News Detail
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INVESTORS
EOG Resources Reports Third Quarter 2011 Results
- Achieves 11 Percent Total Company Organic Production Growth for First Nine Months of 2011 Versus Prior Year Period
- Reports 54 Percent Total Company Crude Oil and Condensate Volume Growth Third Quarter Year-Over-Year and 51 Percent Growth for First Nine Months Year-Over-Year
- Announces 49 Percent Total Liquids Volume Increase in Third Quarter and 47 Percent Growth for First Nine Months Year-Over-Year
- Records Continued Positive Results from Tighter Eagle Ford Well Spacing
- Realizes Ongoing Success in Permian Basin Wolfcamp
- Delivers Consistent Results from North Dakota Bakken and Fort Worth Barnett Combo
- Verifies 2011 Asset Disposition Program Still On Track
HOUSTON, Nov. 1, 2011 /PRNewswire/ -- EOG Resources, Inc. (NYSE: EOG) (EOG) today reported third quarter 2011 net income of $540.9 million, or $2.01 per diluted share. This compares to a third quarter 2010 net loss of $70.9 million, or $0.28 per diluted share.
Consistent with some analysts’ practice of matching cash flow realizations to settlement months, and making certain other adjustments in order to exclude non-recurring items, adjusted non-GAAP net income for the third quarter 2011 was $223.2 million, or $0.83 per share. Adjusted non-GAAP net income for the third quarter 2010 was $46.6 million, or $0.18 per share. The results for the third quarter 2011 included net gains on asset dispositions of $132.9 million, net of tax ($0.49 per share), a $10.6 million, net of tax ($0.04 per share) impairment of certain non-core North American assets and a previously disclosed non-cash net gain of $357.7 million ($229.0 million after tax, or $0.85 per share) on the mark-to-market of financial commodity contracts. During the quarter, the net cash inflow related to financial commodity contracts was $52.5 million ($33.6 million after tax, or $0.12 per share). (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income (loss).)
Operational Highlights
Driven by a 64 percent rise in United States crude oil and condensate production during the third quarter 2011, EOG delivered 54 percent total company crude oil and condensate production growth versus the third quarter 2010. For the first nine months of 2011, year-over-year crude oil and condensate production increased 51 percent. The South Texas Eagle Ford led the surge in crude oil production growth, followed by the Fort Worth Barnett Shale Combo.
Total company liquids production increased 49 percent in the third quarter 2011 over the same period in the prior year and 47 percent year-over-year for the first nine months of 2011.
EOG achieved 11 percent total company organic production growth for the first nine months of 2011 versus 2010. For the full year 2011, total company crude oil and condensate production is projected to increase by 51 percent, while total company liquids production is forecast to rise 47 percent compared to 2010.
“These extraordinary double-digit liquids growth rates, driven primarily by high value organic crude oil production, confirm that EOG’s transition to a crude oil and liquids-focused company is complete,” said Mark G. Papa, Chairman and Chief Executive Officer. “After assembling a best-in-class U.S. onshore liquids-rich portfolio, we are now harvesting these existing assets by maximizing their resource potential. Meanwhile, we continue to pursue new opportunities.”
Crude Oil and Liquids Activity
Across its dominant acreage position in the South Texas Eagle Ford crude oil window, EOG’s 2011 improved completion techniques and cost optimization practices continue to drive operational gains and enhanced well production results. Reflecting this combination, EOG has posted its best wells to date in the South Texas Eagle Ford. In Gonzales County, the northeastern-most part of EOG’s acreage, the Mitchell Unit #1H and #2H began initial production at peak rates of 2,821 and 3,090 barrels of crude oil per day (Bopd) with 2.8 and 2.9 million cubic feet per day (MMcfd) of rich natural gas, respectively. The Meyer Unit #1H, #2H and #6H started sales at peak crude oil rates of 2,372, 1,600 and 2,918 Bopd, respectively, and produced 1.8, 2.2 and 2.7 MMcfd of associated rich natural gas, respectively. The Kerner Carson Unit #1H, #2H, #4H, #6H, #8H and #10H wells were turned to sales at crude oil production rates ranging from 1,580 to 2,239 Bopd with 1.2 to 1.9 MMcfd of rich natural gas. EOG has 100 percent working interest in these Gonzales County wells.
South of Gonzales in Karnes County, the center of EOG’s acreage, the AFO Unit #1H, #2H and #3H began initial maximum production at 2,289, 1,700 and 1,548 Bopd, respectively, with rich natural gas production ranging from 1.2 to 1.6 MMcfd. EOG has 100 percent working interest in these wells. EOG has 50 percent working interest in the Deleon-Reinhard Unit #1H and Deleon-Wiatrek Unit #1H wells, which were completed at peak crude oil rates of 2,235 Bopd with 1.2 MMcfd and 2,161 Bopd with 1.7 MMcfd of rich natural gas, respectively.
In LaSalle County, EOG’s southwestern-most acreage, the Naylor Jones A #6H and A #7H began initial production at 1,582 and 1,342 Bopd with 1.5 and 1.6 MMcfd of rich natural gas, respectively. EOG has 100 percent working interest in these wells.
