EOG Resources Reports Fourth Quarter and Full Year 2013 Results; Exceeds Crude Oil and Total Company Production Growth Targets;

EOG Resources Reports Fourth Quarter and Full Year 2013 Results; Exceeds Crude
  Oil and Total Company Production Growth Targets; Increases Potential Eagle
   Ford Reserves by 45 Percent; Raises Common Stock Dividend by 33 Percent

PR Newswire

HOUSTON, Feb. 24, 2014

HOUSTON, Feb. 24, 2014 /PRNewswire/ --

  oDelivers 40 Percent Year-Over-Year Total Company Crude Oil Growth and 9
    Percent Total Company Production Growth
  oReports Strong Year-Over-Year Increases in Adjusted Non-GAAP Net Income
    Per Share, Adjusted EBITDAX and Discretionary Cash Flow
  oRealizes 16 Percent ROE and 12 Percent ROCE
  oIncreases Eagle Ford Potential Reserves by 45 Percent to 3.2 BnBoe, Net
    After Royalty
  oAchieves 264 Percent Reserve Replacement at Excellent Finding Costs
  oRecords Successive Stellar Results from the Eagle Ford, Bakken and Leonard
    Plays
  oRaises Common Stock Dividend by 33 Percent – 15^th Increase in 15 Years –
    and Announces Two-For-One Stock Split
  oTargets 27 Percent Crude Oil Production and 11.5 Percent Total Company
    Growth for 2014

EOG Resources, Inc.(NYSE: EOG) (EOG) today reported full year 2013 net income
of $2,197 million, or $8.04 per share, as compared to $570 million, or $2.11
per share, for the full year 2012. For the fourth quarter 2013, EOG reported
net income of $580 million, or $2.12 per share. This compares to a fourth
quarter 2012 net loss of $505 million, or $1.88 per share.

Adjusted non-GAAP net income for the full year 2013 was $2,246 million, or
$8.22 per share, and for the full year 2012 was $1,536 million, or $5.67 per
share. Adjusted non-GAAP net income for the fourth quarter 2013 was $548
million, or $2.00 per share, and for the fourth quarter 2012 was $437 million,
or $1.61 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 fourth quarter 2013 excluded a
previously disclosed non-cash net gain of $40.5 million ($25.6 million after
tax, or $0.09 per share) on the mark-to-market of financial commodity
contracts and net gains on asset dispositions of $7.2 million, net of tax
($0.03 per share). During the fourth quarter 2013, the net cash inflow related
to financial commodity contracts was $1.0 million ($0.7 million after tax, or
$0.00 per share). (Please refer to the attached tables for the reconciliation
of adjusted non-GAAP net income to GAAP net income.)

EOG posted excellent financial metrics for 2013 with increases of 45 percent
in adjusted non-GAAP net income per share, 29 percent in discretionary cash
flow and 26 percent in adjusted EBITDAX, compared to 2012. Indicative of its
high rate-of-return and disciplined crude oil investment programs, EOG also
posted 16 percent ROE and 12 percent ROCE last year. (Please refer to the
attached tables for the reconciliation of adjusted non-GAAP net income to GAAP
net income, non-GAAP discretionary cash flow to net cash provided by operating
activities (GAAP), adjusted EBITDAX (non-GAAP) to income before interest
expense and income taxes (GAAP) and non-GAAP inputs to GAAP inputs as used in
the calculation of ROE and ROCE.)

Operational Highlights
In the fourth quarter 2013, EOG increased its U.S. crude oil and condensate
production by 53 percent, while total company crude oil and condensate
production rose by 50 percent over the same prior year period. Total company
liquids production – crude oil, condensate and natural gas liquids (NGLs) –
climbed 41 percent.

For the full year, total company crude oil and condensate production increased
40 percent year-over-year, driven by 42 percent growth in the U.S. Total
company liquids production increased 34 percent, while total natural gas
production decreased 11 percent. Overall total company production increased 9
percent compared to the prior year.

"2013 was an outstanding year for EOG," said William R. "Bill" Thomas,
Chairman and Chief Executive Officer. "Through virtually flawless execution of
our operations plan, we generated robust crude oil production growth
concurrent with strong ROE and ROCE ratios, while deleveraging the company.
Our 2013 financial metrics and year-end balance sheet reflect the value of
EOG's high quality crude oil investments."

South Texas Eagle Ford
The single largest source of EOG's extraordinary crude oil production growth
in 2013 was its mammoth South Texas Eagle Ford play. EOG increased well
productivity and initial production rates by augmenting its technical
knowledge of shale resources and the associated completion processes. Based on
these significant improvements, EOG increased the net potential recoverable
reserve estimate on its crude oil acreage by 45 percent to 3.2 billion barrels
of oil equivalent (BnBoe) from 2.2 BnBoe. While continuing to decrease spacing
between wells in certain areas, the average net reserves per well increased to
450 thousand barrels of crude oil equivalent (Mboe) from 400 Mboe.

Recent Eagle Ford wells include the Boothe Unit #3H, #4H and #17H in Gonzales
County, which began initial production during the fourth quarter at 2,630 to
3,375 barrels of crude oil per day (Bopd) with 365 to 520 barrels per day
(Bpd) of NGLs and 2.1 to 3.0 million cubic feet per day (MMcfd) of natural
gas. The Rudolph Unit #1H was turned to sales at 4,230 Bopd with 505 Bpd of
NGLs and 2.9 MMcfd of natural gas. The Nichols Unit #3H had an initial crude
oil production rate of 3,830 Bpd with 390 Bpd of NGLs and 2.3 MMcfd of natural
gas. In Karnes County, the Fleetwood Unit #1H and #2H began production at
3,630 and 3,435 Bopd with 345 and 350 Bpd of NGLs, respectively, and 2.0 MMcfd
of natural gas each. EOG has 100 percent working interest in these seven
wells.

The Wilde Trust Unit #1H, #2H and #3H, completed in the second quarter 2013,
had combined cumulative production of over 960,000 barrels of crude oil over a
200-day period. EOG holds a 100 percent working interest in these Gonzales
County wells.

Southwest of Gonzales and Karnes counties, the Naylor Jones Unit 42 #1H, #2H
and 60 #2H began production at rates ranging from 1,755 to 2,050 Bopd with 195
to 205 Bpd of NGLs and 1.1 to 1.2 MMcfd of natural gas in McMullen County. In
La Salle County, the Further Unit #1H and #2H had initial crude oil production
rates of 2,605 and 2,550 Bpd with 125 and 155 Bpd of NGLs and 725 and 900
thousand cubic feet per day (Mcfd) of natural gas, respectively. EOG has 100
percent working interest in these five wells.

