EOG Resources Reports Outstanding 2012 Results; Increases Eagle Ford and Leonard Reserve Potential; Announces New Texas Delaware

   EOG Resources Reports Outstanding 2012 Results; Increases Eagle Ford and
 Leonard Reserve Potential; Announces New Texas Delaware Basin Wolfcamp Play;
                  Raises Common Stock Dividend by 10 Percent

PR Newswire

HOUSTON, Feb. 13, 2013

HOUSTON, Feb. 13, 2013 /PRNewswire/ --

  oAchieves 39 Percent Year-Over-Year Total Company Crude Oil and Condensate
    Growth and 37 Percent Total Liquids Growth
  oReports 10 Percent Total Company Production Growth
  oDelivers Strong Year-Over-Year Growth in Non-GAAP Earnings Per Share,
    Adjusted EBITDAX and Discretionary Cash Flow
  oIncreases Eagle Ford Potential Recoverable Reserve Estimate by 600 MMBoe
    to 2.2 BnBoe, Net to EOG
  oHighlights Record Eagle Ford Oil Well
  oAnnounces New Wolfcamp Shale Play in Delaware Basin and Increases Leonard
    Shale Potential Reserves with Total Combined Delaware Basin Potential
    Reserves of 1.35 BnBoe, Net to EOG
  oRealizes Improvements in Bakken/Three Forks Operations
  oDelivers 268 Percent Reserve Replacement at Attractive Finding Costs,
    Excluding Price-Related Reserve Revisions
  oRaises Common Stock Dividend for 14^th Time in 14 Years

EOG Resources, Inc. (NYSE: EOG) (EOG) today reported full year 2012 net income
of $570.3 million, or $2.11 per share, as compared to $1,091.1 million, or
$4.10 per share, for the full year 2011. For the fourth quarter 2012, EOG
reported a net loss of $505.0 million, or $1.88 per share. This compares to
fourth quarter 2011 net income of $120.7 million, or $0.45 per share.

Adjusted non-GAAP net income for the full year 2012 was $1,535.6 million, or
$5.67 per share, and for the full year 2011 was $1,008.5 million, or $3.79 per
share. Adjusted non-GAAP net income for the fourth quarter 2012 was $437.0
million, or $1.61 per share, and for the fourth quarter 2011 was $309.0
million, or $1.15 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, the results for the fourth quarter 2012 include $849.4 million, net of
tax ($3.13 per share) of impairments of certain Canadian natural gas assets,
net losses on asset dispositions of $35.6 million, net of tax ($0.13 per
share) and a previously disclosed non-cash net gain of $66.4 million ($42.5
million after tax, or $0.16 per share) on the mark-to-market of financial
commodity derivative contracts. During the fourth quarter, the net cash inflow
related to financial commodity derivative contracts was $155.5 million ($99.5
million after tax, or $0.37 per share). (Please refer to the attached tables
for the reconciliation of adjusted non-GAAP net income to GAAP net
income/loss.)

Reflecting EOG's higher revenue and production weighting to crude oil for the
full year 2012, adjusted non-GAAP net income per share increased 50 percent,
adjusted EBITDAX increased 26 percent and discretionary cash flow increased 26
percent as compared to 2011. (Please refer to the attached tables for the
reconciliation of adjusted non-GAAP net income per share to GAAP net income
per share, adjusted EBITDAX (non-GAAP) to income before interest expense and
income taxes (GAAP) and non-GAAP discretionary cash flow to net cash provided
by operating activities (GAAP).)

In the United States, crude oil and condensate production increased 46 percent
for the full year 2012 compared to the prior year. Total United States liquids
(crude oil, condensate and natural gas liquids) production increased 42
percent for full year 2012 over the same period a year ago. On a total company
basis, total crude oil and condensate production increased 39 percent and
total liquids production increased 37 percent for the full year compared to
2011. Overall total company production increased 10 percent year-over-year.

"We accomplished all of EOG's 2012 goals. We generated high margin organic
crude oil production growth and delivered excellent year-over-year increases
in EOG's financial metrics. Wemaintained our net-debt-to-total cap ratio
below 30 percent and recorded strong crude oil reserve replacement rates at
attractive finding costs," said Mark G. Papa, Chairman and Chief Executive
Officer. "In addition, we added the Delaware Basin Wolfcamp, a promising new
liquids resource play to our portfolio and significantly increased the
potential recoverable reserves of our largest and highest rate of return
asset, the South Texas Eagle Ford. These add high-value inventory to EOG's
already prolific asset base."