“As we apply what we’ve learned about the Eagle Ford across our extensive operations, EOG’s production results just get better and better,” Papa said. “We are also seeing early positive results from each of our seven downspacing pilot programs. Drilling wells more tightly spaced than our original 130-acre patterns provides even more development opportunities for EOG.”
Across its other crude oil and liquids-rich shale plays, EOG also recorded strong, consistent performance. In the Rocky Mountains, EOG has maintained a steady level of drilling activity in the Colorado Niobrara Shale and Wyoming Powder River Basin plays. Drilling results from the Mid-Continent Marmaton and Permian Basin Leonard also continued to be positive.
In the Permian Basin Wolfcamp in Texas, EOG has been operating a two-rig program and plans to ramp up drilling activity early in 2012. Recent efforts have focused on completion techniques that increase reserves per well and improve cost efficiencies. In Irion and Crockett Counties, the University 40 #1306H, 40 #1308H and 40 #1504H were completed to sales with initial maximum production rates of 1,426, 1,293 and 1,338 Bopd with 0.9, 1.0 and 1.2 MMcfd of rich natural gas, respectively. EOG has 94 percent, 88 percent and 89 percent working interest in these wells, respectively. In Irion County, EOG has 88 percent working interest in the Mayer #5002H, which was turned to sales at 686 Bopd with 1.3 MMcfd of rich natural gas.
Operational improvements are evidenced by individual well results in EOG’s North Texas Fort Worth Barnett Shale Combo. The play was a significant contributor to EOG’s crude oil and liquids growth both during the third quarter and in the first nine months of 2011 versus the same period in 2010. In Montague County, the Ketchum Unit #1H and #2H were brought to sales at 496 and 638 Bopd with increasing rich natural gas rates of 354 and 455 thousand cubic feet per day, respectively. Also in Montague County, the Farrell Unit A #1H, A #2H, B #3H and B #4H began initial production at crude oil rates ranging from 335 to 475 Bopd with 1.0 to 1.4 MMcfd of rich natural gas. EOG has 100 percent working interest in these wells.
In North Dakota, EOG again reported consistent results from its drilling program. A number of wells were completed across the Bakken with strong initial production rates. In Mountrail County, the Liberty 18-14H LR, drilled with a 12,675-foot lateral, began initial production at 1,215 Bopd. EOG has 96 percent working interest in the well. In Dunn County, EOG has 84 percent working interest in the Horse Camp 2-11H and 101-11H. Completed in the Bakken and Three Forks formations, respectively, the wells began flowing to sales at initial maximum production rates of 1,323 and 1,833 Bopd, respectively. Also in the Three Forks, EOG has a 55 percent working interest in the Mandaree 102-05H, which was completed to sales at a maximum peak rate of 1,189 Bopd.
EOG has resumed normal operations in both North Dakota and Waskada, Manitoba following spring flooding that temporarily impacted drilling activity. In a new area of EOG’s horizontal Waskada crude oil play, three recent wells were completed with initial production rates ranging from 300 to 400 Bopd, rates consistent with its 2010 drilling program results.
“EOG continues to deliver consistent long-term production growth at high rates of return from our liquids-rich portfolio. We have the potential to see this growth trend continue for many years to come,” Papa said.
Natural Gas Activity
Consistent with EOG’s overall strategy and emphasis on crude oil and liquids-rich production growth, North America natural gas production decreased 9 percent in the third quarter 2011 compared to the same prior year period. This reflects reduced drilling activity in a weak natural gas price environment, as well as previously announced natural gas asset sales.
Capital Structure
During the first nine months of 2011, total cash proceeds from asset sales were $1.3 billion. EOG anticipates full-year property sales of approximately $1.6 billion.
At September 30, 2011, EOG’s total debt outstanding was $5.2 billion for a debt-to-total capitalization ratio of 29 percent. Taking into account $1.4 billion of cash on the balance sheet at the end of the third quarter, EOG’s net debt was $3.8 billion for a net debt-to-total capitalization ratio of 24 percent. EOG is targeting a net debt-to-total capitalization ratio of 30 percent or less at both year-end 2011 and 2012. (Please refer to the attached tables for the reconciliation of net debt (non-GAAP) to current and long-term debt (GAAP) and the reconciliation of net debt-to-total capitalization ratio (non-GAAP) to debt-to-total capitalization ratio (GAAP).)
“Our successful pursuit of high value crude oil and natural gas liquids growth is producing strong results for EOG. Most importantly, the majority of our liquids growth is oil as opposed to lower valued NGLs,” Papa said. “EOG’s strategy is consistent with the game plan we articulated four years ago.”
Conference Call Scheduled for November 2, 2011
EOG’s third quarter 2011 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Wednesday, November 2, 2011. To listen, log on to www.eogresources.com. The webcast will be archived on EOG’s website through November 16, 2011.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Canada, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol “EOG.”
