News Detail
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INVESTORS
EOG Resources Reports Third Quarter 2013 Results; Again Increases 2013 Production Growth Targets for Crude Oil and Total Company
HOUSTON, Nov. 6, 2013 /PRNewswire/ --
- Delivers 39 Percent Year-Over-Year Total Company Crude Oil Production Growth
- Raises 2013 Full-Year Crude Oil Production Goal to 39 Percent from 35 Percent
- Increases 2013 Total Company Production Growth Target to 9 Percent from 7.5 Percent
- Reports Record Western Eagle Ford Oil Well
- Continues to Achieve Stellar Economic Results from the Eagle Ford, Bakken/Three Forks and Leonard Plays
- Announces Mark G. Papa Will Continue as Director Following Year-end Retirement
EOG Resources, Inc. (NYSE: EOG) (EOG) today reported third quarter 2013 net income of $462.5 million, or $1.69 per share. This compares to third quarter 2012 net income of $355.5 million, or $1.31 per share.
Consistent with some analysts' practice of matching realizations to settlement months and making certain other adjustments in order to exclude one-time items, adjusted non-GAAP net income for the third quarter 2013 was $634.3 million, or $2.32 per share. Adjusted non-GAAP net income for the third quarter 2012 was $468.7 million, or $1.73 per share. The results for the third quarter 2013 included net gains on asset dispositions of $5.2 million, net of tax ($0.02 per share), impairments of $2.4 million, net of tax ($0.01 per share) related to the sale of certain non-core North American assets and a previously disclosed non-cash net loss of $293.4 million ($187.8 million after tax, or $0.69 per share) on the mark-to-market of financial commodity contracts. During the third quarter, the net cash outflow related to financial commodity contracts was $20.6 million ($13.2 million after tax, or $0.05 per share). (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)
EOG reported strong, sustained financial growth for the first nine months of 2013. Earnings per share increased 49 percent, discretionary cash flow increased 29 percent and adjusted EBITDAX rose 27 percent, compared to the same 2012 period. (Please refer to the attached tables for the reconciliation of non-GAAP discretionary cash flow to net cash provided by operating activities (GAAP) and adjusted EBITDAX (non-GAAP) to income before interest expense and income taxes (GAAP).)
Operational Highlights
EOG increased its U.S. crude oil and condensate production by 41 percent and total company crude oil and condensate production by 39 percent in the third quarter of 2013 over the same prior year period. Total company liquids production – crude oil, condensate and natural gas liquids (NGLs) – rose 33 percent.
EOG is increasing its full year crude oil and condensate production growth target for the second time in 2013 to 39 percent from 35 percent, following three quarters of extraordinary results. Total natural gas liquids production is expected to increase 17 percent, compared to the previous 14 percent target, and total natural gas production is projected to decline 11 percent, consistent with EOG's longstanding strategy in North America. Overall, EOG is targeting 9 percent total company production growth in 2013, versus its previous goal of 7.5 percent. In addition, EOG is again lowering certain unit cost estimates, based on results to date.
"EOG is consistently making the best oil wells in the best two oil plays in North America, the Eagle Ford and Bakken/Three Forks," said President and Chief Executive Officer William R. "Bill" Thomas.
South Texas Eagle Ford
In the first three quarters of 2013, EOG built momentum in its western Eagle Ford acreage by increasing drilling activity from six to nine rigs. Through completion advancements, initial production rates have increased more than 20 percent since the first quarter 2013. This enhanced productivity across Atascosa, La Salle and McMullen Counties mirrors the performance level EOG already has reached in its eastern play activities.
During the third quarter, EOG reported its top well to date from its western Eagle Ford acreage. The Kaiser Junior Unit #1H began initial production at 2,815 barrels of oil per day (Bopd) with 160 barrels per day (Bpd) of NGLs and 940 thousand cubic feet per day (Mcfd) of natural gas in Atascosa County. Other third quarter western wells include the Janet Unit #1H and Nelson Zella Unit #1H and #2H in La Salle County, which were completed with initial rates of 2,430, 1,960 and 2,810 Bopd with 175, 120 and 100 Bpd of NGLs and 1,000, 700 and 590 Mcfd of natural gas, respectively. In McMullen County, the River Lowe Ranch #4H, #5H, #6H, #7H, #8H and #9H began sales at initial rates ranging from 1,970 to 2,115 Bopd with 125 to 135 Bpd of NGLs and 720 to 780 Mcfd of natural gas. EOG has 100 percent working interest in these 10 wells.
Highlights from EOG's eastern Eagle Ford acreage include four DeWitt County wells. The Justiss Unit #1H, #2H and #3H were completed at 3,885, 3,560 and 3,940 Bopd with 520, 605 and 670 Bpd of NGLs and 3.0, 3.5 and 3.9 million cubic feet per day (MMcfd) of natural gas, respectively. Also in DeWitt County, the Vinklarek Unit #1H was completed at 4,510 Bopd with 715 Bpd of NGLs and 4.2 MMcfd of natural gas. In Gonzales County, the Baker-Deforest Unit #5H, #6H and #7H came on-line at 3,200, 3,560 and 4,115 Bopd with 420, 490 and 535 Bpd of NGLs and 2.5, 2.9 and 3.1 MMcfd of natural gas, respectively. EOG has 100 percent working interest in these seven Eagle Ford wells.
"Because we now are achieving high growth, high rate-of-return results from our western acreage, we have effectively raised the bar for all of EOG's Eagle Ford acreage," Thomas said.
With a 25-rig drilling program, EOG is increasing the total net wells planned across its Eagle Ford acreage in 2013 from 440 to 460.
North Dakota Bakken/Three Forks
EOG's exceptional Eagle Ford results were replicated in the North Dakota Bakken/Three Forks through improvements in initial production rates and efficient execution of its drilling program.