Operational Highlights

EOG's stellar crude oil production in 2012 was primarily driven by drilling
and completion activity in the Eagle Ford where the company drilled and
completed 305 net wells, operating an average of 23 drilling rigs. In the
North Dakota Bakken/Three Forks, positive results from downspaced drilling
tests, together with significant modifications in drilling and completion
techniques, further boosted EOG's crude oil production growth. Breakthroughs
in geologic modeling in the Leonard/Wolfcamp horizontal shale plays in
southeastern New Mexico and West Texas also contributed to EOG's excellent
performance.

EOG made strides in increasing the amount of crude oil recoverable from both
its Eagle Ford and Bakken resources by testing various drilling densities and
further refining completion practices. In the Eagle Ford, EOG increased the
estimated recoverable potential reserves by 38 percent from 1.6 billion
barrels of oil equivalent (BnBoe) to 2.2 BnBoe, net to EOG. Numerous spacing
pilots across EOG's 569,000 net acres in the crude oil window point to optimal
resource development on 40-acre well spacing in the east and 65 acres in the
west. At current activity levels, EOG has a 12-year Eagle Ford drilling
inventory.

The revised Eagle Ford reserve potential is indicative of an estimated 8
percent recovery of the estimated 26.4 net BnBoe in place on EOG's acreage.
Since discovering the Eagle Ford in 2010, EOG has raised the overall estimated
captured reserve potential from 900 MMBoe (million barrels of oil equivalent)
to 2.2 BnBoe, net to EOG.

EOG's best Eagle Ford well to date is the Burrow Unit #2H, which had an
initial production rate of 6,330 barrels of oil per day (Bopd) with 713
barrels per day (Bpd) of natural gas liquids (NGLs) and 4.1 million cubic feet
per day (MMcfd) of natural gas. Offsetting the Burrow Unit #2H, the Burrow
Unit #1H was completed to sales at a maximum rate of 5,424 Bopd with 600 Bpd
of NGLs and 3.5 MMcfd of natural gas. Two other prolific wells, the Boothe
Unit #1H and #2H, began initial production at 5,380 and 3,810 Bopd with 625
and 525 Bpd of NGLs and 3.6 and 3.0 MMcfd of natural gas, respectively. EOG
has 100 percent working interest in these Gonzales County wells.

In McMullen County, southwest of EOG's Gonzales County sweet spot, the Naylor
Jones Unit 59 East #1H and West #4H had initial peak production rates of 1,670
and 1,150 Bopd with 225 and 138 Bpd of NGLs and 1.3 and 0.8 MMcfd of natural
gas, respectively. EOG has 100 percent working interest in these wells that
were completed in early January 2013.

"The Eagle Ford's potential reserves of 2.2 billion barrels of oil equivalent
represent the largest domestic crude oil find net to one company in 40 years.
Not only is 600 million net barrels a meaningful increase, this onshore U.S.
oil field is readily accessible to premium markets," Papa said. "With both the
technical acumen and high-quality assets, EOG is at the forefront in
developing this world-class shale oil resource."

Over the course of 2012, EOG's North Dakota wells showed marked productivity
improvement following the implementation of new completion techniques. On its
90,000 net acre Bakken Core, EOG confirmed that 320-acre well spacing is
economically sound, and it is very encouraged by 160-acre results. Recent
downspaced tests reflect a gain of approximately 30 percent to 70 percent in
cumulative production over earlier wells drilled in the field. The Fertile
51-0410H, in which EOG has a 94 percent working interest, had a maximum
initial production rate of 1,800 Bopd with 850 thousand cubic feet per day
(Mcfd) of rich natural gas. The first 160-acre spaced wells in the Core area,
the Wayzetta 022-1509H and 149-1509H, had maximum rates of 1,185 and 1,265
Bopd, respectively. EOG has 68 percent working interest in these wells.

Southwest of the Bakken Core in the Antelope Extension, the Hawkeye 01-2501H
and 102-2501H were completed to sales in early January 2013. These McKenzie
County wells, in which EOG has 75 percent working interest, were turned to
sales at 2,445 and 2,945 Bopd, respectively. In the Stateline area near the
North Dakota/Montana border, the Garden Coulee 001-1410H had an initial
production rate of 1,415 Bopd with 1,260 Mcfd of rich natural gas. EOG has a
74 percent working interest in this Williams County, N.D., well.