This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production and costs and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production or generate income or cash flows are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known and unknown risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
- the timing and extent of changes in prices for, and demand for, crude oil, natural gas and related commodities;
- the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
- the extent to which EOG can optimize reserve recovery and economically develop its plays utilizing horizontal and vertical drilling and advanced completion technologies;
- the extent to which EOG is successful in its efforts to economically develop its acreage in, and to produce reserves and achieve anticipated production levels from, its existing and future crude oil and natural gas exploration and development projects, given the risks and uncertainties inherent in drilling, completing and operating crude oil and natural gas wells and the potential for interruptions of development and production, whether involuntary or intentional as a result of market or other conditions;
- the extent to which EOG is successful in its efforts to market its crude oil, natural gas and related commodity production;
- the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities;
- the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights-of-way;
- the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations, environmental laws and regulations relating to air emissions, waste disposal and hydraulic fracturing and laws and regulations imposing conditions and restrictions on drilling and completion operations;
- EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties;
- the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully and economically;
- competition in the oil and gas exploration and production industry for employees and other personnel, equipment, materials and services and, related thereto, the availability and cost of employees and other personnel, equipment, materials and services;
- the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
- weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation of production, gathering, processing, compression and transportation facilities;
- the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
- EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all;
- the extent and effect of any hedging activities engaged in by EOG;
- the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
- political developments around the world, including in the areas in which EOG operates;
- the timing and impact of liquefied natural gas imports;
- the use of competing energy sources and the development of alternative energy sources;
- the extent to which EOG incurs uninsured losses and liabilities;
- acts of war and terrorism and responses to these acts; and
- the other factors described under Item 1A, "Risk Factors", on pages 14 through 20 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2010 and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
Effective January 1, 2010, the United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). As noted above, statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2010, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov.
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For Further Information Contact: |
Investors |
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Maire A. Baldwin |
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(713) 651-6EOG (651-6364) |
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Elizabeth M. Ivers |
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(713) 651-7132 |
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Media |
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K Leonard |
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(713) 571-3870 |
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EOG RESOURCES, INC. |
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FINANCIAL REPORT |
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(Unaudited; in millions, except per share data) |
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Three Months Ended |
Nine Months Ended |
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September 30, |
September 30, |
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2011 |
2010 |
2011 |
2010 |
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Net Operating Revenues |
$ |
2,885.7 |
$ |
1,582.1 |
$ |
7,353.1 |
$ |
4,310.7 |
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Net Income (Loss) |
$ |
540.9 |
$ |
(70.9) |
$ |
970.4 |
$ |
107.0 |
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Net Income (Loss) Per Share |
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Basic |
$ |
2.03 |
$ |
(0.28) |
$ |
3.71 |
$ |
0.43 |
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Diluted |
$ |
2.01 |