"To put our Eagle Ford position in simple terms, our current reserve potential
is almost four times what we estimated four years ago when EOG discovered the
play. With approximately 7,200 total identified individual net well locations,
we still have about 6,000 net wells to drill across EOG's 120-mile crude oil
window," Thomas said. "Our in-house talent keeps finding ways to improve
development of this world-class shale asset where we hold a critical mass of
very desirable acreage. This gives EOG a lot of running room to produce better
and better results over a long period of time."

North Dakota Bakken
In North Dakota where EOG focused drilling activity on two key areas, the
Bakken Core and Antelope Extension, 2013 results surpassed expectations.
Ongoing improvements in drilling and completion techniques transformed what
was a steady development drilling program into a high rate-of-return crude oil
growth play. By confirming downspacing economics in the Bakken Core, EOG
ramped up its drilling plan from one to four wells per section, while
increasing the average recoverable resource per well.

In the Bakken Core in Mountrail County, the Wayzetta 30-3230H and 31-3230H, in
which EOG has 59 percent working interest, began production at 2,510 and 2,540
Bopd, respectively. The Wayzetta 35-1920H, in which EOG has a 60 percent
working interest, had an initial production rate of 2,240 Bopd with 1.2 MMcfd
of rich natural gas.

In the Antelope Extension, EOG drilled the Hawkeye 2-2501H in McKenzie County.
The well, in which EOG has 80 percent working interest, began production with
2,075 Bopd and 3.8 MMcfd of rich natural gas.

Delaware Basin Leonard
EOG's Permian Basin activity also was a solid contributor to its overall 2013
domestic crude oil production growth. Although EOG tested the prospectivity of
multiple target zones in its three distinct horizontal resource plays last
year, it initially concentrated on the Midland Basin Wolfcamp, followed by the
Delaware Basin Leonard and Wolfcamp. Based on compelling well results, EOG
shifted activity to the Delaware Basin Leonard during the second half of 2013.

In Lea County, New Mexico, two Leonard wells were drilled and completed in the
second half of 2013 and turned to sales early in 2014. The Vaca 24 Fed Com #5H
and #6H had initial crude oil production rates of 1,520 and 1,380 Bpd with 265
and 170 Bpd of NGLs and 1.5 and 0.9 MMcfd of natural gas, respectively. EOG
has 89 percent working interest in these wells.

Reserves
At December 31, 2013, EOG's total company net proved reserves of 2,119 million
barrels of crude oil equivalent (MMBoe) increased 17 percent over year-end
2012. Total company net proved developed reserves increased 19 percent to
1,127 MMBoe. Total U.S. net proved crude oil and condensate reserves increased
31 percent. Total proved liquids reserves increased 25 percent year-over-year,
comprising 60 percent of total company proved reserves at December 31, 2013.

In 2013:

  oTotal reserve replacement from all sources – the ratio of net reserve
    additions from drilling, acquisitions, total revisions and dispositions to
    total production – was 264 percent at a total reserve replacement cost of
    $13.42 per barrel of oil equivalent (Boe), based on exploration and
    development expenditures of $6,859 million, net of non-cash lease
    acquisition and asset retirement costs.
  oTotal liquids reserve replacement from all sources – the ratio of net
    reserve additions from drilling, acquisitions, total revisions and
    dispositions to total production – was 346 percent.
  oReserve replacement from drilling – the ratio of extensions, discoveries
    and other additions to total production – was 212 percent. Crude oil
    reserve replacement from drilling in the United States was 297 percent.
  oIn the United States, total reserve replacement from all sources, net of
    revisions and dispositions, was 307 percent at a reserve replacement cost
    of $12.57 per Boe based on exploration and development expenditures of
    $6,290 million, net of non-cash lease acquisition and asset retirement
    costs.

(Please refer to the attached tables for the calculation of total reserve
replacement, total reserve replacement costs, total liquids reserve
replacement, reserve replacement from drilling, U.S. total reserve replacement
and U.S. reserve replacement costs.)

For the 26^th consecutive year, internal reserve estimates were within 5
percent of those prepared by the independent reserve engineering firm of
DeGolyer and MacNaughton (D&M). D&M conducted an independent engineering
analysis of properties comprising about 82percent of EOG's 2013 proved
reserves on a Boe basis.

Hedging Activity
EOG increased the amount of crude oil hedges in place for 2014 compared to
2013. For February 2014, EOG has crude oil financial price swap contracts in
place for 171,000 Bopd at a weighted average price of $96.35 per barrel,
excluding unexercised options. For March 2014, EOG has crude oil financial
price swap contracts in place for 181,000 Bopd at a weighted average price of
$96.55 per barrel, excluding unexercised options. For the period April 1
through May 31, 2014, EOG has crude oil financial price swap contracts in
place for 171,000 Bopd at a weighted average price of $96.55 per barrel,
excluding unexercised options. For June 2014, EOG has crude oil financial
price swap contracts in place for 161,000 Bopd at a weighted average price of
$96.33 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 64,000 Bopd at a weighted average price of $95.18 per barrel,
excluding unexercised options.

EOG also has hedged natural gas volumes. For the period March 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 MMBtu, excluding unexercised options. (For a
comprehensive summary of crude oil and natural gas derivative contracts,
please refer to the attached tables.) 

Capital Structure
During 2013, EOG's cash flows from operating activities exceeded total capital
expenditures. Total proceeds from asset sales were $761 million.

At December 31, 2013, EOG's total debt outstanding was $5,913 million for a
debt-to-total capitalization ratio of 28 percent. Taking into account cash on
the balance sheet of $1.3 billion at year-end, EOG's net debt was $4,595
million for a net debt-to-total capitalization ratio of 23 percent, down from
29 percent at year-end 2012. (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).)

2014 Plans
EOG is targeting 27 percent total company crude oil production growth in 2014,
driven by 29 percent growth in the U.S. Although natural gas prices have
recently increased due to cold winter weather in North America, EOG's
extensive portfolio of crude oil and liquids-rich resources offer far superior
returns compared to alternative natural gas drilling investments. EOG does not
plan to allocate capital to North American dry natural gas drilling in 2014.
As a result, its North American natural gas production is expected to decline
6 percent. Total company production is expected to increase 11.5 percent.

Capital expenditures for 2014 are expected to range from $8.1 to $8.3 billion,
including production facilities and midstream expenditures, but excluding
acquisitions.

"EOG is directing a larger percentage of its 2014 capital budget to the Eagle
Ford and Bakken where we have tremendous drilling opportunity with excellent
rates of return," Thomas said. "By increasing activity in these plays, we
expect the momentum and operational efficiencies we've created to continue."

With plans to drill approximately 520 net wells across its Eagle Ford acreage
during 2014, EOG expects the play's extremely robust production will again
lead the company's overall crude oil growth.