In the Bakken Core, EOG brought a number of Mountrail County wells to sales. The Fertile 50-0509H, in which EOG has 100 percent working interest, began producing crude oil at 2,315 Bopd with 1.0 MMcfd of rich natural gas. The Van Hook 126-2523H and 130-2526H came on-line at peak rates of 2,235 and 1,910 Bopd with 1.1 and 0.9 MMcfd of rich natural gas, respectively. EOG has 67 and 91 percent working interest in these wells, respectively. The Wayzetta 155-2636H, 137-2226H and 150-1509H had initial crude oil rates ranging from 2,060 to 2,500 Bpd with 1.0 to 1.2 MMcfd of rich natural gas. EOG has 72 percent, 65 percent and 63 percent working interest in these wells, respectively.
On its Antelope Extension acreage in McKenzie County, EOG highlighted three wells from the first bench of the Three Forks formation. The Bear Den 100-2017H and 101-2019H began producing at rates of 2,100 and 1,235 Bopd with 2.0 and 1.2 MMcfd of rich natural gas, respectively. The third well, the Bear Den 23-2019H had an initial production rate of 1,665 Bopd with 1.6 MMcfd of rich natural gas. EOG has 91 percent working interest in these three wells.
EOG remains focused on the highly economic Bakken Core and Antelope Extension areas. Based on continuous gains in results from both the Bakken and Three Forks formations, plans are to increase the level of drilling activity in 2014.
"Every quarter, EOG's technical understanding of the Eagle Ford and Bakken/Three Forks expands, as we further modify completion techniques that boost overall well productivity and economics," Thomas said.
Delaware Basin Leonard
During the third quarter, EOG completed three wells in the Delaware Basin Leonard play in Lea County, New Mexico. The Endurance 36 State Com #3H and #4H and Brown Bear 36 State #1H began production at 735, 875 and 720 Bopd, respectively. The wells, in which EOG has 100 percent working interest, also produced 85, 105 and 120 Bpd of NGLs with 460, 570 and 665 Mcfd of natural gas, respectively. Plans are to increase drilling activity in the Leonard in 2014.
"With premier positions in the Eagle Ford and Bakken/Three Forks, EOG continues to set new crude oil production records. Through our tenacious attention to the completion process, we are enhancing the productivity and profitability of these world class assets to ultimately realize a greater volume of the potential oil in the ground," said Mark G. Papa, Executive Chairman of the Board. "We also are pleased with the strides EOG is making in the Delaware Basin Leonard."
Hedging Activity
In recent weeks, EOG increased the amount of crude oil hedges in place for the remainder of 2013 and 2014. For the period November 1 through December 31, 2013, EOG has crude oil financial price swap contracts in place for 126,000 Bopd at a weighted average price of $98.80 per barrel, excluding unexercised options.
For the period January 1 through June 30, 2014, EOG has crude oil financial price swap contracts in place for approximately 123,000 Bopd at a weighted average price of $96.44 per barrel, excluding unexercised options. For the period July 1 through December 31, 2014, EOG has crude oil financial price swap contracts in place for 9,000 Bopd at an average price of $95.30 per barrel, excluding unexercised options.
EOG also has hedges in place for natural gas volumes. For December 2013, EOG has natural gas financial price swap contracts in place for 150,000 million British thermal units per day (MMBtud) at a weighted average price of $4.79 per million British thermal units (MMBtu), excluding unexercised options. For the full year 2014, EOG has natural gas financial price swap contracts in place for 170,000 MMBtud at a weighted average price of $4.54 per MMBtu, excluding unexercised options. (For a comprehensive summary of crude oil and natural gas derivative contracts, please refer to the attached tables.)
Capital Structure
For the first nine months of 2013, EOG's cash flows from operating activities and proceeds from asset sales exceeded total capital expenditures.
To date, EOG has closed on approximately $620 million of asset sales, exceeding its stated goal for the year. Proceeds from asset sales for the full year 2013 are expected to be approximately $750 million. At September 30, 2013, EOG's total debt outstanding was $6,313 million for a debt-to-total capitalization ratio of 30 percent. Taking into account cash on the balance sheet of $1,319 million at the end of the third quarter, EOG's net debt was $4,994 million for a net debt-to-total capitalization ratio of 25 percent. (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).)
Board of Directors
As previously announced, in addition to his current role as Chief Executive Officer, Thomas will succeed Papa as Chairman of the Board on January 1, 2014. Papa will retire both as Executive Chairman of the Board and as an employee at year-end, although he will continue to serve as an EOG director.
Conference Call November 7, 2013
EOG's third quarter 2013 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Thursday, November 7, 2013. To listen, log on to www.eogresources.com. The webcast will be archived on EOG's website through November 21, 2013.
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, statements regarding future commodity prices 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," "should" 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, generate income or cash flows or pay dividends 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, unknown or currently unforeseen 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 and condensate, natural gas liquids, 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, advanced completion technologies and hydraulic fracturing;
- 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 and capital expenditure requirements 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, and EOG's ability to retain mineral licenses and leases;
- 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, hydraulic fracturing and access to and use of water, laws and regulations imposing conditions and restrictions on drilling and completion operations and laws and regulations with respect to derivatives and hedging activities;
- 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, and to otherwise satisfy its capital expenditure requirements;
- 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 conditions and developments around the world (such as political instability and armed conflict), including in the areas in which EOG operates;
- the use of competing energy sources and the development of alternative energy sources;
- the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;
- acts of war and terrorism and responses to these acts;
- physical, electronic and cyber security breaches; and
- the other factors described under Item 1A, "Risk Factors", on pages 16 through 23 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2012 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.