$ |
(0.28) |
$ |
3.66 |
$ |
0.42 |
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Average Number of Shares Outstanding |
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Basic |
266.1 |
251.0 |
261.7 |
250.7 |
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Diluted |
269.3 |
251.0 |
265.2 |
254.4 |
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SUMMARY INCOME STATEMENTS |
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(Unaudited; in thousands, except per share data) |
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Three Months Ended |
Nine Months Ended |
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September 30, |
September 30, |
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2011 |
2010 |
2011 |
2010 |
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Net Operating Revenues |
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Crude Oil and Condensate |
$ |
953,154 |
$ |
506,368 |
$ |
2,649,034 |
$ |
1,368,338 |
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Natural Gas Liquids |
206,572 |
107,482 |
539,104 |
314,750 |
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Natural Gas |
576,803 |
602,242 |
1,760,715 |
1,832,578 |
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Gains on Mark-to-Market Commodity Derivative Contracts |
357,664 |
60,998 |
480,539 |
105,816 |
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Gathering, Processing and Marketing |
578,022 |
233,971 |
1,461,303 |
601,790 |
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Gains on Asset Dispositions, Net |
207,468 |
64,809 |
442,981 |
72,441 |
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Other, Net |
6,061 |
6,205 |
19,424 |
15,023 |
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Total |
2,885,744 |
1,582,075 |
7,353,100 |
4,310,736 |
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Operating Expenses |
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Lease and Well |
248,926 |
180,921 |
680,710 |
507,647 |
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Transportation Costs |
108,678 |
103,262 |
308,276 |
286,318 |
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Gathering and Processing Costs |
18,532 |
18,472 |
55,444 |
47,353 |
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Exploration Costs |
48,469 |
47,307 |
140,616 |
148,635 |
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Dry Hole Costs |
22,604 |
2,700 |
47,231 |
45,095 |
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Impairments |
83,431 |
352,908 |
531,413 |
502,865 |
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Marketing Costs |
572,604 |
231,758 |
1,427,450 |
591,735 |
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Depreciation, Depletion and Amortization |
651,684 |
500,888 |
1,822,854 |
1,398,137 |
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General and Administrative |
82,260 |
81,310 |
219,703 |
206,470 |
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Taxes Other Than Income |
98,526 |
74,244 |
308,669 |
227,773 |
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Total |
1,935,714 |
1,593,770 |
5,542,366 |
3,962,028 |
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Operating Income (Loss) |
950,030 |
(11,695) |
1,810,734 |
348,708 |
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Other Income, Net |
1,377 |
5,772 |
11,205 |
7,910 |
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Income (Loss) Before Interest Expense and Income Taxes |
951,407 |
(5,923) |
1,821,939 |
356,618 |
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Interest Expense, Net |
52,186 |
32,890 |
153,772 |
88,215 |
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Income (Loss) Before Income Taxes |
899,221 |
(38,813) |
1,668,167 |
268,403 |
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Income Tax Provision |
358,343 |
32,093 |
697,742 |
161,422 |
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Net Income (Loss) |
$ |
540,878 |
$ |
(70,906) |
$ |
970,425 |
$ |
106,981 |
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Dividends Declared per Common Share |
$ |
0.160 |
$ |
0.155 |
$ |
0.480 |
$ |
0.465 |
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EOG RESOURCES, INC. |
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OPERATING HIGHLIGHTS |
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(Unaudited) |
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Three Months Ended |
Nine Months Ended |
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September 30, |
September 30, |
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2011 |
2010 |
2011 |
2010 |
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Wellhead Volumes and Prices |
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Crude Oil and Condensate Volumes (MBbld) (A) |
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United States |
108.9 |
66.6 |
94.3 |
59.5 |
