EOG Resources Announces Outstanding Second Quarter 2014 Results; Increases Common Stock Dividend 34 Percent and Adds Delaware B

  EOG Resources Announces Outstanding Second Quarter 2014 Results; Increases    Common Stock Dividend 34 Percent and Adds Delaware Basin Crude Oil Play  PR Newswire  HOUSTON, Aug. 5, 2014  HOUSTON, Aug. 5, 2014 /PRNewswire/ --    oReports 17 Percent Increase in Total Production, Plus 33 Percent Increase     in US Crude Oil and Condensate Production Year-Over-Year   oRaises Common Stock Dividend 34 Percent, Second Increase in 2014   oAdds Second Bone Spring Sand Crude Oil Play to Portfolio of High Return     Assets   oRealizes Positive Leonard Shale Downspacing Tests   oBuilds on Stellar Eagle Ford and Bakken Success  EOG Resources, Inc.(NYSE: EOG) (EOG) today reported second quarter 2014 net income of $706.4 million, or $1.29 per share. This compares to second quarter 2013 net income of $659.7 million, or $1.21 per share.  Adjusted non-GAAP net income for the second quarter 2014 was $796.0 million, or $1.45 per share, and adjusted non-GAAP net income for the same prior year period was $573.8 million, or $1.05 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 2014 excluded a previously disclosed non-cash net loss of $229.3 million ($147.0 million after-tax, or $0.27 per share) on the mark-to-market of financial commodity derivative contracts and net gains on asset dispositions of $3.9 million ($1.7 million net of tax, or $0.01 per share). During the second quarter 2014, the net cash outflow related to settlements of financial commodity derivative contracts was $86.9 million ($55.7 million after-tax, or $0.10 per share). (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)  For the first half 2014, EOG posted strong financial metrics driven by reinvestment of capital into high rate-of-return drilling opportunities. Discretionary cash flow increased 22 percent and adjusted EBITDAX advanced 24 percent. In addition, adjusted non-GAAP earnings per share increased 46 percent, compared to the first half 2013. (Please refer to the attached tables for the reconciliation of non-GAAP discretionary cash flow to net cash provided by operating activities (GAAP), adjusted non-GAAP EBITDAX to income before interest expense and income taxes (GAAP) and adjusted non-GAAP net income to GAAP net income.)  Dividend Increase  The board of directors increased the cash dividend on the common stock by 34 percent. Effective with the dividend payable October 31, 2014, to holders of record as of October 17, 2014, the board declared a quarterly dividend of $0.1675 per share on the common stock. The indicated annual rate of $0.67 per share represents the 16^th increase in 15 years.  "EOG's bottom line is a reflection of our top quality drilling operations and return focused capital investments," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "Because EOG has demonstrated its ability to sustain crude oil growth and reinvest cash flows in high return assets, we've increased the common stock dividend for the second time this year, enhancing long-term value for our stockholders."  Operational Highlights  In the U.S., crude oil and condensate production increased 33 percent in the second quarter 2014, compared to the same prior year period. Production gains from the South Texas Eagle Ford and North Dakota Bakken led EOG's U.S. crude oil production growth. Driven by the South Texas Eagle Ford and the Permian Basin, natural gas liquids (NGLs) production increased 22 percent, compared to the second quarter 2013. Natural gas production slightly increased due to EOG's Trinidad operations and strong associated gas production in the U.S. Overall, total company production increased 17 percent.  Delaware Basin  EOG expanded its inventory of crude oil plays with successful drilling results in the Second Bone Spring Sand, which underlies its extensive Leonard Shale acreage position in Lea and Eddycounties, New Mexico. Through the application of advanced completion techniques, EOG realized robust results from two recent wells. The Mars 3 State #1H, in which EOG has 67 percent working interest, came online at 1,270 barrels of oil per day (Bopd) with 150 barrels per day (Bpd) of NGLs and 1.1 million cubic feet per day (MMcfd) of natural gas. EOG has 100 percent working interest in the Jolly Roger 16 State #1H, which had an initial production rate of 1,450 Bopd with 210 Bpd of NGLs and 1.5 MMcfd of natural gas. While EOG estimates the play may be prospective over the majority of its 73,000 net Leonard acres, evaluation and confirmation is ongoing. Across the Second Bone Spring Sand, EOG's production mix is estimated to be approximately 70 percent crude oil with average estimated gross reserves per well of 500 thousand barrels of oil equivalent. Plans are to drill several more wells in the Second Bone Spring Sand in 2014 and increase activity in 2015.  In the West Texas and southeast New Mexico Leonard Shale play, EOG continues to enhance completions and test well spacing both within and across zones to maximize recovery of the hydrocarbons in place.  Over the last 12 months, EOG has systematically tightened spacing from 660 to 300 feet between wells to test production interference between Leonard 'A' wells. In Lea County, EOG completed a 500-foot spacing test by drilling the Dragon 36 State #05H, #06H, #07H and #08H. The wells were turned to production at initial rates of 1,100, 1,500, 1,270 and 1,360 Bopd, respectively. EOG has 100 percent working interest in these Leonard 'A' zone wells that had associated NGL production of 200, 195, 235 and 235 Bpd and 1.1, 1.1, 1.3 and 1.3 MMcfd of natural gas, respectively.  