EOG Resources Reports Third Quarter 2013 Results; Again Increases 2013 Production Growth Targets for Crude Oil and Total

    EOG Resources Reports Third Quarter 2013 Results; Again Increases 2013
          Production Growth Targets for Crude Oil and Total Company

PR Newswire

HOUSTON, Nov. 6, 2013

HOUSTON, Nov. 6, 2013 /PRNewswire/ --

  oDelivers 39 Percent Year-Over-Year Total Company Crude Oil Production
    Growth
  oRaises 2013 Full-Year Crude Oil Production Goal to 39 Percent from 35
    Percent
  oIncreases 2013 Total Company Production Growth Target to 9 Percent from
    7.5 Percent
  oReports Record Western Eagle Ford Oil Well
  oContinues to Achieve Stellar Economic Results from the Eagle Ford,
    Bakken/Three Forks and Leonard Plays
  oAnnounces Mark G. Papa Will Continue as Director Following Year-end
    Retirement

EOG Resources, Inc.(NYSE: EOG)(EOG) today reported third quarter 2013 net
income of $462.5 million, or $1.69 per share. This compares to third quarter
2012 net income of $355.5 million, or $1.31 per share.

Consistent with some analysts' practice of matching realizations to settlement
months and making certain other adjustments in order to exclude one-time
items, adjusted non-GAAP net income for the third quarter 2013 was $634.3
million, or $2.32 per share. Adjusted non-GAAP net income for the third
quarter 2012 was $468.7 million, or $1.73 per share. The results for the third
quarter 2013 included net gains on asset dispositions of $5.2 million, net of
tax ($0.02 per share), impairments of $2.4 million, net of tax ($0.01 per
share) related to the sale of certain non-core North American assets and a
previously disclosed non-cash net loss of $293.4 million ($187.8 million after
tax, or $0.69 per share) on the mark-to-market of financial commodity
contracts. During the third quarter, the net cash outflow related to financial
commodity contracts was $20.6 million ($13.2 million after tax, or $0.05 per
share). (Please refer to the attached tables for the reconciliation of
adjusted non-GAAP net income to GAAP net income.)

EOG reported strong, sustained financial growth for the first nine months of
2013. Earnings per share increased 49 percent, discretionary cash flow
increased 29 percent and adjusted EBITDAX rose 27 percent, compared to the
same 2012 period. (Please refer to the attached tables for the reconciliation
of non-GAAP discretionary cash flow to net cash provided by operating
activities (GAAP) and adjusted EBITDAX (non-GAAP) to income before interest
expense and income taxes (GAAP).)

Operational Highlights

EOG increased its U.S. crude oil and condensate production by 41 percent and
total company crude oil and condensate production by 39 percent in the third
quarter of 2013 over the same prior year period. Total company liquids
production – crude oil, condensate and natural gas liquids (NGLs) – rose 33
percent.

EOG is increasing its full year crude oil and condensate production growth
target for the second time in 2013 to 39 percent from 35 percent, following
three quarters of extraordinary results. Total natural gas liquids production
is expected to increase 17 percent, compared to the previous 14 percent
target, and total natural gas production is projected to decline 11 percent,
consistent with EOG's longstanding strategy in North America. Overall, EOG is
targeting 9 percent total company production growth in 2013, versus its
previous goal of 7.5 percent. In addition, EOG is again lowering certain unit
cost estimates, based on results to date.

"EOG is consistently making the best oil wells in the best two oil plays in
North America, the Eagle Ford and Bakken/Three Forks," said President and
Chief Executive Officer William R. "Bill" Thomas.

South Texas Eagle Ford

In the first three quarters of 2013, EOG built momentum in its western Eagle
Ford acreage by increasing drilling activity from six to nine rigs. Through
completion advancements, initial production rates have increased more than 20
percent since the first quarter 2013. This enhanced productivity across
Atascosa, La Salle and McMullen Counties mirrors the performance level EOG
already has reached in its eastern play activities.

During the third quarter, EOG reported its top well to date from its western
Eagle Ford acreage. The Kaiser Junior Unit #1H began initial production at
2,815 barrels of oil per day (Bopd) with 160 barrels per day (Bpd) of NGLs and
940 thousand cubic feet per day (Mcfd) of natural gas in Atascosa County.
Other third quarter western wells include the Janet Unit #1H and Nelson Zella
Unit #1H and #2H in La Salle County, which were completed with initial rates
of 2,430, 1,960 and 2,810 Bopd with 175, 120 and 100 Bpd of NGLs and 1,000,
700 and 590 Mcfd of natural gas, respectively. In McMullen County, the River
Lowe Ranch #4H, #5H, #6H, #7H, #8H and #9H began sales at initial rates
ranging from 1,970 to 2,115 Bopd with 125 to 135 Bpd of NGLs and 720 to 780
Mcfd of natural gas. EOG has 100 percent working interest in these 10 wells.

Highlights from EOG's eastern Eagle Ford acreage include four DeWitt County
wells. The Justiss Unit #1H, #2H and #3H were completed at 3,885, 3,560 and
3,940 Bopd with 520, 605 and 670 Bpd of NGLs and 3.0, 3.5 and 3.9 million
cubic feet per day (MMcfd) of natural gas, respectively. Also in DeWitt
County, the Vinklarek Unit #1H was completed at 4,510 Bopd with 715 Bpd of
NGLs and 4.2 MMcfd of natural gas. In Gonzales County, the Baker-Deforest Unit
#5H, #6H and #7H came on-line at 3,200, 3,560 and 4,115 Bopd with 420, 490 and
535 Bpd of NGLs and 2.5, 2.9 and 3.1 MMcfd of natural gas, respectively. EOG
has 100 percent working interest in these seven Eagle Ford wells.