On the Texas side of the Delaware Basin, EOG confirmed a new shale play with
the completion of two horizontal Wolfcamp wells on its 114,000 net acre
position. In Reeves County, the Harrison Ranch #56-1002H and #56-1001H tested
at rates of 377 Bopd with 602 Bpd of NGLs and 3.9 MMcfd of natural gas and 635
Bopd with 480 Bpd of NGLs and 3.1 MMcfd of natural gas, respectively. EOG has
100 percent working interest in these wells. Based on the geologic
characteristics of the formation and the potential to drill multiple laterals
combined with data from over 200 previously drilled vertical wells on EOG's
acreage, estimated net potential reserves are approximately 800 MMBoe, a mix
of crude oil and liquids-rich natural gas. 

In southeastern New Mexico, the overall economics and size of EOG's horizontal
Delaware Basin Leonard Shale play improved last year due to strong well
results and decreased drilling costs. The Vaca 14 Fed #6H was completed in Lea
County at an initial rate of 1,290 Bopd with 255 Bpd of NGLs and 1.4 MMcfd of
natural gas. EOG has 100 percent working interest in this well. EOG has
increased the total net reserve potential on its 73,000 net acres from 65
MMBoe to 550 MMBoe, predicated on better well results and a 50 percent crude
oil yield. Total potential reserves on EOG's Delaware Basin horizontal
Wolfcamp and Leonard Shale plays are estimated to be 1.35 BnBoe, net.

During 2012, EOG secured premium pricing for some of its Bakken, Eagle Ford
and Permian Basin crude oil by expanding its innovative crude-by-rail
operations. Commissioned in April 2012, a crude oil unloading terminal at St.
James, La., enabled EOG to achieve average domestic crude oil realizations
exceeding benchmark West Texas Intermediate indices.

Reserves

EOG's total company net proved reserves were 1,811 MMBoe at December 31, 2012.
Total company net proved developed reserves decreased 2 percent, and total
North American net proved developed reserves were approximately flat with the
previous year, excluding the impact of property dispositions. Total company
net proved undeveloped reserves decreased 15 percent year over year due to low
natural gas prices in 2012 that caused essentially all of the previously
booked proved undeveloped reserves in EOG's North American dry gas properties
to be written off. Total proved liquids reserves increased 37 percent
year-over-year, comprising 56 percent of total company proved reserves at
December 31, 2012.

In 2012:

  oTotal reserve replacement from all sources – the ratio of net reserve
    additions from drilling, acquisitions, total revisions and dispositions to
    total production – was 268 percent at a total reserve replacement cost of
    $12.60 per barrel of oil equivalent (Boe), based on exploration and
    development expenditures of $6,921 million and excluding price-related
    revisions. (For the calculation of total reserve replacement and total
    reserve replacement costs, please refer to the attached tables.)
  oTotal liquids reserve replacement from all sources – the ratio of net
    reserve additions from drilling, acquisitions, total revisions and
    dispositions to total production – was 452 percent. (For the calculation
    of total liquids reserve replacement, please refer to the attached
    tables.)
  oReserve replacement from drilling – the ratio of extensions, discoveries
    and other additions to total production – was 238 percent. Crude oil
    reserve replacement from drilling in the United States was 442 percent.
    (For the calculation of reserve replacement from drilling, please refer to
    the attached tables.)
  oIn the United States, total reserve replacement from all sources,
    excluding price-related revisions, was 326 percent at a reserve
    replacement cost of $11.82 per Boe based on exploration and development
    expenditures of $6,362 million. (For the calculation of United States
    total reserve replacement and total reserve replacement costs, please
    refer to the attached tables.) In the United States, 80 percent of the
    reserve additions were liquids.

For the 25^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). For 2012, D&M prepared a complete independent
engineering analysis of properties comprising 87 percent of EOG's proved
reserves on a Boe basis.

Capital Structure

EOG's 2012 total cash capital expenditure program was approximately $7.5
billion. (Please refer to the attached tables for the reconciliation of total
expenditures (GAAP) to total cash expenditures (non-GAAP).) Through year-end
2012, EOG's cash proceeds from asset sales were approximately $1.3 billion.