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Canada |
6.8 |
5.9 |
8.0 |
6.1 |
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Trinidad |
3.1 |
4.8 |
3.6 |
4.7 |
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Other International (B) |
0.1 |
0.1 |
0.1 |
0.1 |
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Total |
118.9 |
77.4 |
106.0 |
70.4 |
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Average Crude Oil and Condensate Prices ($/Bbl) (C) |
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United States |
$ |
87.22 |
$ |
71.54 |
$ |
91.40 |
$ |
72.58 |
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Canada |
90.54 |
69.12 |
92.76 |
71.32 |
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Trinidad |
89.70 |
65.06 |
91.56 |
66.91 |
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Composite |
87.49 |
70.96 |
91.52 |
72.09 |
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Natural Gas Liquids Volumes (MBbld) (A) |
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United States |
43.2 |
31.1 |
38.7 |
27.4 |
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Canada |
0.8 |
0.8 |
0.8 |
0.9 |
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Total |
44.0 |
31.9 |
39.5 |
28.3 |
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Average Natural Gas Liquids Prices ($/Bbl) (C) |
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United States |
$ |
50.90 |
$ |
36.56 |
$ |
49.85 |
$ |
40.68 |
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Canada |
57.69 |
40.34 |
54.36 |
42.90 |
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Composite |
51.02 |
36.66 |
49.93 |
40.75 |
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Natural Gas Volumes (MMcfd) (A) |
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United States |
1,122 |
1,175 |
1,123 |
1,096 |
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Canada |
123 |
200 |
135 |
205 |
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Trinidad |
330 |
333 |
354 |
342 |
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Other International (B) |
12 |
14 |
13 |
15 |
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Total |
1,587 |
1,722 |
1,625 |
1,658 |
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Average Natural Gas Prices ($/Mcf) (C) |
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United States |
$ |
4.06 |
$ |
4.21 |
$ |
4.13 |
$ |
4.50 |
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Canada |
3.81 |
3.42 |
3.88 |
4.09 |
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Trinidad |
3.59 |
2.53 |
3.42 |
2.54 |
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Other International (B) |
5.54 |
5.41 |
5.60 |
4.64 |
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Composite |
3.95 |
3.80 |
3.97 |
4.05 |
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Crude Oil Equivalent Volumes (MBoed) (D) |
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United States |
339.4 |
293.5 |
320.3 |
269.6 |
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Canada |
27.9 |
40.0 |
31.2 |
41.1 |
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Trinidad |
58.0 |
60.3 |
62.7 |
61.7 |
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Other International (B) |
2.0 |
2.5 |
2.2 |
2.6 |
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Total |
427.3 |
396.3 |
416.4 |
375.0 |
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Total MMBoe (D) |
39.3 |
36.5 |
113.7 |
102.4 |
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(A) |
Thousand barrels per day or million cubic feet per day, as applicable. |
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(B) |
Other International includes EOG's United Kingdom and China operations. |
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(C) |
Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments. |
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(D) |
Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalents are determined using the ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. |
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EOG RESOURCES, INC. |
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SUMMARY BALANCE SHEETS |
|||||||
|
(Unaudited; in thousands, except share data) |
|||||||
|
September 30, |
December 31, |
||||||
|
2011 |
2010 |
||||||
|
ASSETS |
|||||||
|
Current Assets |
|||||||
|
Cash and Cash Equivalents |
$ |
1,386,728 |
$ |
788,853 |
|||
|
Accounts Receivable, Net |
1,249,649 |
1,113,279 |
|||||
|
Inventories |
580,355 |
415,792 |
|||||
|
Assets from Price Risk Management Activities |
364,991 |
48,153 |
|||||
|
Income Taxes Receivable |
28,013 |
54,916 |
|||||
|
Deferred Income Taxes |
- |
9,260 |
|||||
|
Other |
125,626 |
97,193 |
|||||
|
Total |
3,735,362 |
2,527,446 |
|||||
|
Property, Plant and Equipment |
|||||||
|
Oil and Gas Properties (Successful Efforts Method) |
32,196,279 |
29,263,809 |
|||||
|
Other Property, Plant and Equipment |
1,993,824 |
1,733,073 |