"Because we now are achieving high growth, high rate-of-return results from
our western acreage, we have effectively raised the bar for all of EOG's Eagle
Ford acreage," Thomas said.

With a 25-rig drilling program, EOG is increasing the total net wells planned
across its Eagle Ford acreage in 2013 from 440 to 460.

North Dakota Bakken/Three Forks

EOG's exceptional Eagle Ford results were replicated in the North Dakota
Bakken/Three Forks through improvements in initial production rates and
efficient execution of its drilling program.

In the Bakken Core, EOG brought a number of Mountrail County wells to sales.
The Fertile 50-0509H, in which EOG has 100 percent working interest, began
producing crude oil at 2,315 Bopd with 1.0 MMcfd of rich natural gas. The Van
Hook 126-2523H and 130-2526H came on-line at peak rates of 2,235 and 1,910
Bopd with 1.1 and 0.9 MMcfd of rich natural gas, respectively. EOG has 67 and
91 percent working interest in these wells, respectively. The Wayzetta
155-2636H, 137-2226H and 150-1509H had initial crude oil rates ranging from
2,060 to 2,500 Bpd with 1.0 to 1.2 MMcfd of rich natural gas. EOG has 72
percent, 65 percent and 63 percent working interest in these wells,
respectively.

On its Antelope Extension acreage in McKenzie County, EOG highlighted three
wells from the first bench of the Three Forks formation. The Bear Den
100-2017H and 101-2019H began producing at rates of 2,100 and 1,235 Bopd with
2.0 and 1.2 MMcfd of rich natural gas, respectively. The third well, the Bear
Den 23-2019H had an initial production rate of 1,665 Bopd with 1.6 MMcfd of
rich natural gas. EOG has 91 percent working interest in these three wells.

EOG remains focused on the highly economic Bakken Core and Antelope Extension
areas. Based on continuous gains in results from both the Bakken and Three
Forks formations, plans are to increase the level of drilling activity in
2014.

"Every quarter, EOG's technical understanding of the Eagle Ford and
Bakken/Three Forks expands, as we further modify completion techniques that
boost overall well productivity and economics," Thomas said.

Delaware Basin Leonard

During the third quarter, EOG completed three wells in the Delaware Basin
Leonard play in Lea County, New Mexico. The Endurance 36 State Com #3H and #4H
and Brown Bear 36 State #1H began production at 735, 875 and 720 Bopd,
respectively. The wells, in which EOG has 100 percent working interest, also
produced 85, 105 and 120 Bpd of NGLs with 460, 570 and 665 Mcfd of natural
gas, respectively. Plans are to increase drilling activity in the Leonard in
2014.

"With premier positions in the Eagle Ford and Bakken/Three Forks, EOG
continues to set new crude oil production records. Through our tenacious
attention to the completion process, we are enhancing the productivity and
profitability of these world class assets to ultimately realize a greater
volume of the potential oil in the ground," said Mark G. Papa, Executive
Chairman of the Board. "We also are pleased with the strides EOG is making in
the Delaware Basin Leonard."

Hedging Activity

In recent weeks, EOG increased the amount of crude oil hedges in place for the
remainder of 2013 and 2014. For the period November 1 through December 31,
2013, EOG has crude oil financial price swap contracts in place for 126,000
Bopd at a weighted average price of $98.80 per barrel, excluding unexercised
options.

For the period January 1 through June 30, 2014, EOG has crude oil financial
price swap contracts in place for approximately 123,000 Bopd at a weighted
average price of $96.44 per barrel, excluding unexercised options. For the
period July 1 through December 31, 2014, EOG has crude oil financial price
swap contracts in place for 9,000 Bopd at an average price of $95.30 per
barrel, excluding unexercised options.

EOG also has hedges in place for natural gas volumes. For December 2013, EOG
has natural gas financial price swap contracts in place for 150,000 million
British thermal units per day (MMBtud) at a weighted average price of $4.79
per million British thermal units (MMBtu), excluding unexercised options. For
the full year 2014, EOG has natural gas financial price swap contracts in
place for 170,000 MMBtud at a weighted average price of $4.54 per MMBtu,
excluding unexercised options. (For a comprehensive summary of crude oil and
natural gas derivative contracts, please refer to the attached tables.) 

Capital Structure

For the first nine months of 2013, EOG's cash flows from operating activities
and proceeds from asset sales exceeded total capital expenditures.

To date, EOG has closed on approximately $620 million of asset sales,
exceeding its stated goal for the year. Proceeds from asset sales for the full
year 2013 are expected to be approximately $750 million. At September 30,
2013, EOG's total debt outstanding was $6,313 million for a debt-to-total
capitalization ratio of 30 percent. Taking into account cash on the balance
sheet of $1,319 million at the end of the third quarter, EOG's net debt was
$4,994 million for a net debt-to-total capitalization ratio of 25 percent.
(Please refer to the attached tables for the reconciliation of net debt
(non-GAAP) to current and long-term debt (GAAP) and the reconciliation of net
debt-to-total capitalization ratio (non-GAAP) to debt-to-total capitalization
ratio (GAAP).)

