EOG Resources, Inc. — Q3 2013 Form 10-Q
Reporting period: Three and nine months ended September 30, 2013; filed November 6, 2013. EOG is an independent oil and gas producer operating in the United States, Canada, Trinidad and other international markets. Amounts below are in U.S. dollars.
Financial and operating performance
| Metric | Q3 2013 | Q3 2012 | Nine months 2013 | Nine months 2012 |
|---|---|---|---|---|
| Net operating revenues | $3.541B | $2.955B | $10.738B | $8.671B |
| Operating income | $770M | $606M | $2.695B | $1.858B |
| Net income | $462M | $355M | $1.617B | $1.075B |
| Diluted earnings per share | $1.69 | $1.31 | $5.93 | $3.98 |
| Operating cash flow | — | — | $5.328B | $4.010B |
- Q3 reported operating margin was approximately 21.7%, versus 20.5% a year earlier; nine-month margin was approximately 25.1%, versus 21.4%. These ratios use reported net operating revenues, which include marketing revenue and mark-to-market derivative results.
- Q3 production averaged 526,400 barrels of oil equivalent per day, up about 10% year over year. Nine-month production averaged 502,800 Boe/d, up about 7%. Oil and NGLs made up approximately 55% of total company production for the nine months, compared with 45% in 2012.
- For the first nine months, crude oil and condensate revenue rose 46%, driven by higher volumes and realized prices. NGL revenue rose 7%, as volume growth was partly offset by lower prices. Natural gas revenue rose 10% as higher prices outweighed lower volumes.
- Cash and cash equivalents were $1.319B at September 30, up from $876M at year-end 2012. Current assets were $4.192B and current liabilities $3.347B. Total debt was approximately $6.313B; management reported debt-to-total capitalization of 30%, down from 32% at year-end.
- Investing cash outflow was $4.763B and financing cash outflow was $127M for the first nine months. Cash increased by $442M. Dividends paid were $148M. Cash additions to oil and gas and other property were $5.355B; this is a cash-flow measure and differs from reported total expenditures.
Material changes versus the comparable period
- Net income increased 30% in Q3 and 50% for the nine-month period. Growth reflected stronger wellhead revenues, especially from U.S. oil production and prices.
- Derivative mark-to-market results swung to losses: $293M in Q3 2013 versus $5M of gains in Q3 2012, and $207M of losses for nine months versus $327M of gains. These non-cash valuation movements can make reported revenue and earnings volatile; settled derivatives generated a $115M net cash inflow for nine months, versus $556M in the prior-year period.
- Transportation costs rose to $629M for nine months from $432M, while DD&A rose to $2.686B from $2.383B. Management attributed higher DD&A in part to increased U.S. production, higher unit rates, and prior downward revisions to natural gas reserves.
- Revenue gains were partly offset by lower net gains on asset dispositions ($186M versus $248M for nine months). Asset-sale proceeds also declined to $587M from $1.214B.
- Oil and liquids growth was concentrated in the Eagle Ford, Permian Basin and Bakken. Natural gas deliveries declined 13% for nine months, largely reflecting asset sales and reduced U.S. gas drilling, as well as lower Trinidad volumes.
Outlook, commentary, risks and unusual items
- Management estimated 2013 capital expenditures at $7.0B–$7.2B, excluding acquisitions, with most spending directed to U.S. crude oil and liquids-rich plays. It expected capital expenditures to be slightly higher than operating cash flow and cited non-core asset sales as a means to address any shortfall.
- EOG emphasized returns on invested capital, cost control, reserve recovery and production growth. It expected crude oil and NGL production to continue increasing in 2013, both in volume and as a share of total production.
- After the quarter, on October 1, EOG repaid $400M of 6.125% senior notes at maturity. A $2.0B unsecured revolving credit facility had no borrowings or letters of credit outstanding at September 30. A separate $68M cash deposit was restricted as collateral for Canadian well-abandonment obligations.
- Crude oil and natural gas derivatives had a net liability fair value of $127M at September 30. Commodity derivatives are not designated as accounting hedges, so fair-value changes are recorded in earnings. Contract volumes and potential counterparty extension options affect future price exposure.
- Unusual items included $93M of nine-month impairments of proved properties and other assets, a $24.1M write-off related to the UK Columbus gas project in Q2, and an unsuccessful exploratory well in the UK in Q3. Management said ordinary-course lawsuits and claims were not expected to have a material adverse effect, though outcomes are uncertain.
- Forward-looking risks include commodity prices and demand, drilling and reserve-recovery performance, access to transportation and services, operating costs, regulation and environmental requirements, financing access, counterparty credit, and political and currency risks. Management reported effective disclosure controls and no material change in internal control over financial reporting.
Important facts for investors to verify
- How much earnings and realized cash generation depend on commodity prices versus derivative settlements and mark-to-market movements.
- Whether the 2013 capital budget, production growth and expected asset-sale proceeds are consistent with operating cash flow and liquidity.
- Trends in transportation expense, DD&A per Boe, reserve revisions and the economics of the company’s oil-focused development program.
- Upcoming debt maturities and refinancing plans, including the notes classified as long-term based on management’s intent to replace them.
- Potential effects of derivative counterparty options, restricted cash requirements, regulatory obligations and unresolved legal or environmental matters.