News Detail
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INVESTORS
EOG Resources Reports Second Quarter 2013 Results; Increases 2013 Crude Oil Production Growth Target and Overall Total Production Estimates
HOUSTON, Aug. 6, 2013 /PRNewswire/ --
- Delivers 35 Percent Year-Over-Year Total Company Crude Oil Production Growth
- Raises 2013 Full Year Crude Oil Production Target to 35 Percent from 28 Percent
- Increases Total Company Overall Production Growth Target to 7.5 Percent from 4 Percent
- Announces Record South Texas Eagle Ford Oil Well
- Extends Bakken/Three Forks Drilling Inventory and Posts Excellent North Dakota Well Results
- Drives Down Costs in Key Areas of Operations
EOG Resources, Inc. (NYSE: EOG) today reported second quarter 2013 net income of $659.7 million, or $2.42 per share. This compares to second quarter 2012 net income of $395.8 million, or $1.47 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 second quarter 2013 was $573.8 million, or $2.10 per share. Adjusted non-GAAP net income for the second quarter 2012 was $312.4 million, or $1.16 per share. The results for the second quarter 2013 included net gains on asset dispositions of $9.4 million, net of tax ($0.04 per share), impairments of $2.0 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 gain of $191.5 million ($122.6 million after tax, or $0.45 per share) on the mark-to-market of financial commodity contracts. During the quarter, the net cash inflow related to financial commodity contracts was $68.9 million ($44.1 million after tax, or $0.16 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 second quarter 2013. Compared to the second quarter 2012, earnings per share increased 65 percent, discretionary cash flow increased 35 percent and adjusted EBITDAX rose 34 percent. (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).)
"EOG has captured premier positions in key U.S. onshore oil plays – the South Texas Eagle Ford, North Dakota Bakken and Delaware Basin, and we continue to enhance their profitability," said Mark G. Papa, Executive Chairman of the Board. "EOG's financial metrics reflect the superior quality of these assets, as well as our technical acumen in improving well completion design and our ongoing focus on reducing costs."
Operational Highlights
EOG's U.S. crude oil and condensate production increased 37 percent both in the second quarter and the first half of 2013, compared to the same periods in 2012. Total company crude oil and condensate production increased 35 percent in the second quarter over the same prior year period. Total company liquids – crude oil, condensate and natural gas liquids (NGLs) – production rose 30 percent, versus the second quarter 2012.
Based on its exceptional performance during the first half of 2013, EOG is increasing its full year crude oil and condensate production growth target to 35 percent from 28 percent. Total NGL production is expected to increase 14 percent from the previous 10 percent target, while natural gas production is projected to decline 11.5 percent during 2013. Overall, EOG is targeting 7.5 percent total company production growth in 2013. EOG also anticipates certain unit costs will be lower than originally forecast.
"We have the confidence to raise the bar on EOG's performance expectations because our outstanding assets perform better and better, quarter after quarter," said President and Chief Executive Officer William R. "Bill" Thomas. "EOG expects to achieve these higher goals within our previously stated capex estimate."
At June 30, 2013, EOG's Eagle Ford net production of approximately 173,000 barrels of oil equivalent per day, continued to out-perform the rest of the industry.
Since discovering the prolific Eagle Ford, EOG has more than doubled the initial crude oil production rates from its wells in both the western and eastern parts of the play. Efficiency gains from more effective completions and reduced drilling days are resulting in excellent rates of return.
EOG recorded strong well and economic results from its western Eagle Ford acreage where more than a third of its second quarter drilling activity in the play occurred. In La Salle County, EOG's initial production rates and overall well productivity showed a marked improvement, compared to similar completions in the same area three years ago. The Keller #1H and #2H began production at rates of 1,855 and 2,050 barrels of crude oil per day (Bopd) with 75 and 50 barrels per day (Bpd) of NGLs and 430 and 300 thousand cubic feet per day (Mcfd) of natural gas, respectively. The Smart Unit #1H and #2H had initial rates of 1,495 and 2,030 Bopd with 60 and 75 Bpd of NGLs and 340 and 440 Mcfd of natural gas, respectively. The Dossett Unit #1H and #2H were completed to sales at 1,590 and 2,185 Bopd with 85 and 115 Bpd of NGLs and 490 and 655 Mcfd of natural gas, respectively. In McMullen County, the Naylor Jones B #1H started production at 1,830 Bopd with 240 Bpd of NGLs and 1.4 million cubic feet per day (MMcfd) of natural gas. EOG has 100 percent working interest in these seven wells.
EOG again achieved excellent well results in Gonzales County, the northeastern area of its Eagle Ford acreage. The Burrow Unit #3H, #4H and #5H were completed to sales in May at initial production rates of 2,990, 3,030 and 7,515 Bopd with 385, 370 and 860 Bpd of NGLs and 2.2, 2.1 and 5.0 MMcfd of natural gas, respectively. After 30 days, the Burrow Unit #5H, EOG's best Eagle Ford well to date, had an average production rate of 4,265 Bopd. The Wilde Trust Unit #1H, #2H and #3H began production in early June at rates of 5,475, 6,520 and 5,525 Bopd with 880, 710 and 775 Bpd of NGLs and 5.1, 4.1 and 4.5 MMcfd of natural gas, respectively. EOG has 100 percent working interest in these six Gonzales County wells.