Board of Directors

As previously announced, in addition to his current role as Chief Executive
Officer, Thomas will succeed Papa as Chairman of the Board on January 1, 2014.
Papa will retire both as Executive Chairman of the Board and as an employee at
year-end, although he will continue to serve as an EOG director.

Conference Call November 7, 2013

EOG's third quarter 2013 results conference call will be available via live
audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Thursday,
November 7, 2013. To listen, log on to www.eogresources.com. The webcast will
be archived on EOG's website through November 21, 2013.

EOG Resources, Inc. is one of the largest independent (non-integrated) crude
oil and natural gas companies in the United States with proved reserves in the
United States, Canada, Trinidad, the United Kingdom and China. EOG Resources,
Inc. is listed on the New York Stock Exchange and is traded under the ticker
symbol "EOG."

This press release includes forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements, other than
statements of historical facts, including, among others, statements and
projections regarding EOG's future financial position, operations,
performance, business strategy, returns, budgets, reserves, levels of
production and costs, statements regarding future commodity prices and
statements regarding the plans and objectives of EOG's management for future
operations, are forward-looking statements. EOG typically uses words such as
"expect," "anticipate," "estimate," "project," "strategy," "intend," "plan,"
"target," "goal," "may," "will," "should" and "believe" or the negative of
those terms or other variations or comparable terminology to identify its
forward-looking statements. In particular, statements, express or implied,
concerning EOG's future operating results and returns or EOG's ability to
replace or increase reserves, increase production, generate income or cash
flows or pay dividends are forward-looking statements. Forward-looking
statements are not guarantees of performance. Although EOG believes the
expectations reflected in its forward-looking statements are reasonable and
are based on reasonable assumptions, no assurance can be given that these
assumptions are accurate or that any of these expectations will be achieved
(in full or at all) or will prove to have been correct. Moreover, EOG's
forward-looking statements may be affected by known, unknown or currently
unforeseen risks, events or circumstances that may be outside EOG's control.
Important factors that could cause EOG's actual results to differ materially
from the expectations reflected in EOG's forward-looking statements include,
among others:

  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 can optimize reserve recovery and economically
    develop its plays utilizing horizontal and vertical drilling, advanced
    completion technologies and hydraulic fracturing;
  othe 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;
  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,
    gathering, processing, compression and transportation 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 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;
  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, equipment, materials and services and,
    related thereto, the availability and cost of employees and other
    personnel, equipment, materials 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
    of production, gathering, processing, 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 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.

For Further Information Contact: Investors
                                 Maire A. Baldwin
                                 (713) 651-6EOG (651-6364)
                                 Kimberly A. Matthews
                                 (713) 571-4676
                                 Media
                                 K Leonard
                                 (713) 571-3870



EOG RESOURCES, INC.
FINANCIAL REPORT
(Unaudited; in millions, except per share data)
                           Three Months Ended        Nine Months Ended
                           September 30,             September 30,
                           2013         2012         2013          2012
Net Operating Revenues     $ 3,541.4    $ 2,954.9    $ 10,738.1    $ 8,670.8
Net Income                $ 462.5      $ 355.5      $ 1,616.9     $ 1,075.3
Net Income Per Share
 Basic                     $ 1.71       $ 1.33       $ 5.99        $ 4.03
 Diluted                   $ 1.69       $ 1.31       $ 5.93        $ 3.98
Average Number of Common
Shares
 Basic                       270.5        267.9        269.9         267.1
 Diluted                     273.6        271.0        272.9         270.3
SUMMARY INCOME STATEMENTS
(Unaudited; in thousands, except per share data)
                           Three Months Ended        Nine Months Ended
                           September 30,             September 30,
                           2013         2012         2013          2012
Net Operating Revenues
 Crude Oil and Condensate  $ 2,337,742  $ 1,512,168  $ 6,132,574   $ 4,198,753
 Natural Gas Liquids         208,190      170,351      556,176       518,684
 Natural Gas                 396,123      426,728      1,269,604     1,153,433
 (Losses) Gains on
 Mark-to-Market Commodity    (293,387)    4,671        (206,853)     327,328
 Derivative Contracts
 Gathering, Processing and   872,699      764,385      2,755,069     2,193,290
 Marketing
 Gains on Asset              8,183        67,376       185,569       248,134
 Dispositions, Net
 Other, Net                  11,846       9,176        45,956        31,203
             Total           3,541,396    2,954,855    10,738,095    8,670,825
Operating Expenses
 Lease and Well              299,169      253,452      817,057       765,703
 Transportation Costs        219,790      164,407      628,538       431,642
 Gathering and Processing    31,121       26,223       81,522        72,403
 Costs
 Exploration Costs           39,429       45,953       130,968       136,909
 Dry Hole Costs              19,548       1,924        59,260        13,005
 Impairments                85,917       62,875       177,432       250,239
 Marketing Costs             876,761      755,457      2,746,900     2,155,043
 Depreciation, Depletion     928,800      825,851      2,685,719     2,383,359
 and Amortization
 General and                 98,654       92,870       257,246       244,866
 Administrative
 Taxes Other Than Income     172,438      120,096      458,566       359,798
             Total           2,771,627    2,349,108    8,043,208     6,812,967
Operating Income             769,769      605,747      2,694,887     1,857,858
Other Income, Net            11,168       7,596        5,867         22,902
Income Before Interest       780,937      613,343      2,700,754     1,880,760
Expense and Income Taxes
Interest Expense, Net        59,382       53,154       182,950       154,198
Income Before Income Taxes   721,555      560,189      2,517,804     1,726,562
Income Tax Provision         259,057      204,698      900,889       651,284
Net Income                 $ 462,498    $ 355,491    $ 1,616,915   $ 1,075,278
Dividends Declared per     $ 0.1875     $ 0.17       $ 0.5625      $ 0.51
Common Share