EOG is increasing activity in the North Dakota Bakken/Three Forks where it is
targeting an 80-net well drilling program, an uptick over 2013. Operations
will be primarily in the Core, followed by the Antelope Extension area. Based
on successful drilling results from the first and second intervals of the
Three Forks formation in the Antelope Extension last year, EOG intends to test
additional benches during 2014. 

As a result of sound technical progress achieved last year, EOG is shifting
its Permian capital expenditure program from the Midland Basin to the higher
rate-of-return Delaware Basin in 2014. Concentrating on the Leonard play and,
to a lesser extent, the Wolfcamp, the emphasis will be on implementing
efficient drilling patterns while continuing to test additional prospective
zones.

"2014 should be another great year for EOG. We will stay focused on improving
EOG's overall returns as we pursue a wealth of high rate-of-return drilling
opportunities across our onshore domestic crude oil plays, and we'll continue
to seek exciting new prospects to add to our deep inventory," Thomas said.

Stock Split and Dividend Increase
The board of directors approved a two-for-one stock split in the form of a
stock dividend. It will be payable to record holders as of March 17, 2014, and
issued March 31, 2014. In addition, the board increased the cash dividend on
the common stock by 33 percent. Effective with the dividend payable April 30,
2014 to holders of record as of April 16, 2014, the board declared a
post-split quarterly dividend of $0.125 per share on the common stock. The
post-split indicated annual rate of $0.50 per share represents the 15^th
increase in 15 years.

Conference Call February 25, 2014
EOG's fourth quarter and full year 2013 results conference call will be
available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time)
on Tuesday, February 25, 2014. To listen, log on to www.eogresources.com. The
webcast will be archived on EOG's website through March 10, 2014.

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) 651-6EOG (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        Twelve Months Ended
                          December 31,              December 31,
                          2013         2012         2013          2012
Net Operating Revenues    $ 3,749.0    $ 3,011.8    $ 14,487.1    $ 11,682.6
Net Income (Loss)         $ 580.2      $ (505.0)    $ 2,197.1     $ 570.3
Net Income (Loss) Per
Share
 Basic                    $ 2.14       $ (1.88)     $ 8.13        $ 2.13
 Diluted                  $ 2.12       $ (1.88)     $ 8.04        $ 2.11
Average Number of Common
Shares
 Basic                      270.9        268.9        270.2         267.6
 Diluted                    274.0        268.9        273.1         270.8
SUMMARY INCOME STATEMENTS
(Unaudited; in thousands, except per share data)
                          Three Months Ended        Twelve Months Ended
                          December 31,              December 31,
                          2013         2012         2013          2012
Net Operating Revenues
 Crude Oil and Condensate $ 2,168,073  $ 1,460,684  $ 8,300,647   $ 5,659,437
 Natural Gas Liquids        217,794      208,493      773,970       727,177
 Natural Gas                411,425      418,329      1,681,029     1,571,762
 Gains (Losses) on
 Mark-to-Market Commodity   40,504       66,416       (166,349)     393,744
 Derivative Contracts
 Gathering, Processing      888,680      903,404      3,643,749     3,096,694
 and Marketing
 Gains (Losses) on Asset    11,996       (55,474)     197,565       192,660
 Dispositions, Net
 Other, Net                 10,551       9,959        56,507        41,162
            Total           3,749,023    3,011,811    14,487,118    11,682,636
Operating Expenses
 Lease and Well             288,921      234,349      1,105,978     1,000,052
 Transportation Costs       224,506      169,789      853,044       601,431
 Gathering and Processing   26,349       25,542       107,871       97,945
 Costs
 Exploration Costs          30,378       48,660       161,346       185,569
 Dry Hole Costs             15,395       1,965        74,655        14,970
 Impairments               109,509      1,020,496    286,941       1,270,735
 Marketing Costs            901,940      880,451      3,648,840     3,035,494
 Depreciation, Depletion    915,257      786,344      3,600,976     3,169,703
 and Amortization
 General and                91,066       86,679       348,312       331,545
 Administrative
 Taxes Other Than Income    165,378      135,597      623,944       495,395
            Total           2,768,699    3,389,872    10,811,907    10,202,839
Operating Income (Loss)     980,324      (378,061)    3,675,211     1,479,797
Other Income (Expense),     (8,732)      (8,407)      (2,865)       14,495
Net
Income (Loss) Before
Interest Expense and        971,592      (386,468)    3,672,346     1,494,292
Income Taxes
Interest Expense, Net       52,510       59,354       235,460       213,552
Income (Loss) Before        919,082      (445,822)    3,436,886     1,280,740
Income Taxes
Income Tax Provision        338,888      59,177       1,239,777     710,461
Net Income (Loss)         $ 580,194    $ (504,999)  $ 2,197,109   $ 570,279
Dividends Declared per    $ 0.1875     $ 0.17       $ 0.75        $ 0.68
Common Share



EOG RESOURCES, INC.
OPERATING HIGHLIGHTS
(Unaudited)
                                       Three Months Ended  Twelve Months Ended
                                       December 31,        December 31,
                                       2013       2012     2013        2012
Wellhead Volumes and Prices
Crude Oil and Condensate Volumes
(MBbld) ^(A)
      United States                       235.4     154.1     212.1      149.3
      Canada                              7.7       7.5       7.0        7.0
      Trinidad                            1.1       1.0       1.2        1.5
      Other International ^(B)            0.1       0.1       0.1        0.1
                   Total                  244.3     162.7     220.4      157.9
Average Crude Oil and Condensate
Prices ($/Bbl) ^(C)
      United States                    $  97.23   $ 98.72  $  103.81   $ 98.38
      Canada                              78.02     85.59     87.05      86.08
      Trinidad                            84.91     83.93     90.30      92.26
      Other International ^(B)            89.97     87.34     89.11      89.57
                   Composite              96.57     98.02     103.20     97.77
Natural Gas Liquids Volumes (MBbld)
^(A)
      United States                       66.6      57.0      64.3       55.1
      Canada                              0.8       0.8       0.9        0.8
                   Total                  67.4      57.8      65.2       55.9
Average Natural Gas Liquids Prices
($/Bbl) ^(C)
      United States                    $  35.01   $ 35.36  $  32.46    $ 35.41
      Canada                              45.17     42.50     39.45      44.13
                   Composite              35.13     35.45     32.55      35.54
Natural Gas Volumes (MMcfd) ^(A)
      United States                       873       981       908        1,034
      Canada                              69        84        76         95
      Trinidad                            372       335       355        378
      Other International ^(B)            7         8         8          9
                   Total                  1,321     1,408     1,347      1,516
Average Natural Gas Prices ($/Mcf)
^(C)
      United States                    $  3.28    $ 2.93   $  3.32     $ 2.51
      Canada                              3.34      2.98      3.08       2.49
      Trinidad                            3.60      4.12      3.68       3.72
      Other International ^(B)            6.01      5.75      6.45       5.71
                   Composite              3.39      3.23      3.42       2.83
Crude Oil Equivalent Volumes (MBoed)
^(D)
      United States                      447.6     374.6     427.9      376.6
      Canada                              19.9      22.3      20.5       23.6
      Trinidad                            63.0      56.8      60.4       64.5
      Other International ^(B)            1.3       1.4       1.3        1.7
                   Total                  531.8     455.1     510.1      466.4
Total MMBoe ^(D)                          48.9      41.9      186.2      170.7