At December 31, 2012, EOG's total debt outstanding was $6,312 million for a
debt-to-total capitalization ratio of 32 percent. Taking into account cash on
the balance sheet of $876 million at the end of the fourth quarter, EOG's net
debt was $5,436 million for a net debt-to-total capitalization ratio of 29
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).)

"2012 marked a turning point for EOG. We continued to develop our key crude
oil assets while locking up core natural gas and Combo acreage in the Barnett,
Leonard and Wolfcamp plays for the long term. In addition, we exited the
Kitimat LNG project," Papa said.

2013 Plans

EOG is targeting total company crude oil production growth of 28 percent with
a 23 percent increase in total liquids production in 2013. In North America,
natural gas production is expected to decrease 15 percent from 2012. EOG is
continuing to de-emphasize natural gas drilling in a weak price environment.
Driven by high margin, domestic crude oil production, overall EOG's total
company production is expected to increase 4 percent over 2012.

Estimated exploration and development expenditures for 2013 are expected to
range from $7.0 to $7.2 billion, including production facilities and midstream
expenditures, and excluding acquisitions. Overall asset sales are expected to
be approximately $550 million, of which $466 million has closed to date.

In 2013, EOG plans an active crude oil and liquids exploration program
focusing on increasing recovery of hydrocarbons in existing plays and pursuing
new greenfield opportunities. The majority of EOG's capital expenditures will
be directed toward its two key crude oil assets, the Eagle Ford and
Bakken/Three Forks. The Eagle Ford, where EOG estimates it will drill and
complete approximately 400 net wells, is expected to contribute the largest
share of company production growth in 2013. In the North Dakota Bakken Core
and Antelope Extension Bakken/Three Forks, plans are to test additional
downspaced drilling patterns. In its southeastern New Mexico horizontal
Leonard/West Texas Wolfcamp Shale plays, EOG anticipates operating a moderate
drilling program in 2013. Drilling activity in the new Delaware Basin Wolfcamp
play is expected to ramp up over the next two years to achieve significant
production growth for EOG beginning in 2015. Very minimal dry gas drilling
activity is expected in 2013.

"EOG's demonstrated ability to organically grow crude oil volumes should lead
to strong 2013 returns," Papa said. "Until other commodity prices strengthen,
we are directing EOG's capex dollars almost exclusively toward crude oil
exploration and development. Leading with our Eagle Ford and North Dakota
operations, EOG is well positioned to achieve its game plan, while identifying
strategic marketing advances that will further strengthen our position. With
the most attractive drilling program in our history, EOG has the critical
assets in place to make 2013 another outstanding year."

2013 Hedging

For the period January 1 through June 30, 2013, EOG has crude oil financial
price swap contracts in place for an average of 105,000 Bopd at a weighted
average price of $99.23 per barrel, excluding unexercised options. For the
period July 1 through December 31, 2013, EOG has an average of 93,000 Bopd
hedged at a weighted average price of $98.44 per barrel, excluding unexercised
options.

Despite very minimal dry natural gas drilling activity planned for 2013, EOG
has financial price swap contracts in place for 150,000 million British
thermal units per day of natural gas at aweighted average price of $4.79 per
million British thermal units, excluding unexercised options for the calendar
year. (For a comprehensive summary of EOG's crude oil and natural gas
derivative contracts, please refer to the attached tables.)

Dividend Increase

Following an increase in the common stock dividend in 2012, EOG's Board of
Directors has again increased the cash dividend on the common stock. Effective
with the dividend payable on April 30, 2013, to holders of record as of April
16, 2013, the quarterly dividend on the common stock will be $0.1875 per
share, an increase of 10 percent over the previous indicated annual rate. The
indicated annual rate of $0.75 per share reflects the 14^th increase in 14
years.

Conference Call Scheduled for Thursday, February 14, 2013

EOG's fourth quarter and full year 2012 results conference call will be
available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time)
on Thursday, February 14, 2013. To listen, log on to www.eogresources.com. The
webcast will be archived on EOG's website through Thursday, February 28, 2013.

