year over year. Brent averaged $101.85 per barrel, down 8%; Henry Hub natural gas averaged $4.07 per thousand cubic feet, up 14%.
- Cash flow and investment: Nine-month operating cash flow was $14.138bn, including $13.995bn from continuing operations, versus $12.176bn total a year earlier. Capital expenditures and investments were $12.729bn, versus $11.281bn. Dividends paid were $2.618bn.
- Liquidity and debt: Cash and cash equivalents were $5.408bn at quarter-end, down from $6.246bn at year-end 2013. Total debt was $21.187bn, versus $21.662bn; debt-to-capital was 28%, versus 29%. The company reported $6.1bn of available revolving-credit capacity and $860m of Qatar Funding commercial paper outstanding.
- Balance sheet: Total assets were $118.986bn, total liabilities $63.325bn and total equity $55.661bn. Environmental remediation accruals were $366m.
Material changes and unusual items
- Lower asset-disposition gains, lower crude prices, higher operating expenses, impairments, lower LNG volumes and higher depreciation weighed on continuing earnings. Higher liquids volumes and gains associated with claims and settlements partly offset these effects.
- The July Nigeria upstream sale generated a reported $1.052bn before-tax gain in discontinued operations. Q3 discontinued-operations income was $1.078bn.
- Q3 other comprehensive loss was $1.913bn, largely reflecting a $1.932bn foreign-currency translation loss; comprehensive income attributable to ConocoPhillips was $791m.
- Lower 48 impairments were $102m in Q3; related undeveloped-leasehold impairment was recorded in exploration expense. The company also recorded a $145m pre-tax impairment for the Amauligak, Arctic Islands and other Beaufort properties after deferring development.
- Management expected a $520m after-tax charge when the Freeport LNG agreement termination became effective, alongside an approximately $50m one-time net cash outflow and anticipated annual operating-cost savings of $50m–$60m over 19 years.
Outlook, commentary and risks
- Management expected full-year 2014 continuing-operations production, excluding Libya, of approximately 1,525–1,535 MBOED; Q4 guidance was 1,545–1,575 MBOED. Q4 guidance reflected the absence of APLNG ramp-gas sales to a third-party LNG project, Malaysian infrastructure constraints and value-driven ethane rejection in the Lower 48.
- The 2014 capital budget remained $16.7bn; $12.7bn had been spent through September. Management said its 2015 capital-budget assessment was ongoing in response to weakening commodity prices.
- Management described the company as on track to meet its 2014 value proposition, which targets 3%–5% production and cash-margin growth normalized to 2013 prices. A 2015 capital-spending outlook was expected in December 2014.
- KBB first gas was expected in November 2014, but production was expected to be significantly constrained pending third-party pipeline repairs; peak production was anticipated by mid-2015. Management also expected a roughly $140m after-tax Q4 dry-hole charge for the Kamoxi-1 well, which it planned to plug and abandon.
- Key risks include volatile commodity prices, production and exploration uncertainty, operating and transportation constraints, political events and expropriation, environmental and climate regulation, litigation, and project execution. The company was pursuing damages in Venezuela and Ecuador arbitrations; amounts and outcomes were uncertain. It also reported approximately $3.0bn of maximum exposure under its APLNG project-finance completion guarantee.
Important facts for investors to verify
- How much reported net income and EPS depended on the Nigeria disposition gain, versus continuing operations.
- Whether production guidance was achieved, particularly excluding Libya, and whether third-party infrastructure constraints delayed KBB or other project ramp-ups.
- The effect of falling crude prices and the Lower 48 crude differential on realized prices, cash generation and the 2015 capital budget.
- The timing and accounting impact of the expected Freeport LNG termination charge, related cash flows and projected cost savings.
- Potential outcomes and exposures from APLNG guarantees, environmental liabilities and pending Venezuela, Ecuador and Timor-Leste proceedings.