"With wells in our western drilling program following the same trend as those in the east, results from the EOG's Eagle Ford activity continue to outpace our expectations," Papa said.
Improved drilling efficiencies and completion technology also have enhanced well productivity in EOG's Bakken/Three Forks operations. During the second quarter, EOG's North Dakota drilling program focused on the Bakken formation. In the Bakken Core, results from 160-acre spacing between wells continue to be encouraging. In Mountrail County, two Core wells drilled on 160-acre spacing, the Parshall 25-3032H and 22-3032H, were completed to sales at 2,685 and 2,120 Bopd, respectively. EOG has 62 percent working interest in these wells. EOG has 78 percent working interest in the Van Hook 29-1113H and 30-1113H, which began production at 2,390 and 2,295 Bopd, respectively, which were also 160-acre spaced wells.
In the Antelope Extension, EOG's other North Dakota development target this year, the Bear Den 20-1708H was completed in the Bakken formation at 2,455 Bopd. EOG has 91 percent working interest in the well.
Based on the success of its current spacing programs, EOG has increased its drilling inventory in the Bakken/Three Forks from seven to 12 years.
EOG remains active in the Delaware Basin Leonard and Wolfcamp, although the plays are constrained by a lack of natural gas processing infrastructure that is being addressed. In Reeves County, Texas, EOG drilled its best Delaware Basin Wolfcamp well to date. EOG has 100 percent working interest in the Phillips State 56 #301H, which was completed to sales at 870 Bopd with 570 Bpd of NGLs and 3.7 MMcfd of natural gas.
EOG completed and brought to sales a number of highly economic wells in the Leonard formation in Lea County, New Mexico. The Diamond 31 Fed Com #2H, #3H and #4H came online at 1,780, 1,905 and 1,530 Bopd with 215, 165 and 150 Bpd of NGLs and 1,200, 910 and 835 Mcfd of natural gas, respectively. EOG has 91 percent working interest in these wells.
"We expect EOG's three high rate-of-return oil plays, the Eagle Ford, Bakken/Three Forks and Delaware Basin, to provide us with years of drilling inventory, as well as significant growth opportunities," Papa said. "These plays just get bigger and better."
Hedging Activity
In recent weeks, EOG has increased the amount of crude oil hedges in place for the remainder of 2013. For the period August 1 through December 31, 2013, EOG has crude oil financial price swap contracts in place for approximately 121,200 Bpd at a weighted average price of $98.82 per barrel, excluding unexercised options.
For the full year 2014, EOG has crude oil financial price swap contracts in place for approximately 51,000 Bpd at a weighted average price of $96.43 per barrel, excluding unexercised options.
EOG also has hedged some natural gas volumes for 2013 and 2014. For the period September 1 through October 31, 2013, EOG has natural gas financial price swap contracts in place for 200,000 million British thermal units per day (MMBtud) at a weighted average price of $4.72 per million British thermal units (MMBtu), excluding unexercised options. For the period November 1 through December 31, 2013, EOG has hedged 150,000 MMBtud at a weighted average price of $4.79 per 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
To date, EOG has closed on approximately $580 million of asset sales, exceeding its stated goal for the year. At June 30, 2013, EOG's total debt outstanding was $6,313 million for a debt-to-total capitalization ratio of 31 percent. Taking into account cash on the balance sheet of $1,228 million at the end of the second quarter, EOG's net debt was $5,085 million for a net debt-to-total capitalization ratio of 26 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).)