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

This press release includes forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements, other than
statements of historical facts, including, among others, statements and
projections regarding EOG's future financial position, operations,
performance, business strategy, returns, budgets, reserves, levels of
production and costs 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" 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 and unknown risks,
events or circumstances that may be outside EOG's control. Important factors
that could cause EOG's actual results to differ materially from the
expectations reflected in EOG's forward-looking statements include, among
others:

  othe timing and extent of changes in prices for, and demand for, crude oil
    and condensate, natural gas liquids, natural gas and related commodities;
  othe extent to which EOG is successful in its efforts to acquire or
    discover additional reserves;
  othe extent to which EOG can optimize reserve recovery and economically
    develop its plays utilizing horizontal and vertical drilling, advanced
    completion technologies and hydraulic fracturing;
  othe extent to which EOG is successful in its efforts to economically
    develop its acreage in, and to produce reserves and achieve anticipated
    production levels from, its existing and future crude oil and natural gas
    exploration and development projects, given the risks and uncertainties
    and capital expenditure requirements inherent in drilling, completing and
    operating crude oil and natural gas wells and the potential for
    interruptions of development and production, whether involuntary or
    intentional as a result of market or other conditions;
  othe extent to which EOG is successful in its efforts to market its crude
    oil, natural gas and related commodity production;
  othe availability, proximity and capacity of, and costs associated with,
    gathering, processing, compression and transportation facilities;
  othe availability, cost, terms and timing of issuance or execution of, and
    competition for, mineral licenses and leases and governmental and other
    permits and rights-of-way;
  othe impact of, and changes in, government policies, laws and regulations,
    including tax laws and regulations, environmental laws and regulations
    relating to air emissions, waste disposal, hydraulic fracturing and access
    to and use of water, laws and regulations imposing conditions and
    restrictions on drilling and completion operations and laws and
    regulations with respect to derivatives and hedging activities;
  oEOG's ability to effectively integrate acquired crude oil and natural gas
    properties into its operations, fully identify existing and potential
    problems with respect to such properties and accurately estimate reserves,
    production and costs with respect to such properties;
  othe extent to which EOG's third-party-operated crude oil and natural gas
    properties are operated successfully and economically;
  ocompetition in the oil and gas exploration and production industry for
    employees and other personnel, equipment, materials and services and,
    related thereto, the availability and cost of employees and other
    personnel, equipment, materials and services;
  othe accuracy of reserve estimates, which by their nature involve the
    exercise of professional judgment and may therefore be imprecise;
  oweather, including its impact on crude oil and natural gas demand, and
    weather-related delays in drilling and in the installation and operation
    of production, gathering, processing, compression and transportation
    facilities;
  othe ability of EOG's customers and other contractual counterparties to
    satisfy their obligations to EOG and, related thereto, to access the
    credit and capital markets to obtain financing needed to satisfy their
    obligations to EOG;
  oEOG's ability to access the commercial paper market and other credit and
    capital markets to obtain financing on terms it deems acceptable, if at
    all, and to otherwise satisfy its capital expenditure requirements;
  othe extent and effect of any hedging activities engaged in by EOG;
  othe timing and extent of changes in foreign currency exchange rates,
    interest rates, inflation rates, global and domestic financial market
    conditions and global and domestic general economic conditions;
  opolitical developments around the world, 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; and
  othe other factors described under Item 1A, "Risk Factors," on pages 15
    through 23 of EOG's Annual Report on Form 10-K for the fiscal year ended
    December 31, 2011 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.

Effective January 1, 2010, 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, 2011,
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.  

Investors
Maire A. Baldwin
(713) 651-6EOG (651-6364)
Elizabeth M. Ivers
(713) 651-7132
Kimberly A. Matthews
(713) 571-4676