(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)
                                                December 31,    December 31,
                                                2013            2012
ASSETS
Current Assets
 Cash and Cash Equivalents                      $ 1,318,209     $ 876,435
 Accounts Receivable, Net                         1,658,853       1,656,618
 Inventories                                      563,268         683,187
 Assets from Price Risk Management Activities     8,260           166,135
 Income Taxes Receivable                          4,797           29,163
 Deferred Income Taxes                            244,606         -
 Other                                            274,022         178,346
                Total                             4,072,015       3,589,884
Property, Plant and Equipment
 Oil and Gas Properties (Successful Efforts       42,821,803      38,126,298
 Method)
 Other Property, Plant and Equipment              2,967,085       2,740,619
                Total Property, Plant and         45,788,888      40,866,917
                Equipment
 Less: Accumulated Depreciation, Depletion and   (19,640,052)    (17,529,236)
 Amortization
                Total Property, Plant and         26,148,836      23,337,681
                Equipment, Net
Other Assets                                      353,387         409,013
Total Assets                                    $ 30,574,238    $ 27,336,578
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
 Accounts Payable                               $ 2,254,418     $ 2,078,948
 Accrued Taxes Payable                            159,365         162,083
 Dividends Payable                                50,795          45,802
 Liabilities from Price Risk Management           127,542         7,617
 Activities
 Deferred Income Taxes                            -               22,838
 Current Portion of Long-Term Debt                6,579           406,579
 Other                                            263,017         200,191
                Total                             2,861,716       2,924,058
Long-Term Debt                                    5,906,642       5,905,602
Other Liabilities                                 865,067         894,758
Deferred Income Taxes                             5,522,354       4,327,396
Commitments and Contingencies
Stockholders' Equity
 Common Stock, $0.01 Par, 640,000,000 Shares
 Authorized and 273,189,220 Shares and            202,732         202,720
 271,958,495 Shares Issued at December 31, 2013
 and 2012, respectively
 Additional Paid in Capital                       2,646,879       2,500,340
 Accumulated Other Comprehensive Income          415,834         439,895
 Retained Earnings                                12,168,277      10,175,631
 Common Stock Held in Treasury, 103,415 Shares
 and 326,264 Shares at December 31, 2013 and      (15,263)        (33,822)
 2012, respectively
                Total Stockholders' Equity        15,418,459      13,284,764
Total Liabilities and Stockholders' Equity      $ 30,574,238    $ 27,336,578



EOG RESOURCES, INC.
SUMMARY STATEMENTS OF CASH FLOWS
(Unaudited; in thousands)
                                                  Twelve Months Ended
                                                  December 31,
                                                  2013           2012
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided
by Operating Activities:
 Net Income                                      $ 2,197,109    $ 570,279
 Items Not Requiring (Providing) Cash
       Depreciation, Depletion and Amortization     3,600,976      3,169,703
       Impairments                                 286,941        1,270,735
       Stock-Based Compensation Expenses            134,055        127,778
       Deferred Income Taxes                        874,765        292,938
       Gains on Asset Dispositions, Net             (197,565)      (192,660)
       Other, Net                                   11,072         672
 Dry Hole Costs                                     74,655         14,970
 Mark-to-Market Commodity Derivative Contracts
       Total (Gains) Losses                        166,349        (393,744)
       Net Cash Received from Settlements of        116,361        711,479
       Commodity Derivative Contracts
 Excess Tax Benefits from Stock-Based               (55,831)       (67,035)
 Compensation
 Other, Net                                         18,205         14,411
 Changes in Components of Working Capital and
 Other Assets and Liabilities
       Accounts Receivable                          (23,613)       (178,683)
       Inventories                                  53,402         (156,762)
       Accounts Payable                             178,701        (17,150)
       Accrued Taxes Payable                        75,142         78,094
       Other Assets                                 (109,567)      (118,520)
       Other Liabilities                            (20,382)       36,114
 Changes in Components of Working Capital
 Associated with Investing and
    Financing Activities                            (51,361)       74,158
Net Cash Provided by Operating Activities           7,329,414      5,236,777
Investing Cash Flows
 Additions to Oil and Gas Properties                (6,697,091)    (6,735,316)
 Additions to Other Property, Plant and Equipment   (363,536)      (619,800)
 Proceeds from Sales of Assets                      760,557        1,309,776
 Changes in Restricted Cash                         (65,814)       -
 Changes in Components of Working Capital           51,106         (73,923)
 Associated with Investing Activities
Net Cash Used in Investing Activities               (6,314,778)    (6,119,263)
Financing Cash Flows
 Long-Term Debt Repayments                          (400,000)      -
 Long-Term Debt Borrowings                          -              1,234,138
 Dividends Paid                                     (199,178)      (181,080)
 Excess Tax Benefits from Stock-Based               55,831         67,035
 Compensation
 Treasury Stock Purchased                           (63,784)       (58,592)
 Proceeds from Stock Options Exercised and          38,730         82,887
 Employee Stock Purchase Plan
 Debt Issuance Costs                                -              (1,578)
 Repayment of Capital Lease Obligation              (5,780)        (2,824)
 Other, Net                                         255            (235)
Net Cash (Used in) Provided by Financing            (573,926)      1,139,751
Activities
Effect of Exchange Rate Changes on Cash             1,064          3,444
Increase in Cash and Cash Equivalents               441,774        260,709
Cash and Cash Equivalents at Beginning of Period    876,435        615,726
Cash and Cash Equivalents at End of Period        $ 1,318,209    $ 876,435



EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF ADJUSTED NET INCOME (NON-GAAP)
TO NET INCOME (LOSS) (GAAP)
(Unaudited; in thousands, except per share data)
The following chart adjusts the three-month and twelve-month periods
ended December 31, 2013 and 2012 reported Net Income (Loss) (GAAP) to
reflect actual net cash received from settlements of commodity
derivative contracts by eliminating the unrealized mark-to-market
(gains) losses from these transactions, to eliminate the net (gains)
losses on asset dispositions in North America 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      Twelve Months Ended
                  December 31,             December 31,
                  2013        2012         2013              2012
Reported Net
Income (Loss)     $ 580,194   $ (504,999)  $ 2,197,109       $ 570,279
(GAAP)
Mark-to-Market
(MTM) Commodity
Derivative
Contracts Impact
   Total (Gains)    (40,504)    (66,416)     166,349           (393,744)
   Losses
   Net Cash
   Received from
   Settlements of   1,038       155,533      116,361           711,479
   Commodity
   Derivative
   Contracts
       Subtotal     (39,466)    89,117       282,710           317,735
   After-Tax MTM    (24,901)    57,058       181,372           203,430
   Impact
Less: Net (Gains)
Losses on Asset     (7,232)     35,599       (136,848)         (126,053)
Dispositions, Net
of Tax
Add: Impairments
of Certain North    -           849,371      4,425             887,946
American Assets,
Net of Tax
Adjusted Net      $ 548,061   $ 437,029    $ 2,246,058       $ 1,535,602
Income (Non-GAAP)
Net Income (Loss)
Per Share (GAAP)
   Basic          $ 2.14      $ (1.88)     $ 8.13            $ 2.13
   Diluted        $ 2.12      $ (1.88)     $ 8.04            $ 2.11
Adjusted Net
Income Per Share
(Non-GAAP)
   Basic          $ 2.02      $ 1.62       $ 8.31            $ 5.74
   Diluted        $ 2.00      $ 1.61       $ 8.22      (a) $ 5.67      (b)
Percentage
Increase - [(a) -                            45%
(b)] / (b)
Average Number of
Common Shares
(GAAP)
   Basic            270,929     268,941      270,170           267,577
   Diluted          273,983     268,941      273,114           270,762
Average Number of
Shares (Non-GAAP)
   Basic            270,929     268,941      270,170           267,577
   Diluted          273,983     271,921      273,114           270,762



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 twelve-month periods
ended December 31, 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        Twelve Months Ended
                 December 31,              December 31,
                 2013         2012         2013              2012
Net Cash
Provided by
Operating        $ 2,001,230  $ 1,227,187  $ 7,329,414       $ 5,236,777
Activities
(GAAP)
Adjustments:
  Exploration
  Costs
  (excluding       24,201       42,619       134,531           159,182
  Stock-Based
  Compensation
  Expenses)
  Excess Tax
  Benefits from    5,601        17,609       55,831            67,035
  Stock-Based
  Compensation
  Changes in
  Components of
  Working
  Capital and
  Other Assets
  and
  Liabilities
     Accounts      (190,133)    66,509       23,613            178,683
     Receivable
     Inventories   7,745        1,996        (53,402)          156,762
     Accounts      (33,502)     100,832      (178,701)         17,150
     Payable
     Accrued
     Taxes         (1,945)      (35,303)     (75,142)          (78,094)
     Payable
     Other         30,768       (1,565)      109,567           118,520
     Assets
     Other         31,271       3,757        20,382            (36,114)
     Liabilities
  Changes in
  Components of
  Working
  Capital
  Associated
  with Investing
  and
    Financing      (21,584)     13,550       51,361            (74,158)
    Activities
Discretionary
Cash Flow        $ 1,853,652  $ 1,437,191  $ 7,417,454 (a) $ 5,745,743 (b)
(Non-GAAP)
Percentage
Increase - [(a)                              29%
- (b)] / (b)



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 (LOSS) BEFORE INTEREST EXPENSE AND INCOME TAXES
(GAAP)
(Unaudited; in thousands)
The following chart adjusts the three-month and twelve-month periods
ended December 31, 2013 and 2012 reported Income (Loss) 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 received from settlements
of commodity derivative contracts by eliminating the unrealized
mark-to-market (MTM) (gains) losses from these transactions and to
eliminate the net (gains) losses 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 (Loss) 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         Twelve Months Ended
                December 31,               December 31,
                2013         2012          2013              2012
Income (Loss)
Before Interest
Expense and     $ 971,592    $ (386,468)   $ 3,672,346       $ 1,494,292
Income Taxes
(GAAP)
Adjustments:
  Depreciation,
  Depletion and   915,257      786,344       3,600,976         3,169,703
  Amortization
  Exploration     30,378       48,660        161,346           185,569
  Costs
  Dry Hole        15,395       1,965         74,655            14,970
  Costs
  Impairments    109,509      1,020,496     286,941           1,270,735
    EBITDAX       2,042,131    1,470,997     7,796,264         6,135,269
    (Non-GAAP)
  Total (Gains)
  Losses on MTM
  Commodity       (40,504)     (66,416)      166,349           (393,744)
  Derivative
  Contracts
  Net Cash
  Received from
  Settlements     1,038        155,533       116,361           711,479
  of Commodity
  Derivative
  Contracts
  Net (Gains)
  Losses on       (11,996)     55,474        (197,565)         (192,660)
  Asset
  Dispositions
Adjusted
EBITDAX         $ 1,990,669  $ 1,615,588   $ 7,881,409 (a) $ 6,260,344 (b)
(Non-GAAP)
Percentage
Increase - [(a)                              26%
- (b)] / (b)



EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF AFTER-TAX INTEREST EXPENSE (NON-GAAP), ADJUSTED
NET INCOME
(NON-GAAP), NET DEBT (NON-GAAP) AND TOTAL CAPITALIZATION (NON-GAAP) AS USED IN
THE CALCULATIONS OF
RETURN ON CAPITAL EMPLOYED (NON-GAAP) AND RETURN ON EQUITY (NON-GAAP) TO
INTEREST EXPENSE (GAAP),
NET INCOME (GAAP), CURRENT AND LONG-TERM DEBT (GAAP) AND TOTAL CAPITALIZATION
(GAAP), RESPECTIVELY
(Unaudited; in millions, except ratio data)
The following chart reconciles Interest Expense (GAAP), Net Income (GAAP),
Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax
Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP), Net Debt (Non-GAAP)
and Total Capitalization (Non-GAAP), respectively, as used in the Return on
Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes
this presentation may be useful to investors who follow the practice of some
industry analysts who utilize After-Tax Interest Expense, Adjusted Net Income,
Net Debt and Total Capitalization (Non-GAAP)in their ROCE and ROE
calculations. EOG management uses this information for comparative purposes
within the industry.
                                                             2013       2012
Return on Capital Employed (ROCE)
Interest Expense                                            $ 235
Tax Benefit Imputed (based on 35%)                            (82)
After-Tax Interest Expense (Non-GAAP) - (a)                 $ 153
Net Income -                                                 $ 2,197
(b)
Add: After-Tax Mark-to-Market Commodity Derivative             182
Contracts Impact
Add: Impairments of Certain North American Assets, Net of      4
Tax
Less: Net Gains on Asset Dispositions, Net of Tax              (137)
Adjusted Net Income (Non-GAAP) - (c)                      $ 2,246
Total Stockholders' Equity - (d)                          $ 15,418   $ 13,285
Average Total Stockholders' Equity* - (h)                 $ 14,352
Current and Long-Term Debt - (e)                            $ 5,913    $ 6,312
Less:                                                          (1,318)    (876)
Cash
Net Debt (Non-GAAP) - (f)                                   $ 4,595    $ 5,436
Total Capitalization (GAAP) - (d) + (e)                    $ 21,331   $ 19,597
Total Capitalization (Non-GAAP) - (d) + (f)                 $ 20,013   $ 18,721
Average Total Capitalization (Non-GAAP)* - (g)            $ 19,367
ROCE (Non-GAAP) - [(a) + (b)] / (g)                     12.1%
ROCE (Non-GAAP) - [(a) + (c)] / (g)                     12.4%
Return on Equity (ROE)
ROE (Non-GAAP) - (b) / (h)                                     15.3%
ROE (Non-GAAP) - (c) / (h)                                     15.6%
*Average for the current and immediately preceding year