Conference Call Scheduled for August 7, 2013
EOG's second quarter 2013 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Wednesday, August 7, 2013. To listen, log on to www.eogresources.com. The webcast will be archived on EOG's website through August 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 |
Six Months Ended |
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June 30, |
June 30, |
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2013 |
2012 |
2013 |
2012 |
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Net Operating Revenues |
$ |
3,840.2 |
$ |
2,909.3 |
$ |
7,196.7 |
$ |
5,716.0 |
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Net Income |
$ |
659.7 |
$ |
395.8 |
$ |
1,154.4 |
$ |
719.8 |
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Net Income Per Share |
|||||||||||||
|
Basic |
$ |
2.44 |
$ |
1.48 |
$ |
4.28 |
$ |
2.70 |
|||||
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Diluted |
$ |
2.42 |
$ |
1.47 |
$ |
4.24 |
$ |
2.67 |
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Average Number of Common Shares |
|||||||||||||
|
Basic |
270.0 |
266.9 |
269.7 |
266.7 |
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Diluted |
272.7 |
270.0 |
272.5 |
270.1 |
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SUMMARY INCOME STATEMENTS |
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Three Months Ended |
Six Months Ended |
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June 30, |
June 30, |
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2013 |
2012 |
2013 |
2012 |
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Net Operating Revenues |
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Crude Oil and Condensate |
$ |
2,012,999 |
$ |
1,376,250 |
$ |
3,794,832 |
$ |
2,686,585 |
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Natural Gas Liquids |
178,457 |
150,023 |
347,986 |
348,333 |
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Natural Gas |
462,602 |
359,421 |
873,481 |
726,705 |
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Gains on Mark-to-Market Commodity Derivative Contracts |
191,490 |
188,449 |
86,534 |
322,657 |
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Gathering, Processing and Marketing |
959,413 |
710,748 |
1,882,370 |
1,428,905 |
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Gains on Asset Dispositions, Net |
13,153 |
113,290 |
177,386 |
180,758 |
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Other, Net |
22,071 |
11,138 |
34,110 |
22,027 |
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Total |
3,840,185 |
2,909,319 |
7,196,699 |
5,715,970 |
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Operating Expenses |
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Lease and Well |
268,888 |
250,756 |
517,888 |
512,251 |
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Transportation Costs |
224,491 |
135,393 |
408,748 |
267,235 |
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Gathering and Processing Costs |
25,897 |
20,588 |
50,401 |
46,180 |
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Exploration Costs |
47,323 |
48,149 |
91,539 |
90,956 |
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Dry Hole Costs |
35,750 |
11,081 |
39,712 |
11,081 |
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Impairments |
37,967 |
54,217 |
91,515 |
187,364 |
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Marketing Costs |
965,490 |
694,118 |
1,870,139 |
1,399,586 |
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Depreciation, Depletion and Amortization |
910,531 |
808,765 |
1,756,919 |
1,557,508 |
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General and Administrative |
80,607 |
75,727 |
158,592 |
151,996 |
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Taxes Other Than Income |
151,197 |
118,186 |
286,128 |
239,702 |
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Total |
2,748,141 |
2,216,980 |
5,271,581 |
4,463,859 |
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Operating Income |
1,092,044 |
692,339 |
1,925,118 |
1,252,111 |
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Other Income (Expense), Net |
4,833 |
4,675 |
(5,301) |
15,306 |
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Income Before Interest Expense and Income Taxes |
1,096,877 |
697,014 |
1,919,817 |
1,267,417 |
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Interest Expense, Net |
61,647 |
50,775 |
123,568 |
101,044 |
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Income Before Income Taxes |
1,035,230 |
646,239 |
1,796,249 |
1,166,373 |
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Income Tax Provision |
375,538 |
250,461 |
641,832 |
446,586 |
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Net Income |
$ |
659,692 |
$ |
395,778 |
$ |
1,154,417 |
$ |
719,787 |
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Dividends Declared per Common Share |
$ |
0.1875 |
$ |
0.17 |
$ |
0.375 |
$ |
0.34 |
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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 |
Six Months Ended |
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June 30, |
June 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) |
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United States |