|||||
|
Total Property, Plant and Equipment |
34,190,103 |
30,996,882 |
|||||
|
Less: Accumulated Depreciation, Depletion and Amortization |
(13,453,905) |
(12,315,982) |
|||||
|
Total Property, Plant and Equipment, Net |
20,736,198 |
18,680,900 |
|||||
|
Other Assets |
323,118 |
415,887 |
|||||
|
Total Assets |
$ |
24,794,678 |
$ |
21,624,233 |
|||
|
LIABILITIES AND STOCKHOLDERS' EQUITY |
|||||||
|
Current Liabilities |
|||||||
|
Accounts Payable |
$ |
1,926,455 |
$ |
1,664,944 |
|||
|
Accrued Taxes Payable |
157,297 |
82,168 |
|||||
|
Dividends Payable |
43,015 |
38,962 |
|||||
|
Liabilities from Price Risk Management Activities |
- |
28,339 |
|||||
|
Deferred Income Taxes |
139,646 |
41,703 |
|||||
|
Current Portion of Long-Term Debt |
220,000 |
220,000 |
|||||
|
Other |
179,910 |
143,983 |
|||||
|
Total |
2,666,323 |
2,220,099 |
|||||
|
Long-Term Debt |
5,007,746 |
5,003,341 |
|||||
|
Other Liabilities |
768,518 |
667,455 |
|||||
|
Deferred Income Taxes |
3,858,243 |
3,501,706 |
|||||
|
Commitments and Contingencies |
|||||||
|
Stockholders' Equity |
|||||||
|
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and |
|||||||
|
269,124,759 Shares Issued at September 30, 2011 and |
|||||||
|
254,223,521 Shares Issued at December 31, 2010 |
202,691 |
202,542 |
|||||
|
Additional Paid In Capital |
2,230,600 |
729,992 |
|||||
|
Accumulated Other Comprehensive Income |
372,448 |
440,071 |
|||||
|
Retained Earnings |
9,711,207 |
8,870,179 |
|||||
|
Common Stock Held in Treasury, 281,595 Shares at September 30, 2011 |
|||||||
|
and 146,186 Shares at December 31, 2010 |
(23,098) |
(11,152) |
|||||
|
Total Stockholders' Equity |
12,493,848 |
10,231,632 |
|||||
|
Total Liabilities and Stockholders’ Equity |
$ |
24,794,678 |
$ |
21,624,233 |
|||
|
EOG RESOURCES, INC. |
||||||||
|
SUMMARY STATEMENTS OF CASH FLOWS |
||||||||
|
(Unaudited; in thousands) |
||||||||
|
Nine Months Ended |
||||||||
|
September 30, |
||||||||
|
2011 |
2010 |
|||||||
|
Cash Flows from Operating Activities |
||||||||
|
Reconciliation of Net Income to Net Cash Provided by Operating Activities: |
||||||||
|
Net Income |
$ |
970,425 |
$ |
106,981 |
||||
|
Items Not Requiring (Providing) Cash |
||||||||
|
Depreciation, Depletion and Amortization |
1,822,854 |
1,398,137 |
||||||
|
Impairments |
531,413 |
502,865 |
||||||
|
Stock-Based Compensation Expenses |
95,057 |
81,700 |
||||||
|
Deferred Income Taxes |
499,279 |
53,067 |
||||||
|
Gains on Asset Dispositions, Net |
(442,981) |
(72,441) |
||||||
|
Other, Net |
2,270 |
(2,317) |
||||||
|
Dry Hole Costs |
47,231 |
45,095 |
||||||
|
Mark-to-Market Commodity Derivative Contracts |
||||||||
|
Total Gains |
(480,539) |
(105,816) |
||||||
|
Realized Gains |
83,765 |
25,180 |
||||||
|
Other, Net |
21,052 |
13,354 |
||||||
|
Changes in Components of Working Capital and Other Assets and Liabilities |
||||||||
|
Accounts Receivable |
(128,965) |
(124,813) |
||||||
|
Inventories |
(167,611) |
(134,181) |
||||||
|
Accounts Payable |
245,385 |
527,418 |
||||||
|
Accrued Taxes Payable |
101,239 |
(40,104) |
||||||
|
Other Assets |
(28,600) |
(16,051) |
||||||
|
Other Liabilities |
37,022 |
44,348 |
||||||
|
Changes in Components of Working Capital Associated with Investing and |
||||||||
|
Financing Activities |
133,227 |
(216,695) |
||||||
|
Net Cash Provided by Operating Activities |
3,341,523 |
2,085,727 |
||||||
|
Investing Cash Flows |
||||||||
|
Additions to Oil and Gas Properties |
(4,665,535) |
(3,740,883) |
||||||
|
Additions to Other Property, Plant and Equipment |
(502,112) |
(223,072) |
||||||
|
Proceeds from Sales of Assets |
1,294,627 |
126,371 |
||||||
|
Changes in Components of Working Capital Associated with Investing |
||||||||
|
Activities |
(133,512) |
216,546 |
||||||
|
Other, Net |
- |
(4,206) |
||||||
|
Net Cash Used in Investing Activities |
(4,006,532) |
(3,625,244) |
||||||
|
Financing Cash Flows |
||||||||
|
Common Stock Sold |
1,388,270 |
- |
||||||
|
Net Commercial Paper Borrowings |
- |
33,700 |
||||||
|
Long-term Debt Borrowings |
- |
991,395 |
||||||
|
Long-term Debt Repayments |
- |
(37,000) |
||||||
|
Dividends Paid |
(124,133) |
(114,277) |
||||||
|
Treasury Stock Purchased |
(21,357) |
(10,298) |
||||||
|
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan |
26,887 |
24,527 |
||||||
|
Debt Issuance Costs |
- |
(6,469) |
||||||
|
Other, Net |
285 |
149 |
||||||
|
Net Cash Provided by Financing Activities |
1,269,952 |
881,727 |
||||||
|
Effect of Exchange Rate Changes on Cash |
(7,068) |
(129) |
||||||
|
Increase (Decrease) in Cash and Cash Equivalents |
597,875 |
(657,919) |
||||||
|
Cash and Cash Equivalents at Beginning of Period |
788,853 |
685,751 |
||||||
|
Cash and Cash Equivalents at End of Period |
$ |
1,386,728 |
$ |
27,832 |
||||
|
EOG RESOURCES, INC. |
|||||||||||||
|
QUANTITATIVE RECONCILIATION OF ADJUSTED NET INCOME (NON-GAAP) |
|||||||||||||
|
TO NET INCOME (LOSS) (GAAP) |
|||||||||||||
|