EOG RESOURCES, INC.
OPERATING HIGHLIGHTS
(Unaudited)
                                         Three Months Ended  Nine Months Ended
                                         September 30,       September 30,
                                         2013       2012     2013      2012
Wellhead Volumes and Prices
Crude Oil and Condensate Volumes (MBbld)
^(A)
       United States                        227.6     161.3    204.3     147.6
       Canada                               6.1       6.7      6.7       6.9
       Trinidad                             1.2       1.2      1.3       1.7
       Other International ^(B)             0.1       0.1      0.1       0.1
                     Total                  235.0     169.3    212.4     156.3
Average Crude Oil and Condensate Prices
($/Bbl) ^(C)
       United States                     $  108.56  $ 97.64  $ 106.36  $ 98.26
       Canada                               97.90     86.09    90.53     86.25
       Trinidad                             94.96     90.84    91.80     93.85
       Other International ^(B)             81.30     83.59    88.90     90.34
                     Composite              108.20    97.13    105.76    97.68
Natural Gas Liquids Volumes (MBbld) ^(A)
       United States                        68.2      58.1     63.5      54.3
       Canada                               0.9       0.9      0.9       0.9
                     Total                  69.1      59.0     64.4      55.2
Average Natural Gas Liquids Prices
($/Bbl) ^(C)
       United States                     $  32.75   $ 30.95  $ 31.55   $ 35.43
       Canada                               32.24     41.09    37.83     44.61
                     Composite              32.74     31.11    31.64     35.58
Natural Gas Volumes (MMcfd) ^(A)
       United States                        899       1,022    920       1,051
       Canada                               76        94       78        98
       Trinidad                             352       387      350       393
       Other International ^(B)             7         9        8         10
                     Total                  1,334     1,512    1,356     1,552
Average Natural Gas Prices ($/Mcf) ^(C)
       United States                     $  3.19    $ 2.61   $ 3.33    $ 2.39
       Canada                               2.61      2.39     3.01      2.35
       Trinidad                             3.41      4.38     3.71      3.60
       Other International ^(B)             6.12      5.67     6.58      5.70
                     Composite              3.23      3.07     3.43      2.71
Crude Oil Equivalent Volumes (MBoed)
^(D)
       United States                       445.7     389.7    421.2     377.2
       Canada                               19.7      23.2     20.7      24.1
       Trinidad                             59.8      65.7     59.5      67.1
       Other International ^(B)             1.2       1.7      1.4       1.8
                     Total                  526.4     480.3    502.8     470.2
Total MMBoe ^(D)                            48.4      44.2     137.3     128.8

(A)  Thousand barrels per day or million cubic feet per day, as applicable.
(B)  Other International includes EOG's United Kingdom, China and Argentina
     operations.
(C) Dollars per barrel or per thousand cubic feet, as applicable. Excludes
     the impact of financial commodity derivative instruments.
     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)
                                                September 30,   December 31,
                                                2013            2012
ASSETS
Current Assets
 Cash and Cash Equivalents                      $ 1,318,817     $ 876,435
 Accounts Receivable, Net                         1,849,517       1,656,618
 Inventories                                      566,004         683,187
 Assets from Price Risk Management Activities     44,484          166,135
 Income Taxes Receivable                          42,296          29,163
 Deferred Income Taxes                            127,658         -
 Other                                            243,191         178,346
                Total                             4,191,967       3,589,884
Property, Plant and Equipment
 Oil and Gas Properties (Successful Efforts       41,887,901      38,126,298
 Method)
 Other Property, Plant and Equipment              2,954,085       2,740,619
                Total Property, Plant and         44,841,986      40,866,917
                Equipment
 Less: Accumulated Depreciation, Depletion and   (19,242,795)    (17,529,236)
 Amortization
                Total Property, Plant and         25,599,191      23,337,681
                Equipment, Net
Other Assets                                      356,112         409,013
Total Assets                                    $ 30,147,270    $ 27,336,578
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
 Accounts Payable                               $ 2,247,714     $ 2,078,948
 Accrued Taxes Payable                            200,477         162,083
 Dividends Payable                                50,753          45,802
 Liabilities from Price Risk Management           174,648         7,617
 Activities
 Deferred Income Taxes                            -               22,838
 Current Portion of Long-Term Debt                406,579         406,579
 Other                                            267,162         200,191
                Total                             3,347,333       2,924,058
Long-Term Debt                                    5,906,494       5,905,602
Other Liabilities                                 846,780         894,758
Deferred Income Taxes                             5,185,083       4,327,396
Commitments and Contingencies
Stockholders' Equity
 Common Stock, $0.01 Par, 640,000,000 Shares
 Authorized and 273,061,895 Shares Issued at
 September 30, 2013 and 271,958,495 Shares        202,731         202,720
 Issued at December 31, 2012
 Additional Paid in Capital                       2,614,898       2,500,340
 Accumulated Other Comprehensive Income          425,283         439,895
 Retained Earnings                                11,639,302      10,175,631
 Common Stock Held in Treasury, 142,467 Shares
 at September 30, 2013 and326,264 Shares at      (20,634)        (33,822)
 December 31, 2012
                Total Stockholders' Equity        14,861,580      13,284,764
Total Liabilities and Stockholders' Equity      $ 30,147,270    $ 27,336,578