206.5 |
150.5 |
192.4 |
140.7 |
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Canada |
6.4 |
6.4 |
7.1 |
7.0 |
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Trinidad |
1.4 |
1.7 |
1.3 |
1.9 |
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Other International (B) |
0.1 |
0.1 |
0.1 |
0.1 |
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Total |
214.4 |
158.7 |
200.9 |
149.7 |
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Average Crude Oil and Condensate Prices ($/Bbl) (C) |
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United States |
$ |
103.73 |
$ |
95.80 |
$ |
105.04 |
$ |
98.61 |
|||||
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Canada |
89.66 |
82.78 |
87.29 |
86.33 |
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Trinidad |
86.96 |
88.68 |
90.36 |
94.76 |
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Other International (B) |
92.28 |
91.20 |
93.56 |
96.49 |
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Composite |
103.19 |
95.20 |
104.31 |
98.00 |
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Natural Gas Liquids Volumes (MBbld) (A) |
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United States |
63.7 |
54.6 |
61.2 |
52.4 |
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Canada |
1.0 |
0.9 |
0.9 |
0.9 |
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Total |
64.7 |
55.5 |
62.1 |
53.3 |
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Average Natural Gas Liquids Prices ($/Bbl) (C) |
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|
United States |
$ |
30.19 |
$ |
33.54 |
$ |
30.87 |
$ |
38.12 |
|||||
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Canada |
39.49 |
42.89 |
40.62 |
46.54 |
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Composite |
30.33 |
33.72 |
31.02 |
38.27 |
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Natural Gas Volumes (MMcfd) (A) |
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United States |
928 |
1,070 |
931 |
1,067 |
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Canada |
79 |
96 |
79 |
100 |
|||||||||
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Trinidad |
346 |
422 |
349 |
396 |
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Other International (B) |
8 |
10 |
8 |
10 |
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Total |
1,361 |
1,598 |
1,367 |
1,573 |
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Average Natural Gas Prices ($/Mcf) (C) |
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United States |
$ |
3.73 |
$ |
2.09 |
$ |
3.41 |
$ |
2.28 |
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Canada |
3.17 |
2.21 |
3.21 |
2.33 |
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Trinidad |
3.82 |
3.42 |
3.86 |
3.21 |
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Other International (B) |
6.81 |
5.64 |
6.78 |
5.72 |
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Composite |
3.73 |
2.47 |
3.53 |
2.54 |
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Crude Oil Equivalent Volumes (MBoed) (D) |
|||||||||||||
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United States |
424.8 |
383.3 |
408.8 |
370.9 |
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Canada |
20.6 |
23.4 |
21.2 |
24.6 |
|||||||||
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Trinidad |
59.0 |
72.0 |
59.4 |
67.9 |
|||||||||
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Other International (B) |
1.5 |
1.8 |
1.4 |
1.8 |
|||||||||
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Total |
505.9 |
480.5 |
490.8 |
465.2 |
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Total MMBoe (D) |
46.0 |
43.7 |
88.8 |
84.7 |
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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, China and Argentina 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. |
||||||||||||
|
EOG RESOURCES, INC. |
||||||||
|
SUMMARY BALANCE SHEETS |
||||||||
|
(Unaudited; in thousands, except share data) |
||||||||
|
June 30, |
December 31, |
|||||||
|
2013 |
2012 |
|||||||
|
ASSETS |
||||||||
|
Current Assets |
||||||||
|
Cash and Cash Equivalents |
$ |
1,228,016 |
$ |
876,435 |
||||
|
Accounts Receivable, Net |
1,808,954 |
1,656,618 |
||||||
|
Inventories |
657,400 |
683,187 |
||||||
|
Assets from Price Risk Management Activities |
105,667 |
166,135 |
||||||
|
Income Taxes Receivable |
23,450 |
29,163 |
||||||
|
Deferred Income Taxes |
157,012 |
- |
||||||
|
Other |
260,341 |
178,346 |
||||||
|
Total |
4,240,840 |
3,589,884 |
||||||
|
Property, Plant and Equipment |
||||||||
|
Oil and Gas Properties (Successful Efforts Method) |
40,262,580 |
38,126,298 |
||||||
|
Other Property, Plant and Equipment |
2,846,971 |
2,740,619 |
||||||
|
Total Property, Plant and Equipment |
43,109,551 |
40,866,917 |
||||||
|
Less: Accumulated Depreciation, Depletion and Amortization |
(18,529,163) |
(17,529,236) |
||||||
|
Total Property, Plant and Equipment, Net |
24,580,388 |
23,337,681 |
||||||
|
Other Assets |
255,924 |
409,013 |
||||||
|
Total Assets |
$ |
29,077,152 |
$ |
27,336,578 |
||||
|
LIABILITIES AND STOCKHOLDERS' EQUITY |
||||||||
|
Current Liabilities |
||||||||
|
Accounts Payable |
$ |
2,201,940 |
$ |
2,078,948 |
||||
|