(Unaudited; in thousands, except per share data) |
|||||||||||||
|
The following chart adjusts three-month and nine-month periods ended September 30, 2011 and 2010 reported Net Income (Loss) (GAAP) to reflect actual net cash realized from financial commodity price transactions by eliminating the unrealized mark-to-market gains from these transactions, to add back impairment charges related to certain of EOG's non-core North American assets in the first nine months of 2011 and third quarter of 2010, to eliminate the net gains on asset dispositions primarily in North America in the first nine months of 2011 and 2010, and to eliminate the change in the estimated fair value of a contingent consideration liability in 2010 related to EOG's previously disclosed acquisition of Haynesville and Bossier Shale unproved acreage. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match realizations to production settlement months and make certain other adjustments to exclude one-time items. EOG management uses this information for comparative purposes within the industry. |
|||||||||||||
|
Three Months Ended |
Nine Months Ended |
||||||||||||
|
September 30, |
September 30, |
||||||||||||
|
2011 |
2010 |
2011 |
2010 |
||||||||||
|
Reported Net Income (Loss) (GAAP) |
$ |
540,878 |
$ |
(70,906) |
$ |
970,425 |
$ |
106,981 |
|||||
|
Mark-to-Market (MTM) Commodity Derivative Contracts Impact |
|||||||||||||
|
Total Gains |
(357,664) |
(60,998) |
(480,539) |
(105,816) |
|||||||||
|
Realized Gains (Losses) |
52,480 |
(13,647) |
83,765 |
25,180 |
|||||||||
|
Subtotal |
(305,184) |
(74,645) |
(396,774) |
(80,636) |
|||||||||
|
After-Tax MTM Impact |
(195,394) |
(47,791) |
(254,035) |
(51,627) |
|||||||||
|
Add: Impairments of Certain Non-Core North American Assets, Net of Tax |
10,654 |
208,331 |
267,114 |
208,331 |
|||||||||
|
Less: Net Gains on Asset Dispositions, Net of Tax |
(132,895) |
(41,494) |
(284,005) |
(46,381) |
|||||||||
|
Less: Change in Fair Value of Contingent Consideration Liability, Net of Tax |
- |
(1,587) |
- |
(12,941) |
|||||||||
|
Adjusted Net Income (Non-GAAP) |
$ |
223,243 |
$ |
46,553 |
$ |
699,499 |
$ |
204,363 |
|||||
|
Net Income (Loss) Per Share (GAAP) |
|||||||||||||
|
Basic |
$ |
2.03 |
$ |
(0.28) |
$ |
3.71 |
$ |
0.43 |
|||||
|
Diluted |
$ |
2.01 |
$ |
(0.28) |
$ |
3.66 |
$ |
0.42 |
|||||
|
Adjusted Net Income Per Share (Non-GAAP) |
|||||||||||||
|
Basic |
$ |
0.84 |
$ |
0.19 |
$ |
2.67 |
$ |
0.82 |
|||||
|
Diluted |
$ |
0.83 |
$ |
0.18 |
$ |
2.64 |
$ |
0.80 |
|||||
|
Average Number of Shares (GAAP) |
|||||||||||||
|
Basic |
266,053 |
251,015 |
261,664 |
250,719 |
|||||||||
|
Diluted |
269,292 |
251,015 |
265,245 |
254,444 |
|||||||||
|
Average Number of Shares (Non-GAAP) |
|||||||||||||
|
Basic |
266,053 |
251,015 |
261,664 |
250,719 |
|||||||||
|
Diluted |
269,292 |
254,572 |
265,245 |
254,444 |
|||||||||
|
EOG RESOURCES, INC. |
||||||||||||||
|
QUANTITATIVE RECONCILIATION OF DISCRETIONARY CASH FLOW (NON-GAAP) |
||||||||||||||
|
TO NET CASH PROVIDED BY OPERATING ACTIVITIES (GAAP) |
||||||||||||||
|
(Unaudited; in thousands) |
||||||||||||||
|
The following chart reconciles the three-month and nine-month periods ended September 30, 2011 and 2010 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG management uses this information for comparative purposes within the industry. |
||||||||||||||
|
Three Months Ended |
Nine Months Ended |
|||||||||||||
|
September 30, |
September 30, |
|||||||||||||
|
2011 |
2010 |
2011 |
2010 |
|||||||||||
|
Net Cash Provided by Operating Activities (GAAP) |
$ |
1,272,283 |
$ |
784,387 |
$ |
3,341,523 |
$ |
2,085,727 |
||||||
|
Adjustments |
||||||||||||||
|
Exploration Costs (excluding Stock-Based Compensation Expenses) |
40,624 |
40,095 |
121,166 |
130,598 |
||||||||||
|
Changes in Components of Working Capital and Other Assets and Liabilities |
||||||||||||||
|
Accounts Receivable |
(36,335) |
85,538 |
128,965 |
124,813 |
||||||||||
|
Inventories |
40,549 |
66,818 |
167,611 |
134,181 |
||||||||||
|
Accounts Payable |
(56,135) |
(272,540) |
(245,385) |
(527,418) |
||||||||||
|
Accrued Taxes Payable |
(6,928) |
34,093 |
(101,239) |
40,104 |
||||||||||
|
Other Assets |
23,804 |
(8,448) |
28,600 |
16,051 |
||||||||||
|
Other Liabilities |
(49,039) |
(55,278) |
(37,022) |
(44,348) |
||||||||||
|
Changes in Components of Working Capital Associated |
||||||||||||||
|
with Investing and Financing Activities |
(56,587) |
80,722 |
(133,227) |
216,695 |
||||||||||
|
Discretionary Cash Flow (Non-GAAP) |
$ |
1,172,236 |
$ |
755,387 |
$ |
3,270,992 |
$ |
2,176,403 |
||||||
|
EOG RESOURCES, INC. |
||||
|
QUANTITATIVE RECONCILIATION OF NET DEBT (NON-GAAP) AND TOTAL |
||||
|
CAPITALIZATION (NON-GAAP) AS USED IN THE CALCULATION OF |
||||
|
THE NET DEBT-TO-TOTAL CAPITALIZATION RATIO (NON-GAAP) |
||||
|
TO CURRENT AND LONG-TERM DEBT (GAAP) AND TOTAL CAPITALIZATION (GAAP) |
||||
|
(Unaudited; in millions, except ratio data) |
||||
|
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. |
