EOG Resources, Inc. — 2014 Form 10-K Summary
Business context and reporting period
Annual report for the fiscal year ended December 31, 2014; the filing also provides unaudited quarterly results, including fourth-quarter 2014. EOG explores, develops, produces and markets oil and natural gas, with operations concentrated in the United States. At year-end, 97% of proved reserves were in the U.S. and 3% in Trinidad. EOG’s strategy emphasizes returns on capital, cost control and reserve recovery, with a growing focus on oil and liquids-rich plays.
Financial and operating results
| Metric | 2014 | 2013 |
|---|---|---|
| Net operating revenues | $18.04 billion | $14.49 billion |
| Operating income | $5.24 billion | $3.68 billion |
| Net income | $2.92 billion | $2.20 billion |
| Diluted EPS | $5.32 | $4.02 |
| Cash from operating activities | $8.65 billion | $7.33 billion |
| Capital expenditures and other property, plant and equipment | $8.63 billion | $7.36 billion |
| Year-end cash and equivalents | $2.09 billion | $1.32 billion |
| Principal debt outstanding | $5.89 billion | $5.89 billion |
For Q4 2014, revenue was $4.65 billion, operating income $1.23 billion and net income $445 million, compared with $3.75 billion, $980 million and $580 million, respectively, in Q4 2013. Thus, quarterly revenue and operating income rose, while net income declined.
Full-year operating margin was approximately 29.1% and net margin 16.2%, compared with approximately 25.4% and 15.2% in 2013. These are calculated from reported revenue and income. EOG reported current assets of $5.42 billion and current liabilities of $3.38 billion. Its debt-to-total-capitalization ratio was 25%, down from 28%. No commercial paper or revolving-credit borrowings were outstanding at year-end; the company had a $2.0 billion revolving credit agreement.
Production averaged 594.7 thousand barrels of oil equivalent per day, up from 510.1 thousand in 2013. U.S. production rose to 515.0 thousand Boe/day. Composite realized prices were $92.58/bbl for oil and condensate, $31.91/bbl for NGL and $3.88/Mcf for natural gas. Proved reserves increased 378 million Boe to 2.497 billion Boe; reserve additions from drilling and technical evaluation totaled 519 million Boe.
Material changes versus prior periods
- Annual revenue increased 24% and net income increased 33%. Production growth—especially in the Eagle Ford, Bakken and Permian—supported higher wellhead revenue, despite a 10% decline in the composite oil price.
- Reported revenue included an $834 million mark-to-market gain on commodity derivatives, versus a $166 million loss in 2013; cash received from derivative settlements was $34 million in 2014.
- Asset-disposition gains were $508 million, including a $383 million release of accumulated currency translation adjustments following the substantial liquidation of Canadian operations. EOG sold all Manitoba assets and most Alberta assets; proceeds were approximately $400 million, and about $150 million of restricted cash was released.
- Impairments rose to $744 million from $287 million, including $351 million for the U.K. Conwy project and $44 million for Argentina. The filing also cites impairment charges related to U.S. properties and lower commodity prices.
- The effective tax rate rose to 41.6% from 36.1%. EOG recorded $250 million of deferred tax on undistributed foreign earnings after ending its permanent-reinvestment assertion.
- Oil and condensate volumes grew 31%; natural gas volumes were nearly flat. The company’s North American production mix became more liquids-weighted.
Outlook, risks and contingencies
- For 2015, EOG forecast capital expenditures of $4.9–$5.1 billion, excluding acquisitions, focused mainly on U.S. crude-oil drilling. Management expected overall production to decline modestly, with crude-oil production flat, and did not plan to increase oil production in the low-price environment.
- As of January 30, 2015, average 2015 NYMEX oil and gas prices were $51.86/bbl and $2.85/Mcf, respectively—44% and 35% below 2014 average NYMEX prices. EOG disclosed sensitivities, including derivatives, of about $63 million of net income and $93 million of operating cash flow per $1/bbl oil-price change, and $15 million and $22 million, respectively, per $0.10/Mcf gas-price change.
- At February 16, 2015, disclosed 2015 derivative positions included oil swaps at weighted average prices of about $89.98–$91.22/bbl and gas contracts at about $4.48–$4.51/MMBtu, subject to counterparty extension options.
- Risks include commodity-price declines, reserve and impairment-estimate uncertainty, drilling and operational hazards, access to transport and processing capacity, environmental and hydraulic-fracturing regulation, foreign-country exposure, cybersecurity and counterparty risk. The filing warns lower prices could reduce cash flow, make projects uneconomic and prompt further impairments.
- Contractual obligations totaled $13.01 billion at year-end, including $4.20 billion of transportation and storage commitments. Management said ordinary-course lawsuits and claims were not expected to have a material adverse effect. EOG reported no off-balance-sheet arrangements; the auditor gave unqualified opinions on the financial statements and internal controls.
Important facts for investors to verify
- How much of 2014 earnings and cash generation is sustainable after separating derivative mark-to-market gains, asset-sale gains and the Canadian translation adjustment from recurring operations.
- Whether 2015 production, capital spending and cash-flow plans remain achievable under the sharp decline in oil and gas prices, and how much of production is hedged.
- The economics and impairment assumptions for Conwy, Argentina and other properties, plus any further effects of price changes on proved reserves and asset values.
- The ability to meet substantial transportation, drilling and service commitments while maintaining liquidity and the dividend; confirm debt maturities and available borrowing capacity.
- Reserve replacement and development execution in core U.S. plays, including the cost and recovery assumptions underlying the reported reserve additions and proved undeveloped reserves.