Accrued Taxes Payable |
161,608 |
162,083 |
||||||
|
Dividends Payable |
50,614 |
45,802 |
||||||
|
Liabilities from Price Risk Management Activities |
5,482 |
7,617 |
||||||
|
Deferred Income Taxes |
4,310 |
22,838 |
||||||
|
Current Portion of Long-Term Debt |
406,579 |
406,579 |
||||||
|
Other |
189,770 |
200,191 |
||||||
|
Total |
3,020,303 |
2,924,058 |
||||||
|
Long-Term Debt |
5,906,210 |
5,905,602 |
||||||
|
Other Liabilities |
795,308 |
894,758 |
||||||
|
Deferred Income Taxes |
4,970,705 |
4,327,396 |
||||||
|
Commitments and Contingencies |
||||||||
|
Stockholders' Equity |
||||||||
|
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 272,611,848 Shares Issued at June 30, 2013 and 271,958,495 Shares Issued at December 31, 2012 |
||||||||
|
202,726 |
202,720 |
|||||||
|
Additional Paid in Capital |
2,576,441 |
2,500,340 |
||||||
|
Accumulated Other Comprehensive Income |
408,257 |
439,895 |
||||||
|
Retained Earnings |
11,228,011 |
10,175,631 |
||||||
|
Common Stock Held in Treasury, 277,274 Shares at June 30, 2013 and 326,264 Shares at December 31, 2012 |
(30,809) |
(33,822) |
||||||
|
Total Stockholders' Equity |
14,384,626 |
13,284,764 |
||||||
|
Total Liabilities and Stockholders' Equity |
$ |
29,077,152 |
$ |
27,336,578 |
||||
|
EOG RESOURCES, INC. |
||||||||
|
SUMMARY STATEMENTS OF CASH FLOWS |
||||||||
|
(Unaudited; in thousands) |
||||||||
|
Six Months Ended |
||||||||
|
June 30, |
||||||||
|
2013 |
2012 |
|||||||
|
Cash Flows from Operating Activities |
||||||||
|
Reconciliation of Net Income to Net Cash Provided by Operating Activities: |
||||||||
|
Net Income |
$ |
1,154,417 |
$ |
719,787 |
||||
|
Items Not Requiring (Providing) Cash |
||||||||
|
Depreciation, Depletion and Amortization |
1,756,919 |
1,557,508 |
||||||
|
Impairments |
91,515 |
187,364 |
||||||
|
Stock-Based Compensation Expenses |
57,724 |
55,466 |
||||||
|
Deferred Income Taxes |
488,632 |
278,826 |
||||||
|
Gains on Asset Dispositions, Net |
(177,386) |
(180,758) |
||||||
|
Other, Net |
8,747 |
(3,404) |
||||||
|
Dry Hole Costs |
39,712 |
11,081 |
||||||
|
Mark-to-Market Commodity Derivative Contracts |
||||||||
|
Total Gains |
(86,534) |
(322,657) |
||||||
|
Realized Gains |
135,959 |
306,780 |
||||||
|
Excess Tax Benefits from Stock-Based Compensation |
(21,869) |
(22,115) |
||||||
|
Other, Net |
7,759 |
9,890 |
||||||
|
Changes in Components of Working Capital and Other Assets and Liabilities |
||||||||
|
Accounts Receivable |
(164,809) |
115,419 |
||||||
|
Inventories |
22,085 |
(103,576) |
||||||
|
Accounts Payable |
141,369 |
176,355 |
||||||
|
Accrued Taxes Payable |
24,816 |
14,363 |
||||||
|
Other Assets |
(92,305) |
(102,303) |
||||||
|
Other Liabilities |
(51,400) |
(27,355) |
||||||
|
Changes in Components of Working Capital Associated with Investing and
Financing Activities |
(19,639) |
(97,453) |
||||||
|
Net Cash Provided by Operating Activities |
3,315,712 |
2,573,218 |
||||||
|
Investing Cash Flows |
||||||||
|
Additions to Oil and Gas Properties |
(3,250,091) |
(3,748,278) |
||||||
|
Additions to Other Property, Plant and Equipment |
(183,516) |
(315,542) |
||||||
|
Proceeds from Sales of Assets |
579,941 |
1,111,517 |
||||||
|
Changes in Restricted Cash |
(52,322) |
- |
||||||
|
Changes in Components of Working Capital Associated with Investing Activities |
19,358 |
97,746 |
||||||
|
Net Cash Used in Investing Activities |
(2,886,630) |
(2,854,557) |
||||||
|
Financing Cash Flows |
||||||||
|
Dividends Paid |
(97,006) |
(88,892) |
||||||
|
Excess Tax Benefits from Stock-Based Compensation |
21,869 |
22,115 |
||||||
|
Treasury Stock Purchased |
(21,094) |
(22,663) |
||||||
|
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan |
20,773 |
32,986 |
||||||
|
Repayment of Capital Lease Obligation |
(2,866) |
- |
||||||
|
Other, Net |
281 |
(293) |
||||||
|
Net Cash Used in Financing Activities |
(78,043) |
(56,747) |
||||||
|
Effect of Exchange Rate Changes on Cash |
542 |
2,734 |
||||||
|
Increase (Decrease) in Cash and Cash Equivalents |
351,581 |
(335,352) |
||||||
|
Cash and Cash Equivalents at Beginning of Period |
876,435 |
615,726 |
||||||
|
Cash and Cash Equivalents at End of Period |
$ |
1,228,016 |
$ |
280,374 |
||||
|
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 six-month periods ended June 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 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 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 |
Six Months Ended |
||||||||||||
|
June 30, |
June 30, |
||||||||||||
|
2013 |
2012 |
2013 |
2012 |
||||||||||
|
Reported Net Income (GAAP) |
$ |
659,692 |
$ |
395,778 |
$ |
1,154,417 |
$ |
719,787 |
|||||
|
Mark-to-Market (MTM) Commodity Derivative Contracts Impact |
|||||||||||||
|
Total Gains |
(191,490) |
(188,449) |
(86,534) |
(322,657) |
|||||||||
|
Realized Gains |
68,909 |
173,179 |
135,959 |
306,780 |
|||||||||
|
Subtotal |
(122,581) |
(15,270) |
49,425 |
(15,877) |
|||||||||
|
After-Tax MTM Impact |
(78,482) |
(9,776) |
31,645 |
(10,165) |
|||||||||
|
Less: Net Gains on Asset Dispositions, Net of Tax |
(9,382) |
(75,087) |
(124,375) |
(118,298) |
|||||||||
|
Add: Impairments of Certain North American Assets, Net of Tax |
2,003 |
1,526 |
2,003 |
38,575 |
|||||||||
|
Adjusted Net Income (Non-GAAP) |
