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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