The most recent successful pilot in Loving County is a three-well pattern, also in the Leonard 'A' zone. The Gemini #1H, #2H and #3H were drilled 300 feet apart and turned to production at initial rates of 1,120, 1,530 and 1,290 Bopd, respectively. These Leonard 'A' zone wells, in which EOG has 48 percent, 100 percent and 48 percent working interest, respectively, had associated NGL production of 185, 220 and 200 Bpd and 1.0, 1.2 and 1.1 MMcfd of natural gas, respectively.  In addition, EOG has completed two strong Leonard 'B' zone wells, one drilled as part of a two-well pattern offsetting an 'A' zone well. In Lea County, the Falcon 25 Fed #2H began sales from the 'B' zone at 920 Bopd with 120 Bpd of NGLs and 660 thousand cubic feet per day (Mcfd) of natural gas. In Loving County, the Mercury State #2H also was completed in the 'B' zone, flowing 1,630 Bopd with 230 Bpd of NGLs and 1.3 MMcfd of natural gas. Offsetting the Mercury State #2H by 250 feet, the Mercury State #1H was completed in the 'A' zone at 1,700 Bopd with 360 Bpd of NGLs and 2.0 MMcfd of natural gas. EOG has 100 percent working interest in these three wells. Positive initial results from the Falcon 25 Fed #2H and the Mercury State #2H wells support additional downspacing tests of the Leonard 'B' zone.  Using early production results from the tightly spaced Gemini 'A' zone wells and the Mercury State wells drilled across zones 'A' and 'B', EOG is evaluating various downspacing options that could significantly increase the number of drilling locations across its Leonard acreage.  "The Second Bone Spring Sand is yet another example of how EOG organically increases its high return crude oil inventory. Its potential, combined with downspacing results from the Leonard Shale play, positions EOG for steady long-term exploration and development activity in the Delaware Basin. We have the momentum to unlock additional high rate-of-return growth from EOG's oil-rich acreage for years to come," Thomas said.  In Reeves County, Texas, EOG reported a number of successful wells from its 134,000 net acre position in the Delaware Basin Wolfcamp play. The State Apache 57 #1103H, #1104H, #1105H and #1107H were completed at initial rates ranging from 590 to 1,600 Bopd with 200 to 460 Bpd of NGLs and 1.3 to 3.0 MMcfd of natural gas. Also in Reeves County, the State Harrison Ranch 56 #302H and #303H began sales at 660 and 665 Bopd with 275 and 450 Bpd of NGLs and 1.8 and 2.9 MMcfd of natural gas, respectively. EOG has 100 percent working interest in these six wells. EOG continues to test various well spacing patterns and zones on its Delaware Basin Wolfcamp acreage.  Eagle Ford  EOG's South Texas Eagle Ford crude oil play again contributed significantly to total company second quarter crude oil production growth. Associated NGL and natural gas production also contributed to total company growth. Maintaining a robust drilling and completion program across its Eagle Ford acreage, EOG is further improving individual well results by modifying completion techniques and reducing drilling days.  In Karnes County, the McCoy Unit #1H and #2H began production at 5,290 and 5,415 Bopd with 475 and 415 Bpd of NGLs and 2.7 and 2.4 MMcfd of natural gas, respectively. EOG has 90 percent working interest in these wells. The Wolf Unit #6H, #7H, #8H and #9H, in which EOG has 100 percent working interest, began sales at rates ranging from 3,160 to 3,600 Bopd with 310 to 390 Bpd of NGLs and 1.8 to 2.3 MMcfd of natural gas.  Northeast of Karnes in DeWitt County, the Justiss Unit #11H, #12H and #13H had initial production rates of 4,000, 3,900 and 4,130 Bopd with 690, 650 and 750 Bpd of NGLs and 4.0, 3.8 and 4.3 MMcfd of natural gas, respectively. EOG has 100 percent working interest in these three wells.  In Gonzales County, EOG recorded a number of wells with robust initial production including the Boothe Unit #11H and #16H, which had rates of 4,570 and 3,245 Bopd with 580 and 500 Bpd of NGLs and 3.4 and 2.9 MMcfd of natural gas, respectively. The Zimmerman Unit #14H began sales at 3,800 Bopd with 350 Bpd of NGLs and 2.0 MMcfd of natural gas. EOG has 100 percent working interest in these three wells.  Southwest of Gonzales in LaSalle County, the Naylor Jones Unit 127 #1H, #2H and #3H had initial production rates ranging from 2,200 to 2,500 Bopd with 220 to 250 Bpd of NGLs and 1.3 to 1.5 MMcfd of natural gas. EOG has 100 percent, 100 percent and 75 percent working interest in these wells, respectively.  North Dakota Bakken  In the North Dakota Bakken, EOG is concentrating activity on its Core acreage in Mountrail County. Well productivity is improving markedly due to continued refinements in completion designs. Three Core wells, the Wayzetta 43-0311H, 44-0311H and 45-0311H, were completed during the second quarter at 1,505, 2,410 and 2,690 Bopd, respectively. EOG has 75 percent working interest in these wells. EOG continues to drill and evaluate production data from various spacing patterns in order to maximize the value of this asset. In addition, EOG plans to drill several Three Forks wells to test various benches of this play on both its Core and Antelope Extension acreage during the remainder of 2014.  Wyoming  In the Wyoming DJ Basin, EOG is simultaneously developing the stacked Codell and Niobrara formations from multi-well pad locations in Laramie County, Wyoming. During the second quarter, the Jubilee 586-1705H, the second well completed from a multi-well pad, began production from the Codell at an initial rate of 1,145 Bopd with 445 Mcfd of rich natural gas. EOG has 75 percent working interest in the well. A number of wells are targeted to begin production in August through year-end. EOG plans to test well spacing patterns and various completion techniques in both the Codell and Niobrara formations. EOG has increased its acreage position in the Codell by 13,000 net acres to 85,000 net acres.  