$ |
573,831 |
$ |
312,441 |
$ |
1,063,690 |
$ |
629,899 |
|||||
|
Net Income Per Share (GAAP) |
|||||||||||||
|
Basic |
$ |
2.44 |
$ |
1.48 |
$ |
4.28 |
$ |
2.70 |
|||||
|
Diluted |
$ |
2.42 |
(a) |
$ |
1.47 |
(b) |
$ |
4.24 |
$ |
2.67 |
|||
|
Percentage Increase - [(a) - (b)] / (b) |
65% |
||||||||||||
|
Adjusted Net Income Per Share (Non-GAAP) |
|||||||||||||
|
Basic |
$ |
2.13 |
$ |
1.17 |
$ |
3.94 |
$ |
2.36 |
|||||
|
Diluted |
$ |
2.10 |
$ |
1.16 |
$ |
3.90 |
$ |
2.33 |
|||||
|
Average Number of Common Shares |
|||||||||||||
|
Basic |
270,016 |
266,874 |
269,665 |
266,718 |
|||||||||
|
Diluted |
272,739 |
269,985 |
272,473 |
270,083 |
|||||||||
|
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 six-month periods ended June 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 |
Six Months Ended |
|||||||||||||
|
June 30, |
June 30, |
|||||||||||||
|
2013 |
2012 |
2013 |
2012 |
|||||||||||
|
Net Cash Provided by Operating Activities (GAAP) |
$ |
1,890,777 |
$ |
1,495,613 |
$ |
3,315,712 |
$ |
2,573,218 |
||||||
|
Adjustments |
||||||||||||||
|
Exploration Costs (excluding Stock-Based Compensation Expenses) |
40,930 |
41,890 |
77,575 |
78,078 |
||||||||||
|
Excess Tax Benefits from Stock-Based Compensation |
10,196 |
5,464 |
21,869 |
22,115 |
||||||||||
|
Changes in Components of Working Capital and Other Assets and Liabilities |
||||||||||||||
|
Accounts Receivable |
(71,948) |
(205,367) |
164,809 |
(115,419) |
||||||||||
|
Inventories |
(37,143) |
113,784 |
(22,085) |
103,576 |
||||||||||
|
Accounts Payable |
44,696 |
60,270 |
(141,369) |
(176,355) |
||||||||||
|
Accrued Taxes Payable |
(15,812) |
(19,526) |
(24,816) |
(14,363) |
||||||||||
|
Other Assets |
45,112 |
(6,537) |
92,305 |
102,303 |
||||||||||
|
Other Liabilities |
(1,533) |
22,296 |
51,400 |
27,355 |
||||||||||
|
Changes in Components of Working Capital Associated with Investing and Financing Activities |
||||||||||||||
|
(37,782) |
(126,222) |
19,639 |
97,453 |
|||||||||||
|
Discretionary Cash Flow (Non-GAAP) |
$ |
1,867,493 |
(a) |
$ |
1,381,665 |
(b) |
$ |
3,555,039 |
$ |
2,697,961 |
||||
|
Percentage Increase - [(a) - (b)] / (b) |
35% |
|||||||||||||
|
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 six-month periods ended June 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) gains from these transactions and to eliminate the net gains on asset dispositions primarily 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 |
Six Months Ended |
|||||||||||
|
June 30, |
June 30, |
|||||||||||
|
2013 |
2012 |
2013 |
2012 |
|||||||||
|
Income Before Interest Expense and Income Taxes (GAAP) |
$ |
1,096,877 |
$ |
697,014 |
$ |
1,919,817 |
$ |
1,267,417 |
||||
|
Adjustments: |
||||||||||||
|
Depreciation, Depletion and Amortization |
910,531 |
808,765 |
1,756,919 |
1,557,508 |
||||||||
|
Exploration Costs |
47,323 |
48,149 |
91,539 |
90,956 |
||||||||
|
Dry Hole Costs |
35,750 |
11,081 |
39,712 |
11,081 |
||||||||
|
Impairments |
37,967 |
54,217 |
91,515 |
187,364 |
||||||||
|
EBITDAX (Non-GAAP) |
2,128,448 |
1,619,226 |
3,899,502 |
3,114,326 |
||||||||
|
Total Gains on MTM Commodity Derivative Contracts |
(191,490) |
(188,449) |
(86,534) |
(322,657) |
||||||||
|
Realized Gains on MTM Commodity Derivative Contracts |
68,909 |
173,179 |
135,959 |
306,780 |
||||||||
|
Net Gains on Asset Dispositions |
(13,153) |
(113,290) |
(177,386) |
(180,758) |
||||||||
|
Adjusted EBITDAX (Non-GAAP) |
$ |
1,992,714 |
(a) |
$ |
1,490,666 |
(b) |
$ |
3,771,541 |
$ |
2,917,691 |
||
|
Percentage Increase - [(a) - (b)] / (b) |
34% |
|||||||||||
|
EOG RESOURCES, INC. |
|||||||||
|
CRUDE OIL AND NATURAL GAS FINANCIAL |
|||||||||
|
COMMODITY DERIVATIVE CONTRACTS |
|||||||||
|
Presented below is a comprehensive summary of EOG's crude oil and natural gas derivative contracts at August 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 September 30, 2013 |
126,000 |
98.80 |
|||||||
|
October 1, 2013 through December 31, 2013 |
118,000 |
98.84 |
|||||||
|
2014 (2) |
|||||||||
|
January 1, 2014 through March 31, 2014 |
103,000 |
$96.48 |
|||||||
|
April 1, 2014 through June 30, 2014 |
93,000 |
96.47 |
|||||||
|
July 1, 2014 through December 31, 2014 |
5,000 |
95.43 |
|||||||
|
(1) |
EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional three-month and six-month periods. Options covering a notional volume of 8,000 Bbld are exercisable on September 30, 2013. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 8,000 Bbld at an average price of $98.11 per barrel for each month during the period October 1, 2013 through December 31, 2013. 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 93,000 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 93,000 Bbld at an average price of $96.47 per barrel for each month during the period July 1, 2014 through December 31, 2014. Options covering a notional volume of 5,000 Bbld are exercisable 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 5,000 Bbld at an average price of $95.43 per barrel for each month during the period January 1, 2015 through June 30,2015. |
||||||||
|
NATURAL GAS DERIVATIVE CONTRACTS |
|||||||||
|
Weighted |
|||||||||
|
Volume |
Average Price |
||||||||
|
(MMBtud) |
($/MMBtu) |
||||||||
|
2013 (3) |
|||||||||
|
January 1, 2013 through April 30, 2013 (closed) |