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 "potential" reserves and/or other 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, 2012, 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. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
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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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Kimberly A. Matthews |
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(713) 571-4676 |
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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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Three Months Ended |
Nine Months Ended |
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September 30, |
September 30, |
||||||||||||
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2013 |
2012 |
2013 |
2012 |
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Net Operating Revenues |
$ |
3,541.4 |
$ |
2,954.9 |
$ |
10,738.1 |
$ |
8,670.8 |
|||||
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Net Income |
$ |
462.5 |
$ |
355.5 |
$ |
1,616.9 |
$ |
1,075.3 |
|||||
|
Net Income Per Share |
|||||||||||||
|
Basic |
$ |
1.71 |
$ |
1.33 |
$ |
5.99 |
$ |
4.03 |
|||||
|
Diluted |
$ |
1.69 |
$ |
1.31 |
$ |
5.93 |
$ |
3.98 |
|||||
|
Average Number of Common Shares |
|||||||||||||
|
Basic |
270.5 |
267.9 |
269.9 |
267.1 |
|||||||||
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Diluted |
273.6 |
271.0 |
272.9 |
270.3 |
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SUMMARY INCOME STATEMENTS |
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Three Months Ended |
Nine Months Ended |
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September 30, |
September 30, |
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|
2013 |
2012 |
2013 |
2012 |
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Net Operating Revenues |
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Crude Oil and Condensate |
$ |
2,337,742 |
$ |
1,512,168 |
$ |
6,132,574 |
$ |
4,198,753 |
|||||
|
Natural Gas Liquids |
208,190 |
170,351 |
556,176 |
518,684 |
|||||||||
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Natural Gas |
396,123 |
426,728 |
1,269,604 |
1,153,433 |
|||||||||
|
(Losses) Gains on Mark-to-Market Commodity Derivative Contracts |
(293,387) |
4,671 |
(206,853) |
327,328 |
|||||||||
|
Gathering, Processing and Marketing |
872,699 |
764,385 |
2,755,069 |
2,193,290 |
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Gains on Asset Dispositions, Net |
8,183 |
67,376 |
185,569 |
248,134 |
|||||||||
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Other, Net |
11,846 |
9,176 |
45,956 |
31,203 |
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Total |
3,541,396 |
2,954,855 |
10,738,095 |
8,670,825 |
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Operating Expenses |
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Lease and Well |
299,169 |
253,452 |
817,057 |
765,703 |
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Transportation Costs |
219,790 |
164,407 |
628,538 |
431,642 |
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Gathering and Processing Costs |
31,121 |
26,223 |
81,522 |
72,403 |
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Exploration Costs |
39,429 |
45,953 |
130,968 |
136,909 |
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Dry Hole Costs |
19,548 |
1,924 |
59,260 |
13,005 |
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Impairments |
85,917 |
62,875 |
177,432 |
250,239 |
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Marketing Costs |
876,761 |
755,457 |
2,746,900 |
2,155,043 |
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Depreciation, Depletion and Amortization |
928,800 |
825,851 |
2,685,719 |
2,383,359 |
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General and Administrative |
98,654 |
92,870 |
257,246 |
244,866 |
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Taxes Other Than Income |
172,438 |
120,096 |
458,566 |
359,798 |
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Total |
2,771,627 |
2,349,108 |
8,043,208 |
6,812,967 |
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Operating Income |
769,769 |
605,747 |
2,694,887 |
1,857,858 |
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Other Income, Net |
11,168 |
7,596 |
5,867 |
22,902 |
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Income Before Interest Expense and Income Taxes |
780,937 |
613,343 |
2,700,754 |
1,880,760 |
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Interest Expense, Net |
59,382 |
53,154 |
182,950 |
154,198 |
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Income Before Income Taxes |
721,555 |
560,189 |
2,517,804 |
1,726,562 |
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Income Tax Provision |
259,057 |
204,698 |
900,889 |
651,284 |
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Net Income |
$ |
462,498 |
$ |
355,491 |
$ |
1,616,915 |
$ |
1,075,278 |
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Dividends Declared per Common Share |
$ |
0.1875 |
$ |