EOG RESOURCES, INC.
SUMMARY STATEMENTS OF CASH FLOWS
(Unaudited; in thousands)
                                                  Nine Months Ended
                                                  September 30,
                                                  2013           2012
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided
by Operating Activities:
 Net Income                                      $ 1,616,915    $ 1,075,278
 Items Not Requiring (Providing) Cash
          Depreciation, Depletion and               2,685,719      2,383,359
          Amortization
          Impairments                              177,432        250,239
          Stock-Based Compensation Expenses         103,171        101,337
          Deferred Income Taxes                     657,686        385,878
          Gains on Asset Dispositions, Net          (185,569)      (248,134)
          Other, Net                                460            (10,266)
 Dry Hole Costs                                     59,260         13,005
 Mark-to-Market Commodity Derivative Contracts
          Total Losses (Gains)                      206,853        (327,328)
          Realized Gains                            115,323        555,946
 Excess Tax Benefits from Stock-Based               (50,230)       (49,426)
 Compensation
 Other, Net                                         16,222         12,675
 Changes in Components of Working Capital and
 Other Assets and Liabilities
          Accounts Receivable                       (213,746)      (112,174)
          Inventories                               61,147         (154,766)
          Accounts Payable                          145,199        83,682
          Accrued Taxes Payable                     73,197         42,791
          Other Assets                              (78,799)       (120,085)
          Other Liabilities                         10,889         39,871
 Changes in Components of Working Capital
 Associated with Investing and Financing            (72,945)       87,708
 Activities
Net Cash Provided by Operating Activities           5,328,184      4,009,590
Investing Cash Flows
 Additions to Oil and Gas Properties                (5,084,335)    (5,326,884)
 Additions to Other Property, Plant and Equipment   (271,136)      (477,351)
 Proceeds from Sales of Assets                      587,273        1,213,550
 Changes in Restricted Cash                         (68,061)       -
 Changes in Components of Working Capital           72,916         (87,654)
 Associated with Investing Activities
Net Cash Used in Investing Activities               (4,763,343)    (4,678,339)
Financing Cash Flows
 Long-Term Debt Borrowings                          -              1,234,138
 Dividends Paid                                     (147,731)      (134,412)
 Excess Tax Benefits from Stock-Based               50,230         49,426
 Compensation
 Treasury Stock Purchased                           (55,562)       (44,799)
 Proceeds from Stock Options Exercised and          30,080         59,714
 Employee Stock Purchase Plan
 Debt Issuance Costs                                -              (1,771)
 Repayment of Capital Lease Obligation              (4,318)        (1,407)
 Other, Net                                         29             (54)
Net Cash (Used in) Provided by Financing            (127,272)      1,160,835
Activities
Effect of Exchange Rate Changes on Cash             4,813          4,811
Increase in Cash and Cash Equivalents               442,382        496,897
Cash and Cash Equivalents at Beginning of Period    876,435        615,726
Cash and Cash Equivalents at End of Period        $ 1,318,817    $ 1,112,623

EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF ADJUSTED NET INCOME (NON-GAAP)
TO NET INCOME (GAAP)
(Unaudited; in thousands, except per share data)
The following chart adjusts the three-month and nine-month periods ended
September 30, 2013 and 2012 reported Net Income (GAAP) to reflect actual
net cash realized from financial commodity price transactions by
eliminating the unrealized mark-to-market losses (gains) from these
transactions, to eliminate the net gains on asset dispositions in North
America in 2013 and 2012 and to add back impairment charges related to
certain of EOG's non-core North American assets in 2013 and 2012. EOG
believes this presentation may be useful to investors who follow the
practice of some industry analysts who adjust reported company earnings to
match realizations to production settlement months and make certain other
adjustments to exclude non-recurring items. EOG management uses this
information for comparative purposes within the industry.
                     Three Months Ended     Nine Months Ended
                     September 30,           September 30,
                     2013        2012        2013              2012
Reported Net Income  $ 462,498   $ 355,491   $ 1,616,915       $ 1,075,278
(GAAP)
Mark-to-Market (MTM)
 Commodity Derivative
 Contracts Impact
    Total Losses       293,387     (4,671)     206,853           (327,328)
    (Gains)
    Realized           (20,636)    249,166     115,323           555,946
    (Losses) Gains
            Subtotal   272,751     244,495     322,176           228,618
    After-Tax MTM      174,628     156,537     206,273           146,372
    Impact
Less: Net Gains on
Asset Dispositions,    (5,241)     (43,354)    (129,616)         (161,652)
Net of Tax
Add: Impairments of
Certain North          2,422       -           4,425             38,575
American Assets, Net
of Tax
Adjusted Net Income  $ 634,307   $ 468,674   $ 1,697,997       $ 1,098,573
(Non-GAAP)
Net Income Per Share
 (GAAP)
    Basic            $ 1.71      $ 1.33      $ 5.99            $ 4.03
    Diluted          $ 1.69      $ 1.31      $ 5.93      (a) $ 3.98      (b)
Percentage Increase -                          49%
[(a) - (b)] / (b)
Adjusted Net Income Per
 Share (Non-GAAP)
    Basic            $ 2.35      $ 1.75      $ 6.29            $ 4.11
    Diluted          $ 2.32      $ 1.73      $ 6.22            $ 4.06
Average Number of
 Common Shares
    Basic              270,471     267,941     269,934           267,136
    Diluted            273,576     270,982     272,856           270,328

EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF DISCRETIONARY CASH FLOW (NON-GAAP)
TO NET CASH PROVIDED BY OPERATING ACTIVITIES (GAAP)
(Unaudited; in thousands)
The following chart reconciles the three-month and nine-month periods
ended September 30, 2013 and 2012 Net Cash Provided by Operating
Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes
this presentation may be useful to investors who follow the practice of
some industry analysts who adjust Net Cash Provided by Operating
Activities for Exploration Costs (excluding Stock-Based Compensation
Expenses), Excess Tax Benefits from Stock-Based Compensation, Changes in
Components of Working Capital and Other Assets and Liabilities, and
Changes in Components of Working Capital Associated with Investing and
Financing Activities. EOG management uses this information for
comparative purposes within the industry.
                 Three Months Ended        Nine Months Ended
                 September 30,             September 30,
                 2013         2012         2013              2012
Net Cash
Provided by
Operating        $ 2,012,472  $ 1,436,372  $ 5,328,184       $ 4,009,590
Activities
(GAAP)
Adjustments
  Exploration
  Costs
  (excluding       32,755       38,485       110,330           116,563
  Stock-Based
  Compensation
  Expenses)
  Excess Tax
  Benefits from    28,361       27,311       50,230            49,426
  Stock-Based
  Compensation
  Changes in
  Components of
  Working
  Capital and
  Other Assets
  and
  Liabilities
     Accounts      48,937       227,593      213,746           112,174
     Receivable
     Inventories   (39,062)     51,190       (61,147)          154,766
     Accounts      (3,830)      92,673       (145,199)         (83,682)
     Payable
     Accrued
     Taxes         (48,381)     (28,428)     (73,197)          (42,791)
     Payable
     Other         (13,506)     17,782       78,799            120,085
     Assets
     Other         (62,289)     (67,226)     (10,889)          (39,871)
     Liabilities
  Changes in
  Components of
  Working
  Capital
  Associated
  with Investing
  and
    Financing      53,306       (185,161)    72,945            (87,708)
    Activities
Discretionary
Cash Flow        $ 2,008,763  $ 1,610,591  $ 5,563,802 (a) $ 4,308,552 (b)
(Non-GAAP)
Percentage
Increase - [(a)                              29%
- (b)] / (b)

EOG RESOURCES, INC.
CRUDE OIL AND NATURAL GAS FINANCIAL
COMMODITY DERIVATIVE CONTRACTS
EOG hasentered into additional crude oil derivative contracts since filing
its Current Report on Form 8-K dated October 10, 2013. In addition, during
September 2013, EOG settled certain crude oil derivative contracts covering
notional volumes of 5,000 Bbld for the period July 1, 2014 through December
31, 2014. Presented below is a comprehensive summary of EOG's crude oil and
natural gas derivative contracts at November 6, 2013, with notional volumes
expressed in Bbld and MMBtud and prices expressed in $/Bbl and $/MMBtu. EOG
accounts for financial commodity derivative contracts using the mark-to-market
accounting method.
CRUDE OIL DERIVATIVE CONTRACTS
                                                                 Weighted
                                                  Volume        Average Price
                                                  (Bbld)        ($/Bbl)
    2013^(1)
    January 2013 (closed)                         101,000        $     
                                                                 99.29
    February 1, 2013 through April 30, 2013       109,000        99.17
    (closed)
    May 1, 2013 through June 30, 2013 (closed)    101,000        99.29
    July 2013 (closed)                            111,000        98.25
    August 1, 2013 through October 31, 2013       126,000        98.80
    (closed)
    November 1, 2013 through December 31, 2013    126,000        98.80
    2014^(2)
    January 1, 2014 through March 31, 2014        128,000        $     
                                                                 96.44
    April 1, 2014 through June 30, 2014           118,000        96.43
    July 1, 2014 through December 31, 2014        9,000          95.30
    EOG has entered into crude oil derivative contracts which give
    counterparties the option to extend certain current derivative contracts
    for an additional six-month period. Options covering a notional volume of
(1) 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.
    EOG has entered into crude oil derivative contracts which give
    counterparties the option to extend certain current derivative contracts
    for additional six-month and nine-month periods. Options covering a
    notional volume of 10,000 Bbld are exercisable on or about March 31,
    2014. If the counterparties exercise all such options, the notional
    volume of EOG's existing crude oil derivative contracts will increase by
    10,000 Bbld at an average price of $96.60 per barrel for each month during
    the period April 1, 2014 through December 31, 2014. Options covering a
    notional volume of 103,000 Bbld are exercisable on or about June 30,
    2014. If the counterparties exercise all such options, the notional
(2) volume of EOG's existing crude oil derivative contracts will increase by
    103,000 Bbld at an average price of $96.60 per barrel for each month
    during the period July 1, 2014 through December 31, 2014. Options
    covering a notional volume of 9,000 Bbld are exercisable on or about
    December 31, 2014. In addition, in connection with the crude oil
    derivative contracts settled in September 2013 covering a notional volume
    of 5,000 Bbld, counterparties retain the option to enter into derivative
    contracts on December 31, 2014. If the counterparties exercise all such
    options, the notional volume of EOG's existing crude oil derivative
    contracts will increase by 14,000 Bbld at an average price of $95.35 per
    barrel for each month during the period January 1, 2015 through June
    30,2015.
NATURAL GAS DERIVATIVE CONTRACTS
                                                                 Weighted
                                                  Volume         Average Price
                                                  (MMBtud)      ($/MMBtu)
    2013^(3)
    January 1, 2013 through April 30, 2013        150,000        $      
    (closed)                                                     4.79
    May 1, 2013 through October 31, 2013 (closed) 200,000        4.72
    November 2013 (closed)                        150,000        4.79
    December 2013                                 150,000        4.79
    2014^(4)
    January 1, 2014 through December 31, 2014     170,000        $      
                                                                 4.54
    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
(3) of each monthly contract. For December 2013, if the counterparties
    exercise all such options, the notional volume of EOG's existing natural
    gas derivative contracts will increase by 150,000 MMBtud at an average
    price of $4.79 per MMBtu.
    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
(4) entering into derivative contracts at future dates. All such options are
    exercisable monthly up until the settlement date of each monthly
    contract. If the counterparties exercise all such options, the notional
    volume of EOG's existing natural gas derivative contracts will increase by
    320,000 MMBtud at an average price of $4.66 per MMBtu for each month
    during the period January 1, 2014 through December 31, 2014.
    $/Bbl                 Dollars per barrel
    $/MMBtu               Dollars per million British thermal
                          units
    Bbld                  Barrels per day
    MMBtu                 Million British thermal units
    MMBtud                Million British thermal units per day



EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF ADJUSTED EARNINGS BEFORE INTEREST
EXPENSE,
INCOME TAXES, DEPRECIATION, DEPLETION AND AMORTIZATION, EXPLORATION
COSTS,
DRY HOLE COSTS, IMPAIRMENTS AND ADDITIONAL ITEMS (ADJUSTED EBITDAX)
(NON-GAAP) TO INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES (GAAP)
(Unaudited; in thousands)
The following chart adjusts the three-month and nine-month periods ended
September 30, 2013 and 2012 reported Income Before Interest Expense and
Income Taxes (GAAP) to Earnings Before Interest Expense, Income Taxes,
Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole
Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such
amount to reflect actual net cash realized from financial commodity
derivative transactions by eliminating the unrealized mark-to-market
(MTM) losses (gains) from these transactions and to eliminate the net
gains on asset dispositions in North America in 2013 and 2012. EOG
believes this presentation may be useful to investors who follow the
practice of some industry analysts who adjust reported Income Before
Interest Expense and Income Taxes (GAAP) to add back Depreciation,
Depletion and Amortization, Exploration Costs, Dry Hole Costs and
Impairments and further adjust such amount to match realizations to
production settlement months and make certain other adjustments to
exclude non-recurring items. EOG management uses this information for
comparative purposes within the industry.
                 Three Months Ended        Nine Months Ended
                 September 30,             September 30,
                 2013         2012         2013              2012
Income Before
Interest Expense $ 780,937    $ 613,343    $ 2,700,754       $ 1,880,760
and Income Taxes
(GAAP)
Adjustments
  Depreciation,
  Depletion and    928,800      825,851      2,685,719         2,383,359
  Amortization
  Exploration      39,429       45,953       130,968           136,909
  Costs
  Dry Hole Costs   19,548       1,924        59,260            13,005
  Impairments     85,917       62,875       177,432           250,239
     EBITDAX       1,854,631    1,549,946    5,754,133         4,664,272
     (Non-GAAP)
  Total Losses
  (Gains) on MTM
  Commodity        293,387      (4,671)      206,853           (327,328)
  Derivative
  Contracts
  Realized
  (Losses) Gains
  on MTM Commodity (20,636)     249,166      115,323           555,946
  Derivative
  Contracts
  Net Gains on
  Asset            (8,183)      (67,376)     (185,569)         (248,134)
  Dispositions
     Adjusted
     EBITDAX     $ 2,119,199  $ 1,727,065  $ 5,890,740 (a) $ 4,644,756 (b)
     (Non-GAAP)
Percentage Increase - [(a) -                 27%
(b)] / (b)

EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF NET DEBT (NON-GAAP) AND TOTAL
CAPITALIZATION (NON-GAAP) AS USED IN THE CALCULATION OF
THE NET DEBT-TO-TOTAL CAPITALIZATION RATIO (NON-GAAP) TO
CURRENT AND LONG-TERM DEBT (GAAP) AND TOTAL CAPITALIZATION (GAAP)
(Unaudited; in millions, except ratio data)
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt
(Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP),
as used in the Net Debt-to-Total Capitalization ratio calculation. A portion
of the cash is associated with international subsidiaries; tax considerations
may impact debt paydown. EOG believes this presentation may be useful to
investors who follow the practice of some industry analysts who utilize Net
Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total
Capitalization ratio calculation. EOG management uses this information for
comparative purposes within the industry.