In the Wyoming Powder River Basin, EOG is maintaining a steady drilling program with denser pad drilling operations. In the Parkman play, the Mary's Draw 404-21H and 468-34H, which were drilled from the same pad, had initial production rates of 1,045 and 980 Bopd with 305 and 330 Mcfd of rich natural gas, respectively. EOG has 99 percent and 100 percent working interest in the wells, respectively.  "To summarize our position, EOG is extending its lead as the largest crude oil producer in the onshore U.S. Lower 48. We continue to grow the size and quality of our drilling inventory by generating excellent new plays internally and increasing the drilling potential of our existing plays," Thomas said. "EOG is leading its peers in terms of barrels per day of crude oil growth, while our forecast ROE and ROCE metrics exceed the average of all upstream energy sectors, including the majors."  Crude Oil and Natural Gas Hedging Activity  For the period August 1 through December 31, 2014, EOG has crude oil financial price swap contracts in place for 194,000 Bopd at a weighted average price of $96.19 per barrel. For the calendar year 2015, EOG has no crude oil financial derivative contracts in place, excluding unexercised options.  For the period September 1 through December 31, 2014, EOG has natural gas financial price swap contracts in place for 330,000 million British thermal units per day (MMBtud) at a weighted average price of $4.55 per million British thermal units (MMBtu), excluding unexercised options.  For the period January 1 through December 31, 2015, EOG has natural gas financial price swap contracts in place for 175,000 MMBtud at a weighted average price of $4.51 per MMBtu, excluding unexercised options. (For a comprehensive summary of crude oil and natural gas derivative contracts, please refer to the attached tables.)   Cash Flow and Capital Structure  At June 30, 2014, EOG's total debt outstanding was $5,910 million for a debt-to-total capitalization ratio of 26 percent. Taking into account cash on the balance sheet of $1.2 billion at June 30, EOG's net debt was $4,680 million for a net debt-to-total capitalization ratio of 22 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).)  EOG is targeting 29 percent total company crude oil production growth in 2014. Total company production is expected to rise 14 percent, an increase from the previous 12 percent estimate. Capital expenditures are anticipated to range from $8.1 billion to $8.3 billion for 2014, unchanged from prior estimates.  Conference Call August 6, 2014  EOG's second quarter 2014 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Wednesday, August 6, 2014. To listen, log on to www.eogresources.com. The webcast will be archived on EOG's website through August 20, 2014.  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:    othe timing and extent of changes in prices for, and demand for, crude oil     and condensate, natural gas liquids, natural gas and related commodities;   othe extent to which EOG is successful in its efforts to acquire or     discover additional reserves;   othe extent to which EOG is successful in its efforts to economically     develop its acreage in, produce reserves and achieve anticipated     production levels from, and optimize reserve recovery from, its existing     and future crude oil and natural gas exploration and development projects;   othe extent to which EOG is successful in its efforts to market its crude     oil, natural gas and related commodity production;   othe availability, proximity and capacity of, and costs associated with,     appropriate gathering, processing, compression, transportation and     refining facilities;   othe 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;   othe impact of, and changes in, government policies, laws and regulations,     including tax laws and regulations; environmental, health and safety laws     and regulations relating to air emissions, disposal of produced water,     drilling fluids and other wastes, hydraulic fracturing and access to and     use of water; laws and regulations imposing conditions or restrictions on     drilling and completion operations and on the transportation of crude oil     and natural gas; laws and regulations with respect to derivatives and     hedging activities; and laws and regulations with respect to the import     and export of crude oil, natural gas and related commodities;   oEOG'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;   othe extent to which EOG's third-party-operated crude oil and natural gas     properties are operated successfully and economically;   ocompetition in the oil and gas exploration and production industry for     employees and other personnel, facilities, equipment, materials and     services;   othe availability and cost of employees and other personnel, facilities,     equipment, materials (such as water) and services;   othe accuracy of reserve estimates, which by their nature involve the     exercise of professional judgment and may therefore be imprecise;   oweather, including its impact on crude oil and natural gas demand, and     weather-related delays in drilling and in the installation and operation     (by EOG or third parties) of production, gathering, processing, refining,     compression and transportation facilities;   