0.17 |
$ |
0.5625 |
$ |
0.51 |
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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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2013 |
2012 |
2013 |
2012 |
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Wellhead Volumes and Prices |
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Crude Oil and Condensate Volumes (MBbld) (A) |
|||||||||||||
|
United States |
227.6 |
161.3 |
204.3 |
147.6 |
|||||||||
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Canada |
6.1 |
6.7 |
6.7 |
6.9 |
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Trinidad |
1.2 |
1.2 |
1.3 |
1.7 |
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Other International (B) |
0.1 |
0.1 |
0.1 |
0.1 |
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Total |
235.0 |
169.3 |
212.4 |
156.3 |
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Average Crude Oil and Condensate Prices ($/Bbl) (C) |
|||||||||||||
|
United States |
$ |
108.56 |
$ |
97.64 |
$ |
106.36 |
$ |
98.26 |
|||||
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Canada |
97.90 |
86.09 |
90.53 |
86.25 |
|||||||||
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Trinidad |
94.96 |
90.84 |
91.80 |
93.85 |
|||||||||
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Other International (B) |
81.30 |
83.59 |
88.90 |
90.34 |
|||||||||
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Composite |
108.20 |
97.13 |
105.76 |
97.68 |
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Natural Gas Liquids Volumes (MBbld) (A) |
|||||||||||||
|
United States |
68.2 |
58.1 |
63.5 |
54.3 |
|||||||||
|
Canada |
0.9 |
0.9 |
0.9 |
0.9 |
|||||||||
|
Total |
69.1 |
59.0 |
64.4 |
55.2 |
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Average Natural Gas Liquids Prices ($/Bbl) (C) |
|||||||||||||
|
United States |
$ |
32.75 |
$ |
30.95 |
$ |
31.55 |
$ |
35.43 |
|||||
|
Canada |
32.24 |
41.09 |
37.83 |
44.61 |
|||||||||
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Composite |
32.74 |
31.11 |
31.64 |
35.58 |
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Natural Gas Volumes (MMcfd) (A) |
|||||||||||||
|
United States |
899 |
1,022 |
920 |
1,051 |
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Canada |
76 |
94 |
78 |
98 |
|||||||||
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Trinidad |
352 |
387 |
350 |
393 |
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Other International (B) |
7 |
9 |
8 |
10 |
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Total |
1,334 |
1,512 |
1,356 |
1,552 |
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Average Natural Gas Prices ($/Mcf) (C) |
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|
United States |
$ |
3.19 |
$ |
2.61 |
$ |
3.33 |
$ |
2.39 |
|||||
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Canada |
2.61 |
2.39 |
3.01 |
2.35 |
|||||||||
|
Trinidad |
3.41 |
4.38 |
3.71 |
3.60 |
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Other International (B) |
6.12 |
5.67 |
6.58 |
5.70 |
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Composite |
3.23 |
3.07 |
3.43 |
2.71 |
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Crude Oil Equivalent Volumes (MBoed) (D) |
|||||||||||||
|
United States |
445.7 |
389.7 |
421.2 |
377.2 |
|||||||||
|
Canada |
19.7 |
23.2 |
20.7 |
24.1 |
|||||||||
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Trinidad |
59.8 |
65.7 |
59.5 |
67.1 |
|||||||||
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Other International (B) |
1.2 |
1.7 |
1.4 |
1.8 |
|||||||||
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Total |
526.4 |
480.3 |
502.8 |
470.2 |
|||||||||
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Total MMBoe (D) |
48.4 |
44.2 |
137.3 |
128.8 |
|||||||||
|
(A) |
Thousand barrels per day or million cubic feet per day, as applicable. |
||||||||||||
|
(B) |
Other International includes EOG's United Kingdom, China and Argentina operations. |
||||||||||||
|
(C) |
Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments. |
||||||||||||
|
(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. |
||||||||||||
|
EOG RESOURCES, INC. |
||||||||
|
SUMMARY BALANCE SHEETS |
||||||||
|
(Unaudited; in thousands, except share data) |
||||||||
|
September 30, |
December 31, |
|||||||
|
2013 |
2012 |
|||||||
|
ASSETS |
||||||||
|
Current Assets |
||||||||
|
Cash and Cash Equivalents |
$ |
1,318,817 |
$ |
876,435 |
||||
|
Accounts Receivable, Net |
1,849,517 |
1,656,618 |
||||||
|
Inventories |
566,004 |
683,187 |
||||||
|
Assets from Price Risk Management Activities |
44,484 |
166,135 |
||||||
|
Income Taxes Receivable |
42,296 |
29,163 |
||||||
|
Deferred Income Taxes |
127,658 |
- |
||||||
|
Other |
243,191 |
178,346 |
||||||
|
Total |
4,191,967 |
3,589,884 |
||||||
|
Property, Plant and Equipment |
||||||||
|
Oil and Gas Properties (Successful Efforts Method) |
41,887,901 |
38,126,298 |
||||||
|
Other Property, Plant and Equipment |
2,954,085 |
2,740,619 |
||||||
|
Total Property, Plant and Equipment |
44,841,986 |
40,866,917 |
||||||
|
Less: Accumulated Depreciation, Depletion and Amortization |