||||
|
September 30, |
||||
|
2011 |
||||
|
Total Stockholders' Equity - (a) |
$ |
12,494 |
||
|
Current and Long-Term Debt - (b) |
5,227 |
|||
|
Less: Cash |
(1,387) |
|||
|
Net Debt (Non-GAAP) - (c) |
3,840 |
|||
|
Total Capitalization (GAAP) - (a) + (b) |
$ |
17,721 |
||
|
Total Capitalization (Non-GAAP) - (a) + (c) |
$ |
16,334 |
||
|
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] |
29% |
|||
|
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] |
24% |
|||
|
EOG RESOURCES, INC. |
|||||||||||
|
FOURTH QUARTER AND FULL YEAR 2011 FORECAST AND BENCHMARK COMMODITY PRICING |
|||||||||||
|
(a) Fourth Quarter and Full Year 2011 Forecast The forecast items for the fourth quarter and full year 2011 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG’s related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. (b) Benchmark Commodity Pricing EOG bases United States, Canada and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. EOG bases United States and Canada natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month. |
|||||||||||
|
ESTIMATED RANGES |
|||||||||||
|
(Unaudited) |
|||||||||||
|
4Q 2011 |
Full Year 2011 |
||||||||||
|
Daily Production |
|||||||||||
|
Crude Oil and Condensate Volumes (MBbld) |
|||||||||||
|
United States |
119.0 |
- |
126.0 |
98.5 |
- |
104.8 |
|||||
|
Canada |
6.3 |
- |
9.5 |
7.2 |
- |
9.0 |
|||||
|
Trinidad |
2.2 |
- |
2.6 |
3.1 |
- |
3.6 |
|||||
|
Total |
127.5 |
- |
138.1 |
108.8 |
- |
117.4 |
|||||
|
Natural Gas Liquids Volumes (MBbld) |
|||||||||||
|
United States |
41.4 |
- |
47.2 |
37.0 |
- |
43.5 |
|||||
|
Canada |
0.6 |
- |
0.8 |
0.7 |
- |
1.0 |
|||||
|
Total |
42.0 |
- |
48.0 |
37.7 |
- |
44.5 |
|||||
|
Natural Gas Volumes (MMcfd) |
|||||||||||
|
United States |
1,070 |
- |
1,116 |
1,105 |
- |
1,127 |
|||||
|
Canada |
106 |
- |
116 |
126 |
- |
132 |
|||||
|
Trinidad |
310 |
- |
346 |
338 |
- |
357 |
|||||
|
Other International |
8 |
- |
14 |
12 |
- |
14 |
|||||
|
Total |
1,494 |
- |
1,592 |
1,581 |
- |
1,630 |
|||||
|
Crude Oil Equivalent Volumes (MBoed) |
|||||||||||
|
United States |
338.7 |
- |
359.2 |
319.7 |
- |
336.1 |
|||||
|
Canada |
24.6 |
- |
29.6 |
28.9 |
- |
32.0 |
|||||
|
Trinidad |
53.9 |
- |
60.3 |
59.4 |
- |
63.1 |
|||||
|
Other International |
1.3 |
- |
2.3 |
2.0 |
- |
2.3 |
|||||
|
Total |
418.5 |
- |
451.4 |
410.0 |
- |
433.6 |
|||||
|
Operating Costs |
|||||||||||
|
Unit Costs ($/Boe) |
|||||||||||
|
Lease and Well |
$ 6.60 |
- |
$ 6.96 |
$ 6.14 |
- |
$ 6.24 |
|||||
|
Transportation Costs |
$ 2.82 |
- |
$ 3.06 |
$ 2.74 |
- |
$ 2.77 |
|||||
|
Depreciation, Depletion and Amortization |
$ 16.92 |
- |
$ 17.52 |
$ 16.20 |
- |
$ 16.50 |
|||||
|
Expenses ($MM) |
|||||||||||
|
Exploration, Dry Hole and Impairment |
$ 187.0 |
- |
$ 217.0 |
$ 535.0 |
- |
$ 575.0 |
|||||
|
General and Administrative |
$ 85.0 |
- |
$ 90.0 |
$ 304.5 |
- |
$ 309.5 |
|||||
|
Gathering and Processing |
$ 20.0 |
- |
$ 25.0 |
$ 75.5 |
- |
$ 80.5 |
|||||
|
Capitalized Interest |
$ 12.5 |
- |
$ 16.5 |
$ 56.8 |
- |
$ 60.8 |
|||||
|
Net Interest |
$ 45.0 |
- |
$ 55.0 |
$ 199.0 |
- |
$ 209.0 |
|||||
|
Taxes Other Than Income (% of Revenue) |
5.5% |
- |
6.5% |
6.1% |
- |
6.3% |
|||||
|
Income Taxes |
|||||||||||
|
Effective Rate |
40% |
- |
50% |
40% |
- |
45% |
|||||
|
Current Taxes ($MM) |
$ 60 |
- |
$ 75 |
$ 260 |
- |
$ 280 |
|||||
|
Capital Expenditures ($MM) - FY 2011 (Excluding Acquisitions) |
|||||||||||
|
Exploration and Development, Excluding Facilities |
$ 5,750 |
- |
$ 5,850 |
||||||||
|
Exploration and Development Facilities |
$ 450 |
- |
$ 500 |
||||||||
|
Gathering, Processing and Other |
$ 600 |
- |
$ 650 |
||||||||
|
Pricing - (Refer to Benchmark Commodity Pricing in text) |
|||||||||||
|
Crude Oil and Condensate ($/Bbl) |
|||||||||||
|
Differentials |
|||||||||||
|
United States - below WTI |
$ 2.75 |
- |
$ 3.50 |
$ 4.00 |
- |
$ 5.00 |
|||||
|
Canada - below WTI |
$ 5.00 |
- |
$ 5.50 |
$ 3.25 |
- |
$ 3.75 |
|||||
|
Trinidad - below WTI |
$ 2.50 |
- |
$ 3.00 |
$ 2.50 |
- |
$ 3.20 |
|||||
|
Natural Gas ($/Mcf) |
|||||||||||
|
Differentials |
|||||||||||
|
United States - below NYMEX Henry Hub |
$ 0.08 |
- |
$ 0.16 |
$ 0.07 |
- |
$ 0.11 |
|||||
|
Canada - below NYMEX Henry Hub |
$ 0.48 |
- |
$ 0.58 |
$ 0.35 |
- |
$ 0.43 |
|||||
|
Realizations |
|||||||||||
|
Trinidad |
$ 2.50 |
- |
$ 3.25 |
$ 3.20 |
- |
$ 3.39 |
|||||
|
Other International |
$ 5.55 |
- |
$ 6.55 |
$ 5.58 |
- |
$ 5.78 |
|||||
|
Definitions |
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|
$/Bbl |
U.S. Dollars per barrel |
|||
|
$/Boe |
U.S. Dollars per barrel of oil equivalent |
|||
|
$/Mcf |
U.S. Dollars per thousand cubic feet |
|||
|
$MM |
U.S. Dollars in millions |
|||
|
MBbld |
Thousand barrels per day |
|||
|
MBoed |
Thousand barrels of oil equivalent per day |
|||
|
MMcfd |
Million cubic feet per day |
|||
|
NYMEX |
New York Mercantile Exchange |
|||
|
WTI |
West Texas Intermediate |
|||
SOURCE EOG Resources, Inc.