othe 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;   oEOG'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;   othe extent and effect of any hedging activities engaged in by EOG;   othe 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;   opolitical conditions and developments around the world (such as political     instability and armed conflict), including in the areas in which EOG     operates;   othe use of competing energy sources and the development of alternative     energy sources;   othe extent to which EOG incurs uninsured losses and liabilities or losses     and liabilities in excess of its insurance coverage;   oacts of war and terrorism and responses to these acts;   ophysical, electronic and cyber security breaches; and   othe other factors described under Item 1A, "Risk Factors", on pages 17     through 26 of EOG's Annual Report on Form 10-K for the fiscal year ended     December 31, 2013 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, 2013, 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.  For Further Information Contact: Investors                                   Maire A. Baldwin                                   (713) 651-6364                                   Kimberly A. Matthews                                   (713) 571-4676                                   David J. Streit                                   (713) 571-4902                                   Media                                   K Leonard                                   (713) 571-3870    EOG RESOURCES, INC. FINANCIAL REPORT (Unaudited; in millions, except per share data)                            Three Months Ended        Six Months Ended                            June 30,                  June 30,                            2014         2013         2014         2013 Net Operating Revenues     $ 4,187.6    $ 3,840.2    $ 8,271.2    $ 7,196.7 Net Income                $ 706.4      $ 659.7      $ 1,367.3    $ 1,154.4 Net Income Per Share  Basic                     $ 1.30       $ 1.22       $ 2.52       $ 2.14  Diluted                   $ 1.29       $ 1.21       $ 2.49       $ 2.12 Average Number of Common Shares  Basic                       543.1        540.0        542.7        539.3  Diluted                     548.7        545.5        548.0        544.9 SUMMARY INCOME STATEMENTS  (Unaudited; in thousands, except per share data)                            Three Months Ended        Six Months Ended                            June 30,                  June 30,                            2014         2013         2014         2013 Net Operating Revenues  Crude Oil and Condensate  $ 2,618,975  $ 2,012,999  $ 5,016,077  $ 3,794,832  Natural Gas Liquids         247,973      178,457      494,208      347,986  Natural Gas                 509,091      462,602      1,065,784    873,481  Gains (Losses) on  Mark-to-Market Commodity    (229,270)    191,490      (385,006)    86,534  Derivative Contracts  Gathering, Processing and   1,027,795    959,413      2,043,206    1,882,370  Marketing  Gains on Asset              3,856        13,153       15,354       177,386  Dispositions, Net  Other, Net                  9,136        22,071       21,604       34,110                 Total        4,187,556    3,840,185    8,271,227    7,196,699 Operating Expenses  Lease and Well              346,458      268,888      667,292      517,888  Transportation Costs        240,579      224,491      483,816      408,748  Gathering and Processing    32,470       25,897       66,394       50,401  Costs  Exploration Costs           42,208       47,323       90,266       91,539  Dry Hole Costs              5,558        35,750       13,906       39,712  Impairments                39,035       37,967       152,396      91,515  Marketing Costs             1,043,515    965,490      2,049,819    1,870,139  Depreciation, Depletion     996,602      910,531      1,943,093    1,756,919  and Amortization  General and                 90,932       80,607       173,794      158,592  Administrative  Taxes Other Than Income     205,469      151,197      401,442      286,128                 Total        3,042,826    2,748,141    6,042,218    5,271,581 Operating Income            1,144,730    1,092,044    2,229,009    1,925,118 Other Income (Expense),      7,950        4,833        4,612        (5,301) Net Income Before Interest       1,152,680    1,096,877    2,233,621    1,919,817 Expense and Income Taxes Interest Expense, Net        51,867       61,647       102,019      123,568 Income Before Income Taxes   1,100,813    1,035,230    2,131,602    1,796,249 Income Tax Provision         394,460      375,538      764,321      641,832 Net Income                $ 706,353    $ 659,692    $ 1,367,281  $ 1,154,417 Dividends Declared per     $ 0.1250     $ 0.0938     $ 0.2500     $ 0.1875 Common Share  Note: All share and per-share amounts shown have been restated to reflect the announced 2-for-1 stock split effective March 31, 2014.    