(19,242,795) |
(17,529,236) |
||||||
|
Total Property, Plant and Equipment, Net |
25,599,191 |
23,337,681 |
||||||
|
Other Assets |
356,112 |
409,013 |
||||||
|
Total Assets |
$ |
30,147,270 |
$ |
27,336,578 |
||||
|
LIABILITIES AND STOCKHOLDERS' EQUITY |
||||||||
|
Current Liabilities |
||||||||
|
Accounts Payable |
$ |
2,247,714 |
$ |
2,078,948 |
||||
|
Accrued Taxes Payable |
200,477 |
162,083 |
||||||
|
Dividends Payable |
50,753 |
45,802 |
||||||
|
Liabilities from Price Risk Management Activities |
174,648 |
7,617 |
||||||
|
Deferred Income Taxes |
- |
22,838 |
||||||
|
Current Portion of Long-Term Debt |
406,579 |
406,579 |
||||||
|
Other |
267,162 |
200,191 |
||||||
|
Total |
3,347,333 |
2,924,058 |
||||||
|
Long-Term Debt |
5,906,494 |
5,905,602 |
||||||
|
Other Liabilities |
846,780 |
894,758 |
||||||
|
Deferred Income Taxes |
5,185,083 |
4,327,396 |
||||||
|
Commitments and Contingencies |
||||||||
|
Stockholders' Equity |
||||||||
|
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 273,061,895 S hares Issued at September 30, 2013 and 271,958,495 Shares Issued at December 31, 2012 |
||||||||
|
202,731 |
202,720 |
|||||||
|
Additional Paid in Capital |
2,614,898 |
2,500,340 |
||||||
|
Accumulated Other Comprehensive Income |
425,283 |
439,895 |
||||||
|
Retained Earnings |
11,639,302 |
10,175,631 |
||||||
|
Common Stock Held in Treasury, 142,467 Shares at September 30, 2013 and 326,264 Shares at December 31, 2012 |
(20,634) |
(33,822) |
||||||
|
Total Stockholders' Equity |
14,861,580 |
13,284,764 |
||||||
|
Total Liabilities and Stockholders' Equity |
$ |
30,147,270 |
$ |
27,336,578 |
||||
|
EOG RESOURCES, INC. |
|||||||
|
SUMMARY STATEMENTS OF CASH FLOWS |
|||||||
|
(Unaudited; in thousands) |
|||||||
|
Nine Months Ended |
|||||||
|
September 30, |
|||||||
|
2013 |
2012 |
||||||
|
Cash Flows from Operating Activities |
|||||||
|
Reconciliation of Net Income to Net Cash Provided by Operating Activities: |
|||||||
|
Net Income |
$ |
1,616,915 |
$ |
1,075,278 |
|||
|
Items Not Requiring (Providing) Cash |
|||||||
|
Depreciation, Depletion and Amortization |
2,685,719 |
2,383,359 |
|||||
|
Impairments |
177,432 |
250,239 |
|||||
|
Stock-Based Compensation Expenses |
103,171 |
101,337 |
|||||
|
Deferred Income Taxes |
657,686 |
385,878 |
|||||
|
Gains on Asset Dispositions, Net |
(185,569) |
(248,134) |
|||||
|
Other, Net |
460 |
(10,266) |
|||||
|
Dry Hole Costs |
59,260 |
13,005 |
|||||
|
Mark-to-Market Commodity Derivative Contracts |
|||||||
|
Total Losses (Gains) |
206,853 |
(327,328) |
|||||
|
Realized Gains |
115,323 |
555,946 |
|||||
|
Excess Tax Benefits from Stock-Based Compensation |
(50,230) |
(49,426) |
|||||
|
Other, Net |
16,222 |
12,675 |
|||||
|
Changes in Components of Working Capital and Other Assets and Liabilities |
|||||||
|
Accounts Receivable |
(213,746) |
(112,174) |
|||||
|
Inventories |
61,147 |
(154,766) |
|||||
|
Accounts Payable |
145,199 |
83,682 |
|||||
|
Accrued Taxes Payable |
73,197 |
42,791 |
|||||
|
Other Assets |
(78,799) |
(120,085) |
|||||
|
Other Liabilities |
10,889 |
39,871 |
|||||
|
Changes in Components of Working Capital Associated with Investing and Financing Activities |
(72,945) |
87,708 |
|||||
|
Net Cash Provided by Operating Activities |
5,328,184 |
4,009,590 |
|||||
|
Investing Cash Flows |
|||||||
|
Additions to Oil and Gas Properties |
(5,084,335) |
(5,326,884) |
|||||
|
Additions to Other Property, Plant and Equipment |
(271,136) |
(477,351) |
|||||
|
Proceeds from Sales of Assets |
587,273 |
1,213,550 |
|||||
|
Changes in Restricted Cash |
(68,061) |
- |
|||||
|
Changes in Components of Working Capital Associated with Investing Activities |
72,916 |
(87,654) |
|||||
|
Net Cash Used in Investing Activities |
(4,763,343) |
(4,678,339) |
|||||
|
Financing Cash Flows |
|||||||
|
Long-Term Debt Borrowings |
- |
1,234,138 |
|||||
|
Dividends Paid |
(147,731) |
(134,412) |
|||||
|
Excess Tax Benefits from Stock-Based Compensation |
50,230 |
49,426 |
|||||
|
Treasury Stock Purchased |
(55,562) |
(44,799) |
|||||
|
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan |
30,080 |
59,714 |
|||||
|
Debt Issuance Costs |
- |
(1,771) |
|||||
|
Repayment of Capital Lease Obligation |
(4,318) |
(1,407) |
|||||
|
Other, Net |
29 |
(54) |
|||||
|
Net Cash (Used in) Provided by Financing Activities |
(127,272) |
1,160,835 |
|||||
|
Effect of Exchange Rate Changes on Cash |
4,813 |
4,811 |
|||||
|
Increase in Cash and Cash Equivalents |
442,382 |
496,897 |
|||||
|
Cash and Cash Equivalents at Beginning of Period |
876,435 |
615,726 |
|||||
|
Cash and Cash Equivalents at End of Period |
$ |
1,318,817 |
$ |
1,112,623 |
|||
|
EOG RESOURCES, INC. |
||||||||||||||
|
QUANTITATIVE RECONCILIATION OF ADJUSTED NET INCOME (NON-GAAP) |
||||||||||||||
|
TO NET INCOME (GAAP) |
||||||||||||||
|
(Unaudited; in thousands, except per share data) |
||||||||||||||
|