150,000 |
$4.79 |
|||||||
|
May 1, 2013 through August 31, 2013 (closed) |
200,000 |
4.72 |
|||||||
|
September 1, 2013 through October 31, 2013 |
200,000 |
4.72 |
|||||||
|
November 1, 2013 through December 31, 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 the period September 1, 2013 through October 31, 2013, if the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 200,000 MMBtud at an average price of $4.72 per MMBtu for each month during that period. For the period November 1, 2013 through December 31, 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 for each month during that period. |
||||||||
|
(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. |
||||||||
|
Bbld |
Barrels per day |
||||||||
|
$/Bbl |
Dollars per barrel |
||||||||
|
MMBtud |
Million British thermal units per day |
||||||||
|
$/MMBtu |
Dollars per million British thermal units |
||||||||
|
MMBtu |
Million British thermal units |
||||||||
|
EOG RESOURCES, INC. |
|||
|
QUANTITATIVE RECONCILIATION OF NET DEBT (NON-GAAP) AND TOTAL |
|||
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CAPITALIZATION (NON-GAAP) AS USED IN THE CALCULATION OF |
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THE NET DEBT-TO-TOTAL CAPITALIZATION RATIO (NON-GAAP) TO |
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CURRENT AND LONG-TERM DEBT (GAAP) AND TOTAL CAPITALIZATION (GAAP) |
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(Unaudited; in millions, except ratio data) |
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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. |
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At |
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June 30, |
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2013 |
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Total Stockholders' Equity - (a) |
$ |
14,385 |
|
|
Current and Long-Term Debt - (b) |
6,313 |
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Less: Cash |
(1,228) |
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Net Debt (Non-GAAP) - (c) |
5,085 |
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Total Capitalization (GAAP) - (a) + (b) |
$ |
20,698 |
|
|
Total Capitalization (Non-GAAP) - (a) + (c) |
$ |
19,470 |
|
|
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] |
31% |
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Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] |
26% |
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EOG RESOURCES, INC. |
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THIRD QUARTER AND FULL YEAR 2013 FORECAST AND BENCHMARK COMMODITY PRICING |
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(a) Third Quarter and Full Year 2013 Forecast |
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The forecast items for the third 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. |
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(b) Benchmark Commodity Pricing |
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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. |
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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. |
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ESTIMATED RANGES |
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(Unaudited) |
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3Q 2013 |
Full Year 2013 |
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Daily Production |
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|
Crude Oil and Condensate Volumes (MBbld) |
|||||||||||||||
|
United States |
207.0 |
- |
224.0 |
201.0 |
- |
211.0 |
|||||||||
|
Canada |
6.2 |
- |
6.8 |
6.0 |
- |
7.0 |
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|
Trinidad |
1.1 |
- |
1.6 |
1.0 |
- |
1.6 |
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Other International |
0.0 |
- |
0.0 |
0.0 |
- |
0.0 |
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|
Total |
214.3 |
- |
232.4 |
208.0 |
- |
219.6 |
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|
Natural Gas Liquids Volumes (MBbld) |
|||||||||||||||
|
United States |
62.0 |
- |
66.0 |
58.9 |
- |
66.9 |
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|
Canada |
0.6 |
- |
1.1 |
0.7 |
- |
0.8 |
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Total |
62.6 |
- |
67.1 |
59.6 |
- |
67.7 |
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Natural Gas Volumes (MMcfd) |
|||||||||||||||
|
United States |
850 |
- |
900 |
890 |
- |
910 |
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|
Canada |
69 |
- |
76 |
70 |
- |
80 |
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|
Trinidad |
340 |
- |
360 |
348 |
- |
368 |
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Other International |
7 |
- |
9 |
7 |
- |
9 |
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Total |
1,266 |
- |
1,345 |
1,315 |
- |
1,367 |
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|
Crude Oil Equivalent Volumes (MBoed) |
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|
United States |
410.7 |
- |
440.0 |
408.2 |
- |
429.6 |
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|
Canada |
18.3 |
- |
20.6 |
18.4 |
- |
21.1 |