EOG RESOURCES, INC. OPERATING HIGHLIGHTS (Unaudited)                                         Three Months Ended  Six Months Ended                                         June 30,            June 30,                                         2014      2013      2014      2013 Wellhead Volumes and Prices Crude Oil and Condensate Volumes (MBbld) ^(A)        United States                      274.6     206.5     266.4     192.4        Canada                             5.6       6.4       6.4       7.1        Trinidad                           1.0       1.4       1.0       1.3        Other International ^(B)           0.1       0.1       0.1       0.1                      Total                281.3     214.4     273.9     200.9 Average Crude Oil and Condensate Prices ($/Bbl) ^(C)        United States                    $ 102.66  $ 103.73  $ 101.66  $ 105.04        Canada                             94.66     89.66     92.05     87.29        Trinidad                           94.25     86.96     92.09     90.36        Other International ^(B)           91.27     92.28     89.10     93.56                      Composite            102.47    103.19    101.40    104.31 Natural Gas Liquids Volumes (MBbld) ^(A)        United States                      78.5      63.7      74.7      61.2        Canada                             0.7       1.0       0.7       0.9                      Total                79.2      64.7      75.4      62.1 Average Natural Gas Liquids Prices ($/Bbl) ^(C)        United States                    $ 34.35   $ 30.19   $ 36.12   $ 30.87        Canada                             40.90     39.49     44.15     40.62                      Composite            34.41     30.33     36.20     31.02 Natural Gas Volumes (MMcfd) ^(A)        United States                      925       928       910       931        Canada                             67        79        65        79        Trinidad                           380       346       384       349        Other International ^(B)           11        8         9         8                      Total                1,383     1,361     1,368     1,367 Average Natural Gas Prices ($/Mcf) ^(C)        United States                    $ 4.14    $ 3.73    $ 4.54    $ 3.41        Canada                             4.72      3.17      4.71      3.21        Trinidad                           3.69      3.82      3.66      3.86        Other International ^(B)           4.39      6.81      5.04      6.78                      Composite            4.04      3.73      4.31      3.53 Crude Oil Equivalent Volumes (MBoed) ^(D)        United States                     507.2     424.8     492.7     408.8        Canada                             17.4      20.6      18.1      21.2        Trinidad                           64.5      59.0      65.0      59.4        Other International ^(B)           1.9       1.5       1.5       1.4                      Total                591.0     505.9     577.3     490.8 Total MMBoe ^(D)                          53.8      46.0      104.5     88.8  (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.      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 (D)  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,                                                 2014            2013 ASSETS Current Assets  Cash and Cash Equivalents                      $ 1,230,140     $ 1,318,209  Accounts Receivable, Net                         1,902,248       1,658,853  Inventories                                      667,108         563,268  Assets from Price Risk Management Activities     -               8,260  Income Taxes Receivable                          24,527          4,797  Deferred Income Taxes                            485,507         244,606  Other                                            415,215         274,022               Total                               4,724,745       4,072,015 Property, Plant and Equipment  Oil and Gas Properties (Successful Efforts       46,270,734      42,821,803  Method)  Other Property, Plant and Equipment              3,374,278       2,967,085               Total Property, Plant and           49,645,012      45,788,888               Equipment  Less: Accumulated Depreciation, Depletion and   (21,449,581)    (19,640,052)  Amortization               Total Property, Plant and           28,195,431      26,148,836               Equipment, Net Other Assets                                      382,258         353,387 Total Assets                                    $ 33,302,434    $ 30,574,238 LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities  Accounts Payable                               $ 2,661,473     $ 2,254,418  Accrued Taxes Payable                            228,569         159,365  Dividends Payable                                67,865          50,795  Liabilities from Price Risk Management           338,318         127,542  Activities  Current Portion of Long-Term Debt                6,579           6,579  Other                                            234,683         263,017               Total                               3,537,487       2,861,716 Long-Term Debt                                    5,903,099       5,906,642 Other Liabilities                                 991,450         865,067 Deferred Income Taxes                             6,162,010       5,522,354 Commitments and Contingencies Stockholders' Equity  Common Stock, $0.01 Par, 640,000,000 Shares  Authorized and 547,951,875    Shares Issued at June 30, 2014 and    546,378,440 Shares Issued at December 31,      205,482         202,732    2013  Additional Paid in Capital                       2,728,482       2,646,879  Accumulated Other Comprehensive Income          426,588         415,834  Retained Earnings                                13,398,901      12,168,277  Common Stock Held in Treasury, 515,079 Shares  at June 30, 2014 and    206,830 Shares at December 31, 2013           (51,065)        (15,263)               Total Stockholders' Equity          16,708,388      15,418,459 Total Liabilities and Stockholders' Equity      $ 33,302,434    $ 30,574,238  Note: All share amounts shown have been restated to reflect the announced 2-for-1 stock split effective March 31, 2014.    