                                                                At
                                                                September 30,
                                                                2013
Total Stockholders' Equity - (a)                              $ 14,862
Current and Long-Term Debt - (b)                                6,313
Less: Cash                                                     (1,319)
Net Debt (Non-GAAP) - (c)                                       4,994
Total Capitalization (GAAP) - (a) + (b)                       $ 21,175
Total Capitalization (Non-GAAP) - (a) + (c)                   $ 19,856
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]         30%
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) +      25%
(c)]

EOG RESOURCES, INC.
 FOURTH QUARTER AND FULL YEAR 2013 FORECAST AND BENCHMARK COMMODITY PRICING
    (a) Fourth Quarter and Full
    Year 2013 Forecast
The forecast items for the fourth quarter and full year 2013 set forth below for
EOG Resources, Inc. (EOG) are based on current available information and
expectations as of the date of the accompanying press release. EOG undertakes no
obligation, other than as required by applicable law, to update or revise this
forecast, whether as a result of new information, subsequent events, anticipated
or unanticipated circumstances or otherwise. This forecast, which should be read
in conjunction with the accompanying press release and EOG's related Current
Report on Form 8-K filing, replaces and supersedes any previously issued guidance
or forecast.
    (b) Benchmark Commodity
    Pricing
EOG bases United States, Canada and Trinidad crude oil and condensate price
differentials upon the West Texas Intermediate crude oil price at Cushing,
Oklahoma, using the simple average of the NYMEX settlement prices for each
trading day within the applicable calendar month.
EOG bases United States and Canada natural gas price differentials upon the
natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX
settlement prices for the last three trading days of the applicable month.
                                         ESTIMATED
                                         RANGES
                                         (Unaudited)
                        4Q 2013                        Full Year 2013
Daily Production
    Crude Oil and
    Condensate
    Volumes (MBbld)
       United States    227.0  -   233.0               210.0           -   212.0
       Canada           6.0    -   8.0                 6.0             -   7.0
       Trinidad         0.9    -   1.1                 1.1             -   1.3
       Other            0.0    -   0.0                 0.0             -   0.0
       International
        Total           233.9  -   242.1               217.1           -   220.3
    Natural Gas
    Liquids Volumes
    (MBbld)
       United States    64.0   -   70.0                64.0            -   65.0
       Canada           0.7    -   1.1                 0.9             -   1.0
        Total           64.7   -   71.1                64.9            -   66.0
    Natural Gas
    Volumes (MMcfd)
       United States    855    -   880                 904             -   910
       Canada           62     -   82                  74              -   79
       Trinidad         335    -   375                 346             -   356
       Other            5      -   11                  7               -   8
       International
        Total           1,257  -   1,348               1,331           -   1,353
    Crude Oil
    Equivalent
    Volumes (MBoed)
       United States    433.5  -   449.7               424.7           -   428.7
       Canada           17.0   -   22.8                19.2            -   21.2
       Trinidad         56.7   -   63.6                58.8            -   60.6
       Other            0.8    -   1.8                 1.2             -   1.3
       International
        Total           508.0  -   537.9               503.9           -   511.8
Operating Costs
    Unit Costs
    ($/Boe)
       Lease and Well $ 6.20   - $ 6.40              $ 6.02            - $ 6.07
       Transportation $ 4.50   - $ 4.70              $ 4.55            - $ 4.61
       Costs
       Depreciation,
       Depletion and  $ 19.40  - $ 19.80             $ 19.52           - $ 19.63
       Amortization
Expenses ($MM)
    Exploration, Dry
    Hole and          $ 140.0  - $ 190.0             $ 500.0           - $ 550.0
    Impairment
    General and       $ 92.0   - $ 97.0              $ 350.0           - $ 355.0
    Administrative
    Gathering and     $ 29.0   - $ 33.0              $ 110.0           - $ 115.0
    Processing
    Capitalized       $ 12.0   - $ 15.0              $ 46.0            - $ 50.0
    Interest
    Net Interest      $ 50.0   - $ 54.0              $ 233.0           - $ 237.0
Taxes Other Than
Income (% of Wellhead   5.9%   -   6.3%                5.8%            -   5.9%
Revenue)
Income Taxes
    Effective Rate     35%    -   40%                 35%             -   38%
    Current Taxes     $ 105    - $ 120               $ 345             - $ 365
    ($MM)
Capital Expenditures ($MM) -
FY 2013 (Excluding
Acquisitions)
    Exploration and
    Development,                                       Approximately   $ 6,000
    Excluding
    Facilities
    Exploration and
    Development                                        Approximately   $ 800
    Facilities
    Gathering,
    Processing and                                     Approximately   $ 400
    Other
Pricing - (Refer to
Benchmark Commodity
Pricing in text)
    Crude Oil and
    Condensate
    ($/Bbl)
       Differentials
        United States
        - (above)     $ (0.35) - $ 1.15              $ (4.75)          - $ (6.25)
        below WTI
        Canada -
        (above) below $ 12.00  - $ 16.00             $ 9.00            - $ 10.00
        WTI
        Trinidad -
        (above) below $ 10.00  - $ 14.00             $ 7.00            - $ 8.00
        WTI
    Natural Gas
    Liquids
       Realizations
       as % of WTI
        United States   28%    -   32%                 31%             -   33%
        Canada          33%    -   37%                 37%             -   39%
    Natural Gas
    ($/Mcf)
       Differentials
        United States
        - (above)     $ 0.36   - $ 0.46              $ 0.35            - $ 0.39
        below NYMEX
        Henry Hub
        Canada -
        (above) below $ 0.40   - $ 0.50              $ 0.60            - $ 0.64
        NYMEX Henry
        Hub
       Realizations
        Trinidad      $ 2.75   - $ 3.25              $ 3.46            - $ 3.60
        Other         $ 4.50   - $ 5.00              $ 6.00            - $ 6.14
        International
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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