EOG Resources, Inc. — 2018 Form 10-K Summary
Business context and reporting period
EOG explores, develops, produces and markets crude oil, natural gas liquids (NGLs) and natural gas, predominantly in the United States, with operations in Trinidad, China and Canada. This filing covers the fiscal year ended December 31, 2018; the filing was signed February 26, 2019. EOG’s strategy emphasizes returns on capital, cost control and internally generated drilling opportunities. It sold its U.K. operations in the fourth quarter.
Financial and operating performance
| Metric | 2018 | 2017 |
|---|---|---|
| Operating revenues and other | $17.275 billion | $11.208 billion |
| Operating income | $4.469 billion | $926 million |
| Net income | $3.419 billion | $2.583 billion |
| Diluted EPS | $5.89 | $4.46 |
| Cash from operating activities | $7.769 billion | $4.265 billion |
| Net cash used in investing activities | $6.170 billion | $3.987 billion |
| Capital expenditures, as reported in the filing | $6.706 billion | $4.613 billion |
| Debt-to-total capitalization | 24% | 28% |
Operating margin was approximately 25.9% of reported revenue, compared with 8.3% in 2017; net margin was approximately 19.8% versus 23.0%. The net margin comparison reflects a substantial 2017 tax benefit rather than weaker 2018 operating performance. Fourth-quarter 2018 revenue was $4.575 billion, operating income $1.123 billion and net income $893 million.
- Total production averaged 719.2 thousand barrels of oil equivalent per day, up from 608.9 thousand in 2017. U.S. production rose to 664.7 thousand Boe per day.
- Wellhead production revenue increased 51% to $11.946 billion. Crude oil and condensate production rose 19% to 399.9 thousand barrels per day; NGL production rose 31% to 116.1 thousand barrels per day; natural gas production rose 11% to 1,219 MMcfd.
- Composite realized prices, before derivative effects, were $65.21 per barrel for crude oil and condensate, $26.60 per barrel for NGLs and $2.92 per Mcf for natural gas. The gas-price comparison includes a $0.44/Mcf revenue-presentation adjustment associated with adopting the new revenue standard.
- Cash and cash equivalents were $1.556 billion. Current assets of $5.057 billion exceeded current liabilities of $3.728 billion, implying working capital of about $1.329 billion and a current ratio of approximately 1.36.
- Year-end debt was approximately $6.083 billion, including capital lease obligations. EOG repaid $350 million of notes at maturity; year-end commercial paper and revolving-credit borrowings were zero. Its $2.0 billion revolving facility was undrawn, and the company reported covenant compliance.
- EOG paid $438 million of dividends in 2018 and raised its quarterly dividend during the year. The annual dividend was $0.81 per share.
Material changes versus 2017
- Revenue increased 54% and operating income rose to $4.469 billion, reflecting higher commodity prices and production growth, particularly in the Permian Basin and Eagle Ford.
- Operating cash flow increased $3.504 billion to $7.769 billion. Investment spending also increased substantially as EOG expanded drilling and development activity.
- Net income rose 32%, but 2017 included an approximately $2.2 billion tax benefit from remeasuring deferred taxes after the Tax Cuts and Jobs Act. EOG recorded an $822 million tax provision in 2018, versus a $1.921 billion tax benefit in 2017.
- Commodity derivative mark-to-market results shifted to a $166 million loss from a $20 million gain; 2018 included $259 million of net cash payments on settlements.
- Asset dispositions generated a $175 million net gain in 2018, compared with a $99 million net loss in 2017. 2018 impairment expense declined to $347 million from $479 million, though legacy natural-gas assets remained a principal source of proved-property impairments.
- EOG adopted the revenue-recognition standard in 2018. It moved certain gas-processing fees from a revenue deduction to gathering and processing costs, increasing reported revenue and expenses by about $223 million with no impact on operating income, net income or cash flow.
- Proved reserves increased 401 MMBoe to 2,928 MMBoe. Reserve additions were primarily from U.S. drilling and technical evaluations; approximately 98% of year-end proved reserves were in the United States.
Outlook, risks and unusual items
- For 2019, EOG forecast total and crude-oil production to increase from 2018 levels and planned capital expenditures of approximately $6.1–$6.5 billion, excluding acquisitions and non-cash exchanges. It expected to concentrate spending on U.S. crude-oil activity, especially the Eagle Ford, Delaware Basin and Rocky Mountain area.
- Management cited continued efficiency improvements, lower drilling and completion costs, and a strong prospect inventory as priorities. Area plans included approximately 300 net Eagle Ford well completions, 15 Austin Chalk completions and 270 Permian completions.
- EOG did not provide a specific 2019 production-growth percentage or earnings guidance in the supplied filing text. As of February 19, 2019, average 2019 NYMEX prices were $57.15/bbl for crude oil and $2.89/MMBtu for natural gas. Management emphasized that prices are volatile and difficult to predict.
- Management estimated that each $1/bbl change in wellhead crude-oil price, together with the associated NGL-price change, would affect 2019 net income by about $133 million and pretax operating cash flow by about $173 million. Each $0.10/Mcf change in applicable natural-gas price was estimated to affect net income by about $29 million and pretax operating cash flow by about $37 million.
- Key risks include commodity-price declines, drilling and reserve-estimation uncertainty, access to gathering and transportation capacity, operating incidents and weather, customer and counterparty exposure, foreign-country risks, and potential changes to environmental, climate, hydraulic-fracturing and tax rules. Insurance may not cover all losses.
- Contractual obligations totaled $14.196 billion, including $6.040 billion of senior notes, $3.781 billion of transportation and storage commitments, and significant drilling and fracturing-service commitments. The company also reported $6.808 billion of minimum commitments for specified leases, services and purchases; categories and timing differ from the contractual-obligations table.
- Management said ordinary-course lawsuits and claims were not expected to have a material adverse effect. Deloitte & Touche issued unqualified opinions on the financial statements and internal control over financial reporting; management also reported effective disclosure controls.
Important facts for investors to verify
- Whether 2019 production growth and the $6.1–$6.5 billion capital plan are delivered while maintaining returns and cost discipline.
- How much of the 401 MMBoe reserve increase reflects drilling and technical additions versus commodity-price assumptions, and whether PUDs are converted on schedule.
- The sensitivity of cash flow and earnings to commodity prices, especially given the 2018 derivative losses and limited protection from price declines in forecast 2019 production.
- Liquidity and refinancing plans for the $900 million of debt due in 2019, alongside the company’s substantial transportation, drilling and service commitments.
- Execution and commercial progress in key basins, infrastructure availability, and the implications of the U.K. divestiture and remaining international operations.
- Potential cost or operating impacts from environmental, climate, hydraulic-fracturing and other regulatory changes, as well as reserve-estimation and impairment assumptions.