EOG RESOURCES, INC.
CRUDE OIL AND NATURAL GAS FINANCIAL
COMMODITY DERIVATIVE CONTRACTS
EOG has entered into additional crude oil and natural gas derivative contracts
since filing its Current Report on Form 8-K dated January 7, 2014. Presented
below is a comprehensive summary of EOG's crude oil and natural gas derivative
contracts at February 24, 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^(1)
    January 2014 (closed)                         156,000        $     
                                                                 96.30
    February 2014                                171,000        96.35
    March 2014                                    181,000        96.55
    April 1, 2014 through May 31, 2014            171,000        96.55
    June 2014                                     161,000        96.33
    July 1, 2014 through December 31, 2014        64,000         95.18
    EOG has entered into crude oil derivative contracts which give
    counterparties the option to extend certain current derivative contracts
    for additional three-month, 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 10,000 Bbld are exercisable on or about May
    30, 2014. If the counterparties exercise all such options, the notional
    volume of EOG's existing crude oil derivative contracts will increase by
(1) 10,000 Bbld at an average price of $100.00 per barrel for each month
    during the period June 1, 2014 through August 31, 2014. Options covering a
    notional volume of 118,000 Bbld are exercisable on or about June 30, 2014.
    If the counterparties exercise all such options, the notional volume of
    EOG's existing crude oil derivative contracts will increase by 118,000
    Bbld at an average price of $96.64 per barrel for each month during the
    period July 1, 2014 through December 31, 2014. Options covering a notional
    volume of 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 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 March 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.
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
                                      December 31,             December 31,
                                      2013                     2012
Total Stockholders' Equity - (a)      $       15,418           $     13,285
Current and Long-Term Debt - (b)              5,913                  6,312
Less: Cash                                   (1,318)                (876)
Net Debt (Non-GAAP) - (c)                     4,595                  5,436
Total Capitalization (GAAP) - (a) +   $       21,331           $     19,597
(b)
Total Capitalization (Non-GAAP) - (a) $       20,013           $     18,721
+ (c)
Debt-to-Total Capitalization (GAAP) -         28%                    32%
(b) / [(a) + (b)]
Net Debt-to-Total Capitalization              23%                    29%
(Non-GAAP) - (c) / [(a) + (c)]



EOG RESOURCES, INC.
RESERVES SUPPLEMENTAL DATA
(Unaudited)
2013 NET PROVED RESERVES RECONCILIATION SUMMARY
               United            North                Other  Total
               States  Canada  America  Trinidad  Int'l  Int'l  Total
CRUDE OIL &
CONDENSATE
(MMBbls)
Beginning      671.0     17.9      688.9      3.0         8.9      11.9     700.8
Reserves
Revisions     57.6      (5.9)     51.7       (1.0)       (0.1)    (1.1)    50.6
Purchases in   1.1       -         1.1        -           -        -        1.1
place
Extensions,
discoveries    230.0     0.7       230.7      -           0.1      0.1      230.8
and other
additions
Sales in place (2.3)     -         (2.3)      -           -        -        (2.3)
Production    (77.4)    (2.6)     (80.0)     (0.4)       (0.1)    (0.5)    (80.5)
Ending         880.0     10.1      890.1      1.6         8.8      10.4     900.5
Reserves
NATURAL GAS
LIQUIDS
(MMBbls)
Beginning      318.4     1.6       320.0      -           -        -        320.0
Reserves
Revisions     12.2      (0.1)     12.1       -           -        -        12.1
Purchases in   1.2       -         1.2        -           -        -        1.2
place
Extensions,
discoveries    69.2      -         69.2       -           -        -        69.2
and other
additions
Sales in place (1.5)     -         (1.5)      -           -        -        (1.5)
Production    (23.5)    (0.3)     (23.8)     -           -        -        (23.8)
Ending         376.0     1.2       377.2      -           -        -        377.2
Reserves
NATURAL GAS
(Bcf)
Beginning      4,036.0   98.3      4,134.3    588.2       17.0     605.2    4,739.5
Reserves
Revisions     264.0     31.4      295.4      (17.4)      (0.7)    (18.1)   277.3
Purchases in   5.7       -         5.7        -           -        -        5.7
place
Extensions,
discoveries    504.7     0.1       504.8      79.5        9.8      89.3     594.1
and other
additions
Sales in place (69.4)    -         (69.4)     -           -        -        (69.4)
Production    (342.3)   (27.7)    (370.0)    (129.6)     (2.8)    (132.4)  (502.4)
Ending         4,398.7   102.1     4,500.8    520.7       23.3     544.0    5,044.8
Reserves
OIL
EQUIVALENTS
(MMBoe)
Beginning      1,662.1   35.8      1,697.9    101.1       11.7     112.8    1,810.7
Reserves
Revisions     113.9     (0.7)     113.2      (3.9)       (0.3)    (4.2)    109.0
Purchases in   3.2       -         3.2        -           -        -        3.2
place
Extensions,
discoveries    383.4     0.7       384.1      13.2        1.7      14.9     399.0
and other
additions
Sales in place (15.4)    -         (15.4)     -           -        -        (15.4)
Production    (158.0)   (7.5)     (165.5)    (22.0)      (0.5)    (22.5)   (188.0)
Ending         1,989.2   28.3      2,017.5    88.4        12.6     101.0    2,118.5
Reserves
Net Proved
Developed
Reserves
(MMBoe)
 At
December 31,   840.6     24.3      864.9      81.8        3.1      84.9     949.8
2012
 At
December 31,   1,015.4   24.8      1,040.2    83.9        3.4      87.3     1,127.5
2013
2013 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ Millions)
               United            North                Other  Total
               States  Canada  America  Trinidad  Int'l  Int'l  Total
Acquisition
Cost of        $        $      $         $       $     $     $ 
Unproved       411.6    2.5       414.1      -           -      -    414.1
Properties
Exploration    273.8     19.7      293.5      16.1        67.6     83.7     377.2
Costs
Development    5,488.9   136.5     5,625.4    123.7       202.9    326.6    5,952.0
Costs
Total Drilling 6,174.3   158.7     6,333.0    139.8       270.5    410.3    6,743.3
Acquisition
Cost of Proved 120.2     -         120.2      -           -        -        120.2
Properties
Total
Exploration &  6,294.5   158.7     6,453.2    139.8       270.5    410.3    6,863.5
Development
Expenditures
Gathering,
Processing and 360.0     2.8       362.8      -           0.8      0.8      363.6
Other
Asset
Retirement     84.3      13.0      97.3       0.5         36.6     37.1     134.4
Costs
Total          6,738.8   174.5     6,913.3    140.3       307.9    448.2    7,361.5
Expenditures
Proceeds from
Sales of       (362.3)   (397.8)   (760.1)    -           -        -        (760.1)
Assets
Net            $         $        $ 6,153.2  $  140.3  $       $       $
Expenditures   6,376.5   (223.3)                          307.9   448.2   6,601.4
RESERVE
REPLACEMENT
COSTS ($ / Boe
) *
Total
Drilling,      $        $         $         $  10.59  $        $       $ 
Before         16.09    226.71   16.47                 159.12  27.54   16.89
Revisions
All-in Total,  $                  $                     $        $       $ 
Net of         12.57    NA      12.88     $  15.03  193.21  38.35   13.42
Revisions
All-in Total,
Excluding      $        NA      $         $  15.03  $        $       $ 
Revisions Due  14.12              14.66                 193.21  38.35   15.23
to Price
RESERVE
REPLACEMENT *
Drilling Only  243%      9%        232%       60%         340%     66%      212%
All-in Total,
Net of         307%      0%        293%       42%         280%     48%      264%
Revisions &
Dispositions
All-in Total,
Excluding      272%      -75%      256%       42%         280%     48%      231%
Revisions Due
to Price
All-in Total,  364%      -183%     349%       -250%       0%       -200%    346%
Liquids
* See attached reconciliation schedule for calculation methodology



EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF TOTAL EXPLORATION AND DEVELOPMENT EXPENDITURES
FOR DRILLING ONLY (NON-GAAP) AND TOTAL EXPLORATION AND DEVELOPMENT EXPENDITURES
(NON-GAAP)
AS USED IN THE CALCULATION OF RESERVE REPLACEMENT COSTS ($ / BOE)
TO TOTAL COSTS INCURRED IN EXPLORATION AND DEVELOPMENT ACTIVITIES (GAAP)
(Unaudited; in millions, except ratio information)
The following chart reconciles Total Costs Incurred in Exploration and
Development Activities (GAAP) to Total Exploration and Development Expenditures
for Drilling Only (Non-GAAP) and Total Exploration and Development Expenditures
(Non-GAAP), as used in the calculation of Reserve Replacement Costs per Boe.
There are numerous ways that industry participants present Reserve Replacement
Costs, including "Drilling Only" and "All-In", which reflect total exploration
and development expenditures divided by total net proved reserve additions from
extensions and discoveries only, or from all sources. Combined with Reserve
Replacement, these statistics provide management and investors with an indication
of the results of the current year capital investment program. Reserve
Replacement Cost statistics are widely recognized and reported by industry
participants and are used by EOG management and other third parties for
comparative purposes within the industry. Please note that the actual cost of
adding reserves will vary from the reported statistics due to timing differences
in reserve bookings and capital expenditures. Accordingly, some analysts use
three- or five-year averages of reported statistics, while others prefer to
estimate future costs. EOG has not included future capital costs to develop
proved undeveloped reserves in exploration and development expenditures.
             United            North                Other  Total
             States  Canada  America  Trinidad  Int'l  Int'l  Total
Total Costs
Incurred in
Exploration  $         $                               $       $       $
and          6,378.8   171.7    $ 6,550.5  $  140.3  307.1   447.4   6,997.9
Development
Activities
(GAAP)
Less: Asset
Retirement   (84.3)    (13.0)    (97.3)     (0.5)       (36.6)   (37.1)   (134.4)
Costs
 Non-Cash
 Acquisition
 Costs of    (5.0)     -         (5.0)      -           -        -        (5.0)
 Unproved
 Properties
 Acquisition
 Cost of     (120.2)   -         (120.2)    -           -        -        (120.2)
 Proved
 Properties
Total
Exploration
&
Development  $         $                               $       $       $
Expenditures 6,169.3   158.7    $ 6,328.0  $  139.8  270.5   410.3   6,738.3
for Drilling
Only
(Non-GAAP)
(a)
Total Costs
Incurred in
Exploration  $         $                               $       $       $
and          6,378.8   171.7    $ 6,550.5  $  140.3  307.1   447.4   6,997.9
Development
Activities
(GAAP)
Less: Asset
Retirement   (84.3)    (13.0)    (97.3)     (0.5)       (36.6)   (37.1)   (134.4)
Costs
 Non-Cash
 Acquisition
 Costs of    (5.0)     -         (5.0)      -           -        -        (5.0)
 Unproved
 Properties
Total
Exploration
&            $         $                               $       $       $
Development  6,289.5   158.7    $ 6,448.2  $  139.8  270.5   410.3   6,858.5
Expenditures
(Non-GAAP)
(b)
Total        $         $                               $       $       $
Expenditures 6,738.8   174.5    $ 6,913.3  $  140.3  307.9   448.2   7,361.5
(GAAP)
Less: Asset
Retirement   (84.3)    (13.0)    (97.3)     (0.5)       (36.6)   (37.1)   (134.4)
Costs
 Non-Cash
 Acquisition
 Costs of    (5.0)     -         (5.0)      -           -        -        (5.0)
 Unproved
 Properties
Total Cash   $         $                               $       $       $
Expenditures 6,649.5   161.5    $ 6,811.0  $  139.8  271.3   411.1   7,222.1
(Non-GAAP)
Net Proved
Reserve
Additions
From All
Sources -
Oil
Equivalents
(MMBoe)
Revisions
due to price 55.2      5.6       60.8       -           -        -        60.8
(c)
Revisions
other than   58.7      (6.3)     52.4       (3.9)       (0.3)    (4.2)    48.2
price
Purchases in 3.2       -         3.2        -           -        -        3.2
place
Extensions,
discoveries
and other    383.4     0.7       384.1      13.2        1.7      14.9     399.0
additions
(d)
Total Proved
Reserve      500.5     -         500.5      9.3         1.4      10.7     511.2
Additions
(e)
Sales in     (15.4)    -         (15.4)     -           -        -        (15.4)
place
Net Proved
Reserve
Additions    485.1     -         485.1      9.3         1.4      10.7     495.8
From All
Sources (f)
Production   158.0     7.5       165.5      22.0        0.5      22.5     188.0
(g)
RESERVE
REPLACEMENT
COSTS ($ /
BOE)
Total
Drilling,    $        $         $                     $        $       $ 
Before       16.09    226.71   16.47     $  10.59  159.12  27.54   16.89
Revisions (a
/ d)
All-in
Total, Net   $        NA      $         $  15.03  $        $       $ 
of Revisions 12.57              12.88                 193.21  38.35   13.42
(b / e)
All-in
Total,
Excluding    $                  $                     $        $       $ 
Revisions    14.12    NA      14.66     $  15.03  193.21  38.35   15.23
Due to Price
(b / (e -
c))
RESERVE
REPLACEMENT
Drilling
Only (d /    243%      9%        232%       60%         340%     66%      212%
g)
All-in
Total, Net
of Revisions 307%      0%        293%       42%         280%     48%      264%
&
Dispositions
(f / g)
All-in
Total,
Excluding
Revisions    272%      -75%      256%       42%         280%     48%      231%
Due to Price
((f - c ) /
g)
Net Proved
Reserve
Additions
From All
Sources -
Liquids
(MMBbls)
Revisions    69.8      (6.0)     63.8       (1.0)       (0.1)    (1.1)    62.7
Purchases in 2.3       -         2.3        -           -        -        2.3
place
Extensions,
discoveries
and other    299.2     0.7       299.9      -           0.1      0.1      300.0
additions
(h)
Total Proved
Reserve      371.3     (5.3)     366.0      (1.0)       -        (1.0)    365.0
Additions
Sales in     (3.8)     -         (3.8)      -           -        -        (3.8)
place
Net Proved
Reserve
Additions    367.5     (5.3)     362.2      (1.0)       -        (1.0)    361.2
From All
Sources (i)
Production   100.9     2.9       103.8      0.4         0.1      0.5      104.3
(j)
RESERVE
REPLACEMENT
- LIQUIDS
Drilling
Only (h /    297%      24%       289%       0%          100%     20%      288%
j)
All-in
Total, Net
of Revisions 364%      -183%     349%       -250%       0%       -200%    346%
&
Dispositions
(i / j)



