EOG Resources, Inc. — Q2 2013 Form 10-Q
Reporting period: Three and six months ended June 30, 2013. Unaudited consolidated results; amounts below are U.S. dollars, rounded to millions unless noted.
Business context
EOG is an independent oil and 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. North American activity focused on crude oil and liquids-rich plays, notably the Eagle Ford, Permian and Bakken.
Financial and operating performance
| Metric | Q2 2013 | Q2 2012 | Six months 2013 | Six months 2012 |
|---|---|---|---|---|
| Net operating revenues | $3,840m | $2,909m | $7,197m | $5,716m |
| Operating income | $1,092m | $692m | $1,925m | $1,252m |
| Net income | $660m | $396m | $1,154m | $720m |
| Diluted earnings per share | $2.42 | $1.47 | $4.24 | $2.67 |
| Operating margin (approx.) | 28.4% | 23.8% | 26.7% | 21.9% |
| Net margin (approx.) | 17.2% | 13.6% | 16.0% | 12.6% |
- Q2 wellhead revenue rose 41% to $2,654m. Oil and condensate sales increased 46% to $2,013m; natural gas liquids revenue rose 19% to $178m; natural gas revenue rose 29% to $463m.
- Q2 production averaged 505.9 thousand barrels of oil equivalent per day, up from 480.5 thousand. Oil and condensate production increased 35% to 214.4 thousand barrels per day, while natural gas volumes fell 15% to 1,361 million cubic feet per day. Six-month production averaged 490.8 thousand Boe/d versus 465.2 thousand.
- Q2 net mark-to-market commodity derivative gains were $191m, compared with $188m. For the first half, such gains declined to $87m from $323m. These financial commodity contracts are not designated as accounting hedges, so fair-value changes affect reported earnings.
- Cash from operations for the first half was $3,316m, up from $2,573m. Investing activities used $2,887m, including $3,250m of additions to oil and gas properties; financing activities used $78m. Cash increased $352m to $1,228m.
- At June 30, cash was $1,228m, current assets $4,241m and current liabilities $3,020m. Total debt on the balance sheet was approximately $6,313m, including $407m current and $5,906m long-term. Debt-to-total capitalization was 31%, versus 32% at year-end 2012. No commercial paper borrowings or revolver borrowings were outstanding; the $2.0bn revolving credit facility was undrawn.
- Dividends declared increased to $0.1875 per share per quarter from $0.17. First-half dividends paid were $97m.
Material changes and unusual items
- Growth was led by higher oil volumes and stronger realized oil and gas prices. Q2 composite oil price was $103.19/bbl versus $95.20; composite natural gas price was $3.73/Mcf versus $2.47. NGL price declined to $30.33/bbl from $33.72.
- Higher transportation costs, DD&A and interest expense partly offset revenue growth. Q2 transportation costs increased $89m year over year; oil and gas DD&A increased $111m. The oil and gas DD&A unit rate rose primarily following downward natural-gas reserve revisions at year-end 2012 and a greater production mix from higher-cost properties.
- First-half asset-sale proceeds were approximately $580m, versus $1,112m in the prior-year period. 2013 sales included EOG’s interests in the planned Kitimat LNG terminal, proposed Pacific Trail Pipelines and Horn River Basin acreage, as well as other properties and acreage. First-half 2013 gains on asset dispositions were $177m.
- Q2 included a $24.1m write-off related to the Central North Sea Columbus natural gas project. First-half impairments totaled $92m, down from $187m a year earlier.
Outlook, risks and contingencies
- Management estimated 2013 capital expenditures of $7.0bn–$7.2bn, excluding acquisitions, with most directed to U.S. oil and liquids-rich drilling. EOG expected spending to exceed operating cash flow and planned non-core asset sales to help fund the shortfall; management cited flexibility to adjust spending and access financing.
- Management expected crude oil and NGL production to continue rising in 2013, in total and as a share of company output. The filing does not provide a clear numerical full-year production target.
- Development milestones included planned Trinidad well completions and initial production beginning in Q3, anticipated Conwy field production in mid-2014, and an exploratory well planned in the Central North Sea in the second half of 2013.
- Commodity-price, reserve, development, transportation capacity and cost, regulatory, financing, counterparty, foreign-exchange and operational risks could affect results. Derivatives mitigate some price exposure but also create mark-to-market volatility and counterparty/collateral exposure.
- Canadian regulatory requirements led EOG’s subsidiary to establish a letter-of-credit facility for well-abandonment security; $52m of cash was restricted as collateral at June 30. The filing reports ordinary-course lawsuits and claims; management did not expect them, individually or together, to materially adversely affect financial position, results or cash flow.
- Management reported effective disclosure controls and no material change in internal control over financial reporting during the quarter.
Important facts for investors to verify
- Whether the $7.0bn–$7.2bn capital plan, asset-sale funding assumptions and expected production mix remain on track.
- How much of reported earnings and cash generation reflects realized operating performance versus derivative mark-to-market gains and asset-disposition gains.
- Whether rising transportation and DD&A costs, reserve revisions and lower gas volumes affect well-level returns and future profitability.
- The amount and timing of any 2014 debt refinancing, particularly the $350m floating-rate notes and $150m subsidiary debt classified as long-term based on management’s intent and ability to replace them.
- Potential changes in derivative positions, including counterparty extension options, and the effect of commodity prices, collateral terms and restricted cash on liquidity.