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Trinidad |
57.8 |
- |
61.6 |
59.0 |
- |
62.9 |
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Other International |
1.2 |
- |
1.5 |
1.2 |
- |
1.5 |
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Total |
488.0 |
- |
523.7 |
486.8 |
- |
515.1 |
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Operating Costs |
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Unit Costs ($/Boe) |
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Lease and Well |
$ |
6.37 |
- |
$ |
6.62 |
$ |
6.05 |
- |
$ |
6.25 |
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Transportation Costs |
$ |
4.57 |
- |
$ |
4.82 |
$ |
4.45 |
- |
$ |
4.85 |
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Depreciation, Depletion and Amortization |
$ |
19.50 |
- |
$ |
20.00 |
$ |
19.60 |
- |
$ |
20.10 |
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Expenses ($MM) |
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Exploration, Dry Hole and Impairment |
$ |
130.0 |
- |
$ |
170.0 |
$ |
510.0 |
- |
$ |
540.0 |
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General and Administrative |
$ |
105.0 |
- |
$ |
115.0 |
$ |
360.0 |
- |
$ |
390.0 |
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Gathering and Processing |
$ |
25.0 |
- |
$ |
35.0 |
$ |
100.0 |
- |
$ |
130.0 |
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Capitalized Interest |
$ |
12.0 |
- |
$ |
15.0 |
$ |
40.0 |
- |
$ |
50.0 |
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Net Interest |
$ |
58.0 |
- |
$ |
60.0 |
$ |
226.0 |
- |
$ |
246.0 |
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Taxes Other Than Income (% of Wellhead Revenue) |
5.9% |
- |
6.3% |
5.5% |
- |
6.5% |
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Income Taxes |
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Effective Rate |
30% |
- |
40% |
35% |
- |
40% |
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Current Taxes ($MM) |
$ |
80 |
- |
$ |
90 |
$ |
305 |
- |
$ |
325 |
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Capital Expenditures ($MM) - FY 2013 (Excluding Acquisitions) |
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Exploration and Development, Excluding Facilities |
$ |
5,900 |
- |
$ |
6,000 |
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Exploration and Development Facilities |
$ |
730 |
- |
$ |
790 |
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Gathering, Processing and Other |
$ |
415 |
- |
$ |
445 |
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Pricing - (Refer to Benchmark Commodity Pricing in text) |
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Crude Oil and Condensate ($/Bbl) |
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Differentials |
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|
United States - (above) below WTI |
$ |
(2.00) |
- |
$ |
(3.50) |
$ |
(5.40) |
- |
$ |
(7.40) |
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|
Canada - (above) below WTI |
$ |
6.50 |
- |
$ |
9.00 |
$ |
7.00 |
- |
$ |
9.00 |
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|
Trinidad - (above) below WTI |
$ |
5.00 |
- |
$ |
7.00 |
$ |
4.00 |
- |
$ |
6.00 |
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Natural Gas Liquids |
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Realizations as % of WTI |
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|
United States |
28% |
- |
32% |
28% |
- |
32% |
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|
Canada |
40% |
- |
45% |
39% |
- |
43% |
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|
Natural Gas ($/Mcf) |
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|
Differentials |
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|
United States - (above) below NYMEX Henry Hub |
$ |
0.32 |
- |
$ |
0.40 |
$ |
0.24 |
- |
$ |
0.50 |
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|
Canada - (above) below NYMEX Henry Hub |
$ |
0.75 |
- |
$ |
0.85 |
$ |
0.47 |
- |
$ |
0.77 |
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Realizations |
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|
Trinidad |
$ |
2.75 |
- |
$ |
3.25 |
$ |
3.00 |
- |
$ |
3.50 |
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Other International |
$ |
4.95 |
- |
$ |
5.45 |
$ |
5.35 |
- |
$ |
6.35 |
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Definitions |
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$/Bbl |
U.S. Dollars per barrel |
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$/Boe |
U.S. Dollars per barrel of oil equivalent |
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$/Mcf |
U.S. Dollars per thousand cubic feet |
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$MM |
U.S. Dollars in millions |
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MBbld |
Thousand barrels per day |
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MBoed |
Thousand barrels of oil equivalent per day |
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MMcfd |
Million cubic feet per day |
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NYMEX |
New York Mercantile Exchange |
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WTI |
West Texas Intermediate |
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SOURCE EOG Resources, Inc.