EOG RESOURCES, INC.
 FIRST QUARTER AND FULL YEAR 2014 FORECAST AND BENCHMARK COMMODITY PRICING
       (a) First Quarter and Full Year 2014 Forecast
The forecast items for the first 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)
                                        1Q 2014               Full Year 2014
Daily Production
       Crude Oil and Condensate
       Volumes (MBbld)
               United States            246.0   -   256.0     263.0  -   283.0
               Canada                   5.5     -   6.5       4.5    -   6.5
               Trinidad                 0.7     -   1.1       0.6    -   1.0
               Other International      0.0     -   0.0       0.0    -   1.2
                    Total               252.2   -   263.6     268.1  -   291.7
       Natural Gas Liquids Volumes
       (MBbld)
               United States            63.5    -   67.5      68.0   -   77.0
               Canada                   0.5     -   0.7       0.6    -   0.8
                    Total               64.0    -   68.2      68.6   -   77.8
       Natural Gas Volumes (MMcfd)
               United States            845     -   875       850    -   880
               Canada                   56      -   68        55     -   69
               Trinidad                 365     -   385       350    -   370
               Other International      6       -   8         8      -   12
                    Total               1,272   -   1,336     1,263  -   1,331
       Crude Oil Equivalent Volumes
       (MBoed)
               United States            450.4   -   469.4     472.7  -   506.6
               Canada                   15.3    -   18.5      14.3   -   18.8
               Trinidad                 61.5    -   65.3      58.9   -   62.7
               Other International      1.0     -   1.3       1.3    -   3.2
                    Total               528.2   -   554.5     547.2  -   591.3
Operating Costs
       Unit Costs ($/Boe)
               Lease and Well        $  6.35    - $ 6.65    $ 6.25   - $ 6.75
               Transportation Costs  $  4.90    - $ 5.10    $ 4.80   - $ 5.20
               Depreciation,
               Depletion and         $  18.65   - $ 19.35   $ 18.40  - $ 19.20
               Amortization
Expenses ($MM)
       Exploration, Dry Hole and     $  140.0   - $ 160.0   $ 525.0  - $ 575.0
       Impairment
       General and Administrative    $  95.0    - $ 105.0   $ 390.0  - $ 410.0
       Gathering and Processing     $  30.0    - $ 36.0    $ 120.0  - $ 140.0
       Capitalized Interest          $  14.0    - $ 16.0    $ 55.0   - $ 65.0
       Net Interest                  $  48.0    - $ 52.0    $ 190.0  - $ 210.0
Taxes Other Than Income (% of           6.0%    -   6.4%      6.0%   -   6.4%
Wellhead Revenue)
Income Taxes
       Effective Rate                  35%     -   40%       35%    -   40%
       Current Taxes ($MM)           $  105     - $ 120     $ 425    - $ 445
Capital Expenditures ($MM) - FY 2014
(Excluding Acquisitions)
       Exploration and Development,                         $ 6,450    $ 6,550
       Excluding Facilities
       Exploration and Development                          $ 880      $ 920
       Facilities
       Gathering, Processing and                            $ 770      $ 810
       Other
Pricing - (Refer to Benchmark
Commodity Pricing in text)
       Crude Oil and Condensate
       ($/Bbl)
               Differentials
                    United States -
                    (above) below    $  (1.50)  - $ 0.00    $ (0.80) - $ 0.20
                    WTI
                    Canada - (above) $  11.25   - $ 14.00   $ 10.00  - $ 14.00
                    below WTI
                    Trinidad -
                    (above) below    $  8.00    - $ 12.00   $ 8.00   - $ 12.00
                    WTI
       Natural Gas Liquids
               Realizations as % of
               WTI
                    United States       35%     -   43%       31%    -   37%
                    Canada              37%     -   42%       30%    -   40%
       Natural Gas ($/Mcf)
               Differentials
                    United States -
                    (above) below    $  (0.25)  - $ 0.25    $ 0.25   - $ 0.70
                    NYMEX Henry Hub
                    Canada - (above)
                    below NYMEX      $  0.50    - $ 0.80    $ 0.40   - $ 0.80
                    Henry Hub
               Realizations
                    Trinidad         $  2.75    - $ 3.25    $ 2.75   - $ 3.25
                    Other            $  5.00    - $ 7.00    $ 4.00   - $ 6.00
                    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
 
Press spacebar to pause and continue. Press esc to stop.