EOG RESOURCES, INC. SUMMARY STATEMENTS OF CASH FLOWS (Unaudited; in thousands)                                                   Six Months Ended                                                   June 30,                                                   2014           2013 Cash Flows from Operating Activities Reconciliation of Net Income to Net Cash Provided by Operating Activities:  Net Income                                      $ 1,367,281    $ 1,154,417  Items Not Requiring (Providing) Cash    Depreciation, Depletion and Amortization         1,943,093      1,756,919    Impairments                                     152,396        91,515    Stock-Based Compensation Expenses                65,144         57,724    Deferred Income Taxes                            479,109        488,632    Gains on Asset Dispositions, Net                 (15,354)       (177,386)    Other, Net                                       984            8,747  Dry Hole Costs                                     13,906         39,712  Mark-to-Market Commodity Derivative Contracts    Total Losses (Gains)                             385,006        (86,534)    Net Cash (Payments for) Received from            (120,900)      135,959    Settlements of Commodity Derivative Contracts  Excess Tax Benefits from Stock-Based               (63,759)       (21,869)  Compensation  Other, Net                                         7,223          7,759  Changes in Components of Working Capital and  Other Assets and Liabilities    Accounts Receivable                              (249,336)      (164,809)    Inventories                                      (109,756)      22,085    Accounts Payable                                 347,539        141,369    Accrued Taxes Payable                            115,668        24,816    Other Assets                                     (141,453)      (92,305)    Other Liabilities                                57,101         (51,400)  Changes in Components of Working Capital  Associated with Investing and   Financing Activities                              (31,644)       (19,639) Net Cash Provided by Operating Activities           4,202,248      3,315,712 Investing Cash Flows  Additions to Oil and Gas Properties                (3,724,486)    (3,250,091)  Additions to Other Property, Plant and Equipment   (402,972)      (183,516)  Proceeds from Sales of Assets                      74,512         579,941  Changes in Restricted Cash                         (91,238)       (52,322)  Changes in Components of Working Capital           31,620         19,358  Associated with Investing Activities Net Cash Used in Investing Activities               (4,112,564)    (2,886,630) Financing Cash Flows  Long-Term Debt Borrowings                          496,220        -  Long-Term Debt Repayments                          (500,000)      -  Settlement of Foreign Currency Swap                (31,573)       -  Dividends Paid                                     (119,684)      (97,006)  Excess Tax Benefits from Stock-Based               63,759         21,869  Compensation  Treasury Stock Purchased                           (89,524)       (21,094)  Proceeds from Stock Options Exercised and          10,433         20,773  Employee Stock Purchase Plan  Debt Issuance Costs                                (895)          -  Repayment of Capital Lease Obligation              (2,958)        (2,866)  Other, Net                                         24             281 Net Cash Used in Financing Activities               (174,198)      (78,043) Effect of Exchange Rate Changes on Cash             (3,555)        542 (Decrease) Increase in Cash and Cash Equivalents    (88,069)       351,581 Cash and Cash Equivalents at Beginning of Period    1,318,209      876,435 Cash and Cash Equivalents at End of Period        $ 1,230,140    $ 1,228,016    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, 2014 and 2013 reported Net Income (GAAP) to reflect actual net cash (payments for) received from settlements of commodity derivative contracts by eliminating the unrealized mark-to-market losses (gains) from these transactions, to eliminate the net gains on asset dispositions in North America in 2014 and 2013 and to add back impairment charges related to certain of EOG's non-core North American assets in 2014 and 2013. 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,                              2014        2013         2014         2013 Reported Net Income (GAAP)   $ 706,353   $ 659,692    $ 1,367,281  $ 1,154,417 Mark-to-Market (MTM) Commodity Derivative Contracts Impact   Total Losses (Gains)         229,270     (191,490)    385,006      (86,534)   Net Cash (Payments for)   Received from Settlements    (86,867)    68,909       (120,900)    135,959   of Commodity Derivative   Contracts               Subtotal         142,403     (122,581)    264,106      49,425   After-Tax MTM Impact         91,359      (78,482)     169,437      31,645 Less: Net Gains on Asset       (1,663)     (9,382)      (9,040)      (124,375) Dispositions, Net of Tax Add: Impairments of Certain North American Assets, Net     -           2,003        36,058       2,003 of Tax Adjusted Net Income          $ 796,049   $ 573,831    $ 1,563,736  $ 1,063,690 (Non-GAAP) Net Income Per Share (GAAP)   Basic                      $ 1.30      $ 1.22       $ 2.52       $ 2.14   Diluted                    $ 1.29      $ 1.21       $ 2.49       $ 2.12 Adjusted Net Income Per Share (Non-GAAP)   Basic                      $ 1.47      $ 1.06       $ 2.88       $ 1.97   Diluted                    $ 1.45      $ 1.05       $ 2.85       $ 1.95 Adjusted Net Income Per Diluted Share (Non-GAAP) -     38%                      46% Percentage Increase Average Number of Common Shares (GAAP)   Basic                        543,099     540,033      542,675      539,330   Diluted                      548,676     545,477      548,046      544,946  Note: All share and per-share amounts shown have been restated to reflect the announced 2-for-1 stock split effective March 31, 2014.    