EOG Resources, Inc. — Q3 2012 Form 10-Q
Reporting period: Three and nine months ended September 30, 2012; unaudited. Dollar amounts below are in millions unless stated otherwise.
Business context and reporting period
EOG is an independent oil and natural gas producer operating in the United States, Canada, Trinidad, the United Kingdom, China and Argentina. Its strategy emphasizes returns on capital, cost control and developing internally generated prospects. In 2012 it prioritized North American crude oil and liquids-rich plays, particularly the Eagle Ford, Bakken and Permian. Oil and natural gas liquids (NGLs) represented about 45% of company production in the first nine months, versus 35% a year earlier.
Financial and operating performance
| Metric | Q3 2012 | Q3 2011 | Nine months 2012 | Nine months 2011 |
|---|---|---|---|---|
| Net operating revenues | $2,955 | $2,886 | $8,671 | $7,353 |
| Operating income | $606 | $950 | $1,858 | $1,811 |
| Net income | $355 | $541 | $1,075 | $970 |
| Diluted EPS | $1.31 | $2.01 | $3.98 | $3.66 |
| Operating margin | 20.5% | 32.9% | 21.4% | 24.6% |
| Net margin | 12.0% | 18.7% | 12.4% | 13.2% |
Q3 revenue rose 2%, but operating income fell 36% and net income fell 34%. For the first nine months, revenue increased 18%, operating income 3% and net income 11%. The filing attributes the stronger year-to-date result principally to higher oil volumes and prices, partly offset by lower natural gas and NGL prices.
- Production and realized prices: Q3 oil and condensate production was 169.3 thousand barrels per day (up 42%); the composite realized price was $97.13/barrel (up 11%). NGL production was 59.0 thousand barrels per day (up 34%), while price fell 39% to $31.11/barrel. Natural gas production was 1,512 million cubic feet per day (down 5%); price fell 22% to $3.07/Mcf.
- Drivers and cost pressures: Q3 crude oil and condensate revenue grew 59%; natural gas revenue declined 26% and NGL revenue declined 18%. DD&A increased to $826 million from $652 million, and transportation costs rose to $164 million from $109 million, reflecting higher production and transportation activity. Total operating expenses increased 21%.
- Cash flow: Nine-month operating cash flow was $4,010, versus $3,342 in 2011. Investing cash outflow was $4,678; financing cash inflow was $1,161. Cash increased by $497 to $1,113. Cash additions to oil and gas properties were $5,327, and additions to other property, plant and equipment were $477.
- Liquidity and debt: Current assets were $4,000 and current liabilities $2,578 at September 30, implying a current ratio of about 1.55. Cash was $1,113. Long-term debt on the balance sheet was $6,305, up from $5,009 at year-end 2011; management reported debt-to-total-capitalization of 31%, versus 28%. The $2.0 billion revolving credit facility had no borrowings or letters of credit outstanding.
- Dividends: Dividends declared were $0.17 per share in Q3 and $0.51 per share year to date, compared with $0.16 and $0.48, respectively, in 2011.
Material changes versus the prior comparable period
- Q3 results were affected by a sharp year-over-year reduction in mark-to-market commodity derivative gains: $5 million versus $358 million. For nine months, such gains were $327 million versus $481 million. Cash inflows from settled commodity derivatives were $249 million in Q3 and $556 million year to date, compared with $52 million and $84 million, respectively, in 2011.
- Q3 gains on asset dispositions were $67 million, compared with $207 million; nine-month gains were $248 million, compared with $443 million. The company received about $1,214 million from property and acreage sales during the first nine months, primarily in the Rocky Mountain, Upper Gulf Coast and Canada areas.
- Oil and condensate production growth, mainly from the Eagle Ford and Bakken, shifted the production mix toward liquids. Natural gas production declined, partly because of asset sales and lower output in the United States and Canada; Trinidad production increased.
- Nine-month impairments declined to $250 million from $531 million, though EOG recorded a $110 million pretax impairment on property, plant and equipment during the period.
Guidance, outlook, risks and unusual items
- Management estimated 2012 exploration, development and other property, plant and equipment expenditures at approximately $7.6 billion, excluding non-cash items, and expected spending to exceed operating cash flow. The company cited debt issuance and asset sales as funding sources, while retaining flexibility to adjust spending and use available financing.
- On September 10, EOG issued $1.25 billion of 2.625% senior notes due 2023, receiving net proceeds of approximately $1.234 billion for general corporate purposes, including capital expenditures and repayment of commercial paper. A 10-year Eagle Ford crude-oil storage-tank lease was accounted for as a capital lease, with a $66 million asset and liability recognized.
- Commodity prices and derivative positions remain significant sources of variability. At September 30, oil and gas derivatives were a net asset of approximately $245 million. The filing lists substantial oil and gas derivative positions for the remainder of 2012 and 2013; counterparties hold options that could increase covered volumes. Derivative contracts are marked to market, not designated as accounting hedges.
- Management identified risks including commodity prices and demand, development and production performance, transportation and service availability and cost, regulation and taxes, reserve-estimate uncertainty, financing access, counterparty credit, foreign exchange, and political and general economic conditions.
- Various ordinary-course lawsuits and claims are pending; management did not expect them, individually or in aggregate, to materially adversely affect financial position, results or cash flow. The company reported effective disclosure controls and no material change in internal control over financial reporting.
- Project milestones included expected Conwy/Corfe initial production in the second half of 2013 and expected U.K. approval of the revised Columbus development plan in the first quarter of 2013; these are forward-looking expectations, not assurances.
Most important facts for investors to verify
- Whether oil and liquids production growth and realized prices offset declining natural gas and NGL prices and rising DD&A and transportation costs.
- Whether the $7.6 billion 2012 capital program and expected cash-flow shortfall can be funded without materially weakening leverage or liquidity.
- How much derivative volume counterparties elect to add, the resulting realized cash flows, and the sensitivity of earnings to mark-to-market changes.
- The sustainability and composition of earnings, including derivative gains, asset-disposition gains and marketing revenue that largely carries offsetting marketing costs.
- Progress, approval and economics of international projects and the aged exploratory well costs, including Columbus and the Horn River Basin project.