The following chart adjusts the three-month and nine-month periods ended September 30, 2013 and 2012 reported Net Income (GAAP) to reflect actual net cash realized from financial commodity price transactions by eliminating the unrealized mark-to-market losses (gains) from these transactions, to eliminate the net gains on asset dispositions in North America in 2013 and 2012 and to add back impairment charges related to certain of EOG's non-core North American assets in 2013 and 2012. 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 non-recurring items. EOG management uses this information for comparative purposes within the industry. |
||||||||||||||
|
Three Months Ended |
Nine Months Ended |
|||||||||||||
|
September 30, |
September 30, |
|||||||||||||
|
2013 |
2012 |
2013 |
2012 |
|||||||||||
|
Reported Net Income (GAAP) |
$ |
462,498 |
$ |
355,491 |
$ |
1,616,915 |
$ |
1,075,278 |
||||||
|
Mark-to-Market (MTM) |
||||||||||||||
|
Total Losses (Gains) |
293,387 |
(4,671) |
206,853 |
(327,328) |
||||||||||
|
Realized (Losses) Gains |
(20,636) |
249,166 |
115,323 |
555,946 |
||||||||||
|
Subtotal |
272,751 |
244,495 |
322,176 |
228,618 |
||||||||||
|
After-Tax MTM Impact |
174,628 |
156,537 |
206,273 |
146,372 |
||||||||||
|
Less: Net Gains on Asset Dispositions, Net of Tax |
(5,241) |
(43,354) |
(129,616) |
(161,652) |
||||||||||
|
Add: Impairments of Certain North American Assets, Net of Tax |
2,422 |
- |
4,425 |
38,575 |
||||||||||
|
Adjusted Net Income (Non-GAAP) |
$ |
634,307 |
$ |
468,674 |
$ |
1,697,997 |
$ |
1,098,573 |
||||||
|
Net Income Per Share |
||||||||||||||
|
Basic |
$ |
1.71 |
$ |
1.33 |
$ |
5.99 |
$ |
4.03 |
||||||
|
Diluted |
$ |
1.69 |
$ |
1.31 |
$ |
5.93 |
(a) |
$ |
3.98 |
(b) |
||||
|
Percentage Increase - [(a) - (b)] / (b) |
49% |
|||||||||||||
|
Adjusted Net Income Per |
||||||||||||||
|
Basic |
$ |
2.35 |
$ |
1.75 |
$ |
6.29 |
$ |
4.11 |
||||||
|
Diluted |
$ |
2.32 |
$ |
1.73 |
$ |
6.22 |
$ |
4.06 |
||||||
|
Average Number of |
||||||||||||||
|
Basic |
270,471 |
267,941 |
269,934 |
267,136 |
||||||||||
|
Diluted |
273,576 |
270,982 |
272,856 |
270,328 |
||||||||||
|
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, 2013 and 2012 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), Excess Tax Benefits from Stock-Based Compensation, 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, |
||||||||||||||
|
2013 |
2012 |
2013 |
2012 |
||||||||||||
|
Net Cash Provided by Operating Activities (GAAP) |
$ |
2,012,472 |
$ |
1,436,372 |
$ |
5,328,184 |
$ |
4,009,590 |
|||||||
|
Adjustments |
|||||||||||||||
|
Exploration Costs (excluding Stock-Based Compensation Expenses) |
32,755 |
38,485 |
110,330 |
116,563 |
|||||||||||
|
Excess Tax Benefits from Stock-Based Compensation |
28,361 |
27,311 |
50,230 |
49,426 |
|||||||||||
|
Changes in Components of Working Capital and Other Assets and Liabilities |
|||||||||||||||
|
Accounts Receivable |
48,937 |
227,593 |
213,746 |
112,174 |
|||||||||||
|
Inventories |
(39,062) |
51,190 |
(61,147) |
154,766 |
|||||||||||
|
Accounts Payable |
(3,830) |
92,673 |
(145,199) |
(83,682) |
|||||||||||
|
Accrued Taxes Payable |
(48,381) |
(28,428) |
(73,197) |
(42,791) |
|||||||||||
|
Other Assets |
(13,506) |
17,782 |
78,799 |
120,085 |
|||||||||||
|
Other Liabilities |
(62,289) |
(67,226) |
(10,889) |
(39,871) |
|||||||||||
|
Changes in Components of Working Capital Associated with Investing and |
|||||||||||||||
|
Financing Activities |
53,306 |
(185,161) |
72,945 |
(87,708) |
|||||||||||
|
Discretionary Cash Flow (Non-GAAP) |
$ |
2,008,763 |
$ |
1,610,591 |
$ |
5,563,802 |
(a) |
$ |
4,308,552 |
(b) |
|||||
|
Percentage Increase - [(a) - (b)] / (b) |
29% |
||||||||||||||
|
EOG RESOURCES, INC. |
|||||||||
|
CRUDE OIL AND NATURAL GAS FINANCIAL |
|||||||||
|
COMMODITY DERIVATIVE CONTRACTS |
|||||||||
|
EOG has entered into additional crude oil derivative contracts since filing its Current Report on Form 8-K dated October 10, 2013. In addition, during September 2013, EOG settled certain crude oil derivative contracts covering notional volumes of 5,000 Bbld for the period July 1, 2014 through December 31, 2014. Presented below is a comprehensive summary of EOG's crude oil and natural gas derivative contracts at November 6, 2013, with notional volumes expressed in Bbld and MMBtud and prices expressed in $/Bbl and $/MMBtu. EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. |
|||||||||
|
CRUDE OIL DERIVATIVE CONTRACTS |
|||||||||
|
Weighted |
|||||||||
|
Volume |
Average Price |
||||||||
|
(Bbld) |
($/Bbl) |
||||||||
|
2013 (1) |
|||||||||
|
January 2013 (closed) |
101,000 |
$ 99.29 |
|||||||
|
February 1, 2013 through April 30, 2013 (closed) |
109,000 |
99.17 |
|||||||
|
May 1, 2013 through June 30, 2013 (closed) |
101,000 |
99.29 |
|||||||
|
July 2013 (closed) |
111,000 |
98.25 |
|||||||
|
August 1, 2013 through October 31, 2013 (closed) |
126,000 |
98.80 |
|||||||
|
November 1, 2013 through December 31, 2013 |
126,000 |
98.80 |
|||||||
|
2014 (2) |
|||||||||
|
January 1, 2014 through March 31, 2014 |
128,000 |
$ 96.44 |
|||||||
|
April 1, 2014 through June 30, 2014 |
118,000 |
96.43 |
|||||||
|
July 1, 2014 through December 31, 2014 |
9,000 |
95.30 |
|||||||
|
(1) |
EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for an additional six-month period. Options covering a notional volume of 64,000 Bbld are exercisable on December 31, 2013. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 64,000 Bbld at an average price of $99.58 per barrel for each month during the period January 1, 2014 through June 30, 2014. |
||||||||
|
(2) |
EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional six-month and nine-month periods. Options covering a notional volume of 10,000 Bbld are exercisable on or about March 31, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 10,000 Bbld at an average price of $96.60 per barrel for each month during the period April 1, 2014 through December 31, 2014. Options covering a notional volume of 103,000 Bbld are exercisable on or about June 30, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 103,000 Bbld at an average price of $96.60 per barrel for each month during the period July 1, 2014 through December 31, 2014. Options covering a notional volume of 9,000 Bbld are exercisable on or about December 31, 2014. In addition, in connection with the crude oil derivative contracts settled in September 2013 covering a notional volume of 5,000 Bbld, counterparties retain the option to enter into derivative contracts on December 31, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 14,000 Bbld at an average price of $95.35 per barrel for each month during the period January 1, 2015 through June 30,2015. |
||||||||
|
NATURAL GAS DERIVATIVE CONTRACTS |
|||||||||
|
Weighted |
|||||||||
|
Volume |
Average Price |
||||||||
|
(MMBtud) |
($/MMBtu) |
||||||||
|
2013 (3) |
|||||||||
|
January 1, 2013 through April 30, 2013 (closed) |
150,000 |
$ 4.79 |
|||||||
|
May 1, 2013 through October 31, 2013 (closed) |
200,000 |
4.72 |
|||||||
|
November 2013 (closed) |
150,000 |
4.79 |
|||||||
|
December 2013 |
150,000 |
4.79 |
|||||||
|
2014 (4) |
|||||||||
|
January 1, 2014 through December 31, 2014 |
170,000 |
$ 4.54 |
|||||||
|
(3) |
EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates. Such options are exercisable monthly up until the settlement date of each monthly contract. For December 2013, if the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 150,000 MMBtud at an average price of $4.79 per MMBtu. |
||||||||
|
(4) |
EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates. Additionally, in connection with certain natural gas derivative contracts settled in July 2012, counterparties retain an option of entering into derivative contracts at future dates. All such options are exercisable monthly up until the settlement date of each monthly contract. If the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 320,000 MMBtud at an average price of $4.66 per MMBtu for each month during the period January 1, 2014 through December 31, 2014. |
||||||||
|
$/Bbl |
Dollars per barrel |
||||||||
|
$/MMBtu |
Dollars per million British thermal units |
||||||||
|
Bbld |
Barrels per day |
||||||||
|
MMBtu |
Million British thermal units |
||||||||
|
MMBtud |
Million British thermal units per day |
||||||||
|
EOG RESOURCES, INC. |
||||||||||||||
|
QUANTITATIVE RECONCILIATION OF ADJUSTED EARNINGS BEFORE INTEREST EXPENSE, |
||||||||||||||
|
INCOME TAXES, DEPRECIATION, DEPLETION AND AMORTIZATION, EXPLORATION COSTS, |
||||||||||||||
|
DRY HOLE COSTS, IMPAIRMENTS AND ADDITIONAL ITEMS (ADJUSTED EBITDAX) |
||||||||||||||
|
(NON-GAAP) TO INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES (GAAP) |
||||||||||||||
|
(Unaudited; in thousands) |
||||||||||||||
|
The following chart adjusts the three-month and nine-month periods ended September 30, 2013 and 2012 reported Income Before Interest Expense and Income Taxes (GAAP) to Earnings Before Interest Expense, Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash realized from financial commodity derivative transactions by eliminating the unrealized mark-to-market (MTM) losses (gains) from these transactions and to eliminate the net gains on asset dispositions in North America in 2013 and 2012. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Income Before Interest Expense and Income Taxes (GAAP) to add back Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for comparative purposes within the industry. |
||||||||||||||
|
Three Months Ended |
Nine Months Ended |
|||||||||||||
|
September 30, |
September 30, |
|||||||||||||
|
2013 |
2012 |
2013 |
2012 |
|||||||||||
|
Income Before Interest Expense and Income Taxes (GAAP) |
$ |
780,937 |
$ |
613,343 |
$ |
2,700,754 |
$ |
1,880,760 |
||||||
|
Adjustments |
||||||||||||||
|
Depreciation, Depletion and Amortization |
928,800 |
825,851 |
2,685,719 |
2,383,359 |
||||||||||
|
Exploration Costs |
39,429 |
45,953 |
130,968 |
136,909 |
||||||||||
|
Dry Hole Costs |
19,548 |
1,924 |
59,260 |
13,005 |
||||||||||
|
Impairments |
85,917 |
62,875 |
177,432 |
250,239 |
||||||||||
|
EBITDAX (Non-GAAP) |
1,854,631 |
1,549,946 |
5,754,133 |
4,664,272 |
||||||||||
|
Total Losses (Gains) on MTM Commodity Derivative Contracts |
293,387 |
(4,671) |
206,853 |
(327,328) |
||||||||||
|
Realized (Losses) Gains on MTM Commodity Derivative Contracts |
(20,636) |
249,166 |
115,323 |
555,946 |
||||||||||
|
Net Gains on Asset Dispositions |
(8,183) |
(67,376) |
(185,569) |