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, 2014 and 2013 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,                             2014         2013         2014         2013 Net Cash Provided by        $ 1,934,575  $ 1,890,777  $ 4,202,248  $ 3,315,712 Operating Activities (GAAP) Adjustments:  Exploration Costs  (excluding Stock-Based       36,659       40,930       76,783       77,575  Compensation Expenses)  Excess Tax Benefits from     36,337       10,196       63,759       21,869  Stock-Based Compensation  Changes in Components of  Working Capital and Other  Assets and Liabilities           Accounts            105,019      (71,948)     249,336      164,809           Receivable           Inventories         40,808       (37,143)     109,756      (22,085)           Accounts Payable    14,271       44,696       (347,539)    (141,369)           Accrued Taxes       24,133       (15,812)     (115,668)    (24,816)           Payable           Other Assets        128,917      45,112       141,453      92,305           Other Liabilities   (86,270)     (1,533)      (57,101)     51,400  Changes in Components of  Working Capital Associated   (36,639)     (37,782)     31,644       19,639  with Investing and  Financing Activities Discretionary Cash Flow     $ 2,197,810  $ 1,867,493  $ 4,354,671  $ 3,555,039 (Non-GAAP) Discretionary Cash Flow (Non-GAAP) - Percentage       18%                       22% Increase    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, 2014 and 2013 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 (payments for) received from settlements of commodity derivative contracts 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 2014 and 2013. 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,                             2014         2013         2014         2013 Income Before Interest Expense and Income Taxes    $ 1,152,680  $ 1,096,877  $ 2,233,621  $ 1,919,817 (GAAP) Adjustments:   Depreciation, Depletion     996,602      910,531      1,943,093    1,756,919   and Amortization   Exploration Costs           42,208       47,323       90,266       91,539   Dry Hole Costs              5,558        35,750       13,906       39,712   Impairments                39,035       37,967       152,396      91,515       EBITDAX (Non-GAAP)      2,236,083    2,128,448    4,433,282    3,899,502   Total Losses (Gains) on MTM   Commodity Derivative        229,270      (191,490)    385,006      (86,534)   Contracts   Net Cash (Payments for)   Received from Settlements   (86,867)     68,909       (120,900)    135,959   of Commodity Derivative   Contracts   Net Gains on Asset          (3,856)      (13,153)     (15,354)     (177,386)   Dispositions Adjusted EBITDAX (Non-GAAP) $ 2,374,630  $ 1,992,714  $ 4,682,034  $ 3,771,541 Adjusted EBITDAX (Non-GAAP)   19%                       24% - Percentage Increase    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         At                                                        June 30,   December 31,                                                        2014       2013 Total Stockholders' Equity - (a)                       $ 16,708   $   15,418 Current and Long-Term Debt (GAAP) - (b)                  5,910        5,913 Less: Cash                                              (1,230)      (1,318) Net Debt (Non-GAAP) - (c)                                4,680        4,595 Total Capitalization (GAAP) - (a) + (b)                $ 22,618   $   21,331 Total Capitalization (Non-GAAP) - (a) + (c)            $ 21,388   $   20,013 Debt-to-Total Capitalization (GAAP) - (b) / [(a) +       26%          28% (b)] Net Debt-to-Total Capitalization (Non-GAAP) - (c) /      22%          23% [(a) + (c)]    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 5, 2014, 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) 2014 January 2014 (closed)                         156,000  $      96.30 February 2014 (closed)                        171,000  96.35 March 1, 2014 through June 30, 2014 (closed)  181,000  96.55 July 2014 (closed)                            202,000  96.34 August 2014                                   202,000  96.34 September 1, 2014 through December 31, 2014   192,000  96.15 2015 ^(1)                                     -        $         -      EOG has entered into crude oil derivative contracts which give     counterparties the option to extend certain current derivative contracts     for additional six-month periods. Options covering a notional volume of (1) 69,000 Bbld are exercisable on or about December 31, 2014. If the     counterparties exercise all such options, the notional volume of EOG's     existing crude oil derivative contracts will increase by 69,000 Bbld at an     average price of $95.20 per barrel for each month during the period     January 1, 2015 through June 30, 2015.  