Media
K Leonard
(713) 571-3870

EOG RESOURCES, INC.
FINANCIAL REPORT
(Unaudited; in millions, except per share data)
                          Three Months Ended        Twelve Months Ended
                          December 31,              December 31,
                          2012         2011         2012          2011
Net Operating Revenues    $ 3,011.8    $ 2,773.0    $ 11,682.6    $ 10,126.1
Net Income (Loss)         $ (505.0)    $ 120.7      $ 570.3       $ 1,091.1
Net Income (Loss) Per
Share
 Basic                    $ (1.88)     $ 0.45       $ 2.13        $ 4.15
 Diluted                  $ (1.88)     $ 0.45       $ 2.11        $ 4.10
Average Number of Common
Shares
 Basic                      268.9        266.3        267.6         262.7
 Diluted                    268.9        269.5        270.8         266.3
SUMMARY INCOME STATEMENTS
(Unaudited; in thousands, except per share data)
                          Three Months Ended        Twelve Months Ended
                          December 31,              December 31,
                          2012         2011         2012          2011
Net Operating Revenues
 Crude Oil and Condensate $ 1,460,684  $ 1,189,250  $ 5,659,437   $ 3,838,284
 Natural Gas Liquids        208,493      240,260      727,177       779,364
 Natural Gas                418,329      479,825      1,571,762     2,240,540
 Gains on Mark-to-Market
 Commodity Derivative       66,416       145,514      393,744       626,053
 Contracts
 Gathering, Processing      903,404      654,489      3,096,694     2,115,792
 and Marketing
 Gains (Losses) on Asset    (55,474)     49,928       192,660       492,909
 Dispositions, Net
 Other, Net                 9,959        13,749       41,162        33,173
            Total           3,011,811    2,773,015    11,682,636    10,126,115
Operating Expenses
 Lease and Well             234,349      261,244      1,000,052     941,954
 Transportation Costs       169,789      122,046      601,431       430,322
 Gathering and Processing   25,542       25,283       97,945        80,727
 Costs
 Exploration Costs          48,660       31,042       185,569       171,658
 Dry Hole Costs             1,965        5,999        14,970        53,230
 Impairments               1,020,496    499,624      1,270,735     1,031,037
 Marketing Costs            880,451      644,687      3,035,494     2,072,137
 Depreciation, Depletion    786,344      693,527      3,169,703     2,516,381
 and Amortization
 General and                86,679       85,108       331,545       304,811
 Administrative
 Taxes Other Than Income    135,597      101,880      495,395       410,549
            Total           3,389,872    2,470,440    10,202,839    8,012,806
Operating Income (Loss)     (378,061)    302,575      1,479,797     2,113,309
Other Income (Expense),     (8,407)      (4,352)      14,495        6,853
Net
Income (Loss) Before
Interest Expense and        (386,468)    298,223      1,494,292     2,120,162
Income Taxes
Interest Expense, Net       59,354       56,591       213,552       210,363
Income (Loss) Before        (445,822)    241,632      1,280,740     1,909,799
Income Taxes
Income Tax Provision        59,177       120,934      710,461       818,676
Net Income (Loss)         $ (504,999)  $ 120,698    $ 570,279     $ 1,091,123
Dividends Declared per    $ 0.17       $ 0.16       $ 0.68        $ 0.64
Common Share



EOG RESOURCES, INC.
OPERATING HIGHLIGHTS
(Unaudited)
                                       Three Months Ended  Twelve Months Ended
                                       December 31,        December 31,
                                       2012      2011      2012       2011
Wellhead Volumes and Prices
Crude Oil and Condensate Volumes
(MBbld) ^(A)
      United States                       154.1    124.8      149.3     102.0
      Canada                              7.5      7.6        7.0       7.9
      Trinidad                            1.0      2.8        1.5       3.4
      Other International ^(B)            0.1      0.1        0.1       0.1
                   Total                  162.7    135.3      157.9     113.4
Average Crude Oil and Condensate
Prices ($/Bbl) ^(C)
      United States                    $  98.72  $ 96.33   $  98.38   $ 92.92
      Canada                              85.59    89.32      86.08     91.92
      Trinidad                            83.93    87.02      92.26     90.62
      Other International ^(B)            87.34    103.46     89.57     100.11
                   Composite              98.02    95.75      97.77     92.79
Natural Gas Liquids Volumes (MBbld)
^(A)
      United States                       57.0     49.6       55.1      41.5
      Canada                              0.8      1.1        0.8       0.9
                   Total                  57.8     50.7       55.9      42.4
Average Natural Gas Liquids Prices
($/Bbl) ^(C)
      United States                    $  35.36  $ 51.58   $  35.41   $ 50.37
      Canada                              42.50    49.16      44.13     52.69
                   Composite              35.45    51.53      35.54     50.41
Natural Gas Volumes (MMcfd) ^(A)
      United States                       981      1,085      1,034     1,113
      Canada                              84       124        95        132
      Trinidad                            335      313        378       344
      Other International ^(B)            8        11         9         13
                   Total                  1,408    1,533      1,516     1,602
Average Natural Gas Prices ($/Mcf)
^(C)
      