(248,134) |
||||||||||
|
Adjusted EBITDAX (Non-GAAP) |
$ |
2,119,199 |
$ |
1,727,065 |
$ |
5,890,740 |
(a) |
$ |
4,644,756 |
(b) |
||||
|
Percentage Increase - [(a) - (b)] / (b) |
27% |
|||||||||||||
|
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. |
|
At |
||||
|
September 30, |
||||
|
2013 |
||||
|
Total Stockholders' Equity - (a) |
$ |
14,862 |
||
|
Current and Long-Term Debt - (b) |
6,313 |
|||
|
Less: Cash |
(1,319) |
|||
|
Net Debt (Non-GAAP) - (c) |
4,994 |
|||
|
Total Capitalization (GAAP) - (a) + (b) |
$ |
21,175 |
||
|
Total Capitalization (Non-GAAP) - (a) + (c) |
$ |
19,856 |
||
|
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] |
30% |
|||
|
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] |
25% |
|||
|
EOG RESOURCES, INC. |
|||||||||||||||
|
FOURTH QUARTER AND FULL YEAR 2013 FORECAST AND BENCHMARK COMMODITY PRICING |
|||||||||||||||
|
(a) Fourth Quarter and Full Year 2013 Forecast |
|||||||||||||||
|
The forecast items for the fourth quarter and full year 2013 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 2013 |
Full Year 2013 |
||||||||||||||
|
Daily Production |
|||||||||||||||
|
Crude Oil and Condensate Volumes (MBbld) |
|||||||||||||||
|
United States |
227.0 |
- |
233.0 |
210.0 |
- |
212.0 |
|||||||||
|
Canada |
6.0 |
- |
8.0 |
6.0 |
- |
7.0 |
|||||||||
|
Trinidad |
0.9 |
- |
1.1 |
1.1 |
- |
1.3 |
|||||||||
|
Other International |
0.0 |
- |
0.0 |
0.0 |
- |
0.0 |
|||||||||
|
Total |
233.9 |
- |
242.1 |
217.1 |
- |
220.3 |
|||||||||
|
Natural Gas Liquids Volumes (MBbld) |
|||||||||||||||
|
United States |
64.0 |
- |
70.0 |
64.0 |
- |
65.0 |
|||||||||
|
Canada |
0.7 |
- |
1.1 |
0.9 |
- |
1.0 |
|||||||||
|
Total |
64.7 |
- |
71.1 |
64.9 |
- |
66.0 |
|||||||||
|
Natural Gas Volumes (MMcfd) |
|||||||||||||||
|
United States |
855 |
- |
880 |
904 |
- |
910 |
|||||||||
|
Canada |
62 |
- |
82 |
74 |
- |
79 |
|||||||||
|
Trinidad |
335 |
- |
375 |
346 |
- |
356 |
|||||||||
|
Other International |
5 |
- |
11 |
7 |
- |
8 |
|||||||||
|
Total |
1,257 |
- |
1,348 |
1,331 |
- |
1,353 |
|||||||||
|
Crude Oil Equivalent Volumes (MBoed) |
|||||||||||||||
|
United States |
433.5 |
- |
449.7 |
424.7 |
- |
428.7 |
|||||||||
|
Canada |
17.0 |
- |
22.8 |
19.2 |
- |
21.2 |
|||||||||
|
Trinidad |
56.7 |
- |
63.6 |
58.8 |
- |
60.6 |
|||||||||
|
Other International |
0.8 |
- |
1.8 |
1.2 |
- |
1.3 |
|||||||||
|
Total |
508.0 |
- |
537.9 |
503.9 |
- |
511.8 |
|||||||||
|
Operating Costs |
|||||||||||||||
|
Unit Costs ($/Boe) |
|||||||||||||||
|
Lease and Well |
$ |
6.20 |
- |
$ |
6.40 |
$ |
6.02 |
- |
$ |
6.07 |
|||||
|
Transportation Costs |
$ |
4.50 |
- |
$ |
4.70 |
$ |
4.55 |
- |
$ |
4.61 |
|||||
|
Depreciation, Depletion and Amortization |
$ |
19.40 |
- |
$ |
19.80 |
$ |
19.52 |
- |
$ |
19.63 |
|||||
|
Expenses ($MM) |
|||||||||||||||
|
Exploration, Dry Hole and Impairment |
$ |
140.0 |
- |
$ |
190.0 |
$ |
500.0 |
- |
$ |
550.0 |
|||||
|
General and Administrative |
$ |
92.0 |
- |
$ |
97.0 |
$ |
350.0 |
- |
$ |
355.0 |
|||||
|
Gathering and Processing |
$ |
29.0 |
- |
$ |
33.0 |
$ |
110.0 |
- |
$ |
115.0 |
|||||
|
Capitalized Interest |
$ |
12.0 |
- |
$ |
15.0 |
$ |
46.0 |
- |
$ |
50.0 |
|||||
|
Net Interest |
$ |
50.0 |
- |
$ |
54.0 |
$ |
233.0 |
- |
$ |
237.0 |
|||||
|
Taxes Other Than Income (% of Wellhead Revenue) |
5.9% |
- |
6.3% |
5.8% |
- |
5.9% |
|||||||||
|
Income Taxes |
|||||||||||||||
|
Effective Rate |
35% |
- |
40% |
35% |
- |
38% |
|||||||||
|
Current Taxes ($MM) |
$ |
105 |
- |
$ |
120 |
$ |
345 |
- |
$ |
365 |
|||||
|
Capital Expenditures ($MM) - FY 2013 (Excluding Acquisitions) |
|||||||||||||||
|
Exploration and Development, Excluding Facilities |
Approximately |
$ |
6,000 |
||||||||||||
|
Exploration and Development Facilities |
Approximately |
$ |
800 |
||||||||||||
|
Gathering, Processing and Other |
Approximately |
$ |
400 |
||||||||||||
|
Pricing - (Refer to Benchmark Commodity Pricing in text) |
|||||||||||||||
|
Crude Oil and Condensate ($/Bbl) |
|||||||||||||||
|
Differentials |
|||||||||||||||
|
United States - (above) below WTI |
$ |
(0.35) |
- |
$ |
1.15 |
$ |
(4.75) |
- |
$ |
(6.25) |
|||||
|
Canada - (above) below WTI |
$ |
12.00 |
- |
$ |
16.00 |
$ |
9.00 |
- |
$ |
10.00 |
|||||
|
Trinidad - (above) below WTI |
$ |
10.00 |
- |
$ |
14.00 |
$ |
7.00 |
- |
$ |
8.00 |
|||||
|
Natural Gas Liquids |
|||||||||||||||
|
Realizations as % of WTI |
|||||||||||||||
|
United States |
28% |
- |
32% |
31% |
- |
33% |
|||||||||
|
Canada |
33% |
- |
37% |
37% |
- |
39% |
|||||||||
|
Natural Gas ($/Mcf) |
|||||||||||||||
|
Differentials |
|||||||||||||||
|
United States - (above) below NYMEX Henry Hub |
$ |
0.36 |
- |
$ |
0.46 |
$ |
0.35 |
- |
$ |
0.39 |
|||||
|
Canada - (above) below NYMEX Henry Hub |
$ |
0.40 |
- |
$ |
0.50 |
$ |
0.60 |
- |
$ |
0.64 |
|||||
|
Realizations |
|||||||||||||||
|
Trinidad |
$ |
2.75 |
- |
$ |
3.25 |
$ |
3.46 |
- |
$ |
3.60 |
|||||
|
Other International |
$ |
4.50 |
- |
$ |
5.00 |
$ |
6.00 |
- |
$ |
6.14 |
|||||
|
Definitions |
|||||||||||||||
|
$/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 |
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SOURCE EOG Resources, Inc.