EOG Resources, Inc. — Q3 2015 Form 10-Q
Reporting period: Quarter and nine months ended September 30, 2015; unaudited. EOG is an independent oil and gas producer, with operations primarily in the United States and also in Trinidad and other international locations.
Financial performance and condition
- Q3 revenue: $2.172 billion, down 58% from $5.119 billion in Q3 2014. Wellhead revenue declined 54%; lower realized commodity prices were the principal driver.
- Q3 earnings: Operating loss was $6.223 billion and net loss was $4.076 billion, or $7.47 per diluted share, versus net income of $1.104 billion, or $2.01 per diluted share, a year earlier. The quarter included $6.307 billion of impairment expense; management attributed the major property write-downs to lower commodity prices.
- Nine-month results: Revenue was $6.961 billion, down 48%; operating loss was $6.356 billion and net loss was $4.240 billion, or $7.77 per diluted share, versus net income of $2.471 billion, or $4.51 per diluted share, in 2014. Impairment expense was $6.445 billion.
- Commodity prices and production: Q3 composite realized prices were $45.91 per barrel for crude oil and condensate (down 53%), $13.24 per barrel for NGLs (down 59%), and $2.40 per Mcf for natural gas (down 32%). Total production averaged 569.6 thousand Boe per day, down from 614.1 thousand; nine-month production averaged 573.1 thousand Boe per day versus 589.7 thousand.
- Cash flow: Nine-month operating cash flow was $2.979 billion, compared with $6.539 billion in 2014. Investing cash outflow was $4.545 billion; financing cash inflow was $231 million. Cash declined to $743 million from $2.087 billion at year-end 2014.
- Liquidity and debt: At September 30, cash was $743 million, current assets $2.825 billion and current liabilities $2.047 billion. Long-term debt was $6.394 billion, with $36 million of short-term borrowings and current debt. Debt-to-total capitalization was 33%, versus 25% at year-end 2014. EOG had no borrowings under its new $2.0 billion revolving credit facility, due 2020.
- Capital and shareholder returns: Nine-month expenditures totaled $4.312 billion. Dividends paid were $275 million; quarterly dividends declared were $0.1675 per share, unchanged from Q3 2014.
Material changes versus the prior comparable period
- Sharp declines in oil, NGL and gas prices drove lower revenue and cash generation; Q3 crude oil and condensate production also fell 7% year over year. Lower mark-to-market derivative gains—$29 million versus $469 million—further reduced the revenue comparison.
- Commodity-price-related impairments were the exceptional item behind the reported losses. Management reported Q3 write-downs of $6.081 billion pretax for proved oil and gas properties and related assets; the financial statements report $6.307 billion of total impairment expense for the quarter.
- Nine-month operating cash flow fell $3.559 billion year over year. EOG issued $1.0 billion of senior notes in March, repaid $500 million of notes at maturity in June, and established a replacement revolving facility in July.
- EOG completed the sale of substantially all Canadian operations in Q4 2014, affecting year-over-year production and expenses. In Q3 2015 it acquired Delaware Basin properties for approximately $368 million.
Outlook, commentary, risks and contingencies
- Management expected 2015 crude oil and condensate plus NGL production to be relatively flat versus 2014. The 2015 capital expenditure estimate was $4.7–$4.9 billion, excluding acquisitions; spending was focused principally on U.S. crude oil drilling and could be adjusted as conditions warrant.
- Management cited drilling and completion efficiency, cost control, and a strong prospect inventory as strategic priorities. First production from the U.K. Conwy field was anticipated by year-end 2015, although the project recorded a $138 million impairment in Q3. Management was evaluating options for its Argentina investment.
- EOG warned that lower commodity prices could reduce year-end 2015 reported reserves: the trailing 12-month prices used for SEC reserve calculations had fallen approximately 45% for crude oil and condensate and 40% for natural gas versus prices used in its 2014 year-end reserve estimates. The amount of any reserve revision was not yet predictable.
- Outstanding oil and gas derivatives had a $71 million net asset fair value at September 30. Contracts included crude oil swaps at $89.98 per barrel for 10,000 barrels per day through year-end and put options at a $45 strike for 82,500 barrels per day in October–November. Derivative results are marked to market, not designated as accounting hedges.
- Risks include commodity-price volatility, reserve and production uncertainty, transportation and service availability and costs, regulatory and environmental requirements, access to capital, and counterparty and geopolitical risks. Various ordinary-course legal claims were pending; management did not expect them, individually or collectively, to materially adversely affect financial position, results or cash flow.
Key facts for investors to verify
- How much of the impairment charge reflects recurring asset economics versus noncash write-downs, and whether further impairments or reserve revisions follow from commodity prices.
- Whether production, realized prices and operating cash flow support the 2015 flat-production expectation and the stated capital budget.
- Cash and debt trends, capital-spending funding, and compliance with the revolving facility’s debt-to-capitalization covenant.
- Actual performance and timing of Conwy, Delaware Basin acquisitions, and the company’s remaining international investments.
- Derivative volumes, counterparty exposure and the sensitivity of future results to commodity prices; the filing does not provide a single clear forecast for future earnings or cash flow.