NATURAL GAS DERIVATIVE CONTRACTS                                                         Weighted                                              Volume     Average Price                                              (MMBtud)  ($/MMBtu) 2014 ^(2) January 2014 (closed)                        230,000    $       4.51 February 2014 (closed)                       710,000    4.57 March 2014 (closed)                          810,000    4.60 April 2014 (closed)                          465,000    4.52 May 2014 (closed)                            685,000    4.55 June 2014 (closed)                           515,000    4.52 July 2014 (closed)                           340,000    4.55 August 2014 (closed)                         330,000    4.55 September 1, 2014 through December 31, 2014  330,000    4.55 2015 ^(3) January 1, 2015 through December 31, 2015    175,000    $       4.51      EOG has entered into natural gas derivative contracts which give     counterparties the option of entering into derivative contracts at future     dates. All such options are exercisable monthly up until the settlement (2) 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 480,000 MMBtud at an average price of $4.63 per     MMBtu for each month during the period September 1, 2014 through December     31, 2014.     EOG has entered into natural gas derivative contracts which give     counterparties the option of entering into derivative contracts at future     dates. All such options are exercisable monthly up until the settlement (3) 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 175,000 MMBtud at an average price of $4.51 per     MMBtu for each month during the period January 1, 2015 through December     31, 2015.  $/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. THIRD QUARTER AND FULL YEAR 2014 FORECAST AND BENCHMARK COMMODITY PRICING     (a)Third Quarter and Full Year 2014 Forecast The forecast items for the third quarter and full year 2014 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)                                             3Q 2014            Full Year 2014 Daily Production    Crude Oil and Condensate Volumes    (MBbld)        United States                        278.0 -   292.0    268.0 -   288.0        Canada                               4.5   -   5.5      5.5   -   6.5        Trinidad                             0.6   -   0.8      0.7   -   1.0        Other International                  0.0   -   0.0      0.0   -   0.0          Total                              283.1 -   298.3    274.2 -   295.5    Natural Gas Liquids Volumes (MBbld)        United States                        75.5  -   79.5     73.8  -   78.3        Canada                               0.4   -   0.6      0.5   -   0.7          Total                              75.9  -   80.1     74.3  -   79.0    Natural Gas Volumes (MMcfd)        United States                        877   -   901      886   -   905        Canada                               58    -   62       61    -   64        Trinidad                             327   -   345      358   -   372        Other International                  8     -   10       8     -   10          Total                              1,270 -   1,318    1,313 -   1,351    Crude Oil Equivalent Volumes (MBoed)        United States                        499.7 -   521.7    489.5 -   517.1        Canada                               14.6  -   16.4     16.2  -   17.9        Trinidad                             55.1  -   58.3     60.4  -   63.0        Other International                  1.3   -   1.7      1.3   -   1.7          Total                              570.7 -   598.1    567.4 -   599.7 Operating Costs    Unit Costs ($/Boe)        Lease and Well                     $ 6.40  - $ 6.70   $ 6.40  - $ 6.60        Transportation Costs               $ 4.79  - $ 4.98   $ 4.66  - $ 4.86        Depreciation, Depletion and        $ 18.35 - $ 19.05  $ 18.30 - $ 19.00        Amortization Expenses ($MM)    Exploration, Dry Hole and Impairment   $ 130   - $ 150    $ 500   - $ 550    General and Administrative             $ 101   - $ 112    $ 380   - $ 390    Gathering and Processing              $ 38    - $ 44     $ 130   - $ 150    Capitalized Interest                   $ 14    - $ 16     $ 55    - $ 65    Net Interest                           $ 48    - $ 52     $ 194   - $ 214 Taxes Other Than Income (% of Wellhead      6.1%  -   6.5%     6.0%  -   6.5% Revenue) Income Taxes    Effective Rate                          35%   -   40%      35%   -   40%    Current Taxes ($MM)                    $ 120   - $ 135    $ 540   - $ 560 Capital Expenditures ($MM) - FY 2014 (Excluding Acquisitions)    Exploration and Development, Excluding                    $ 6,450 - $ 6,550    Facilities    Exploration and Development Facilities                    $ 880   - $ 920    Gathering, Processing and Other                           $ 770   - $ 810 Pricing - (Refer to Benchmark Commodity Pricing in text)    Crude Oil and Condensate ($/Bbl)        Differentials          United States - (above) below    $ 0.70  - $ 1.70   $ 0.01  - $ 0.51          WTI          Canada - (above) below WTI       $ 10.50 - $ 12.50  $ 8.00  - $ 12.00          Trinidad - (above) below WTI     $ 9.00  - $ 11.00  $ 7.20  - $ 11.40    Natural Gas Liquids        Realizations as % of WTI          United States                      30%   -   37%      32%   -   37%          Canada                             32%   -   38%      38%   -   43%    Natural Gas ($/Mcf)        Differentials          United States - (above) below    $ 0.30  - $ 0.70   $ 0.15  - $ 0.50          NYMEX Henry Hub          Canada - (above) below NYMEX     $ 0.10  - $ 0.50   $ 0.00  - $ 0.25          Henry Hub        Realizations          Trinidad                         $ 2.85  - $ 3.35   $ 3.20  - $ 3.55          Other International              $ 3.75  - $ 5.75   $ 3.80  - $ 5.90  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    SOURCE EOG Resources, Inc.  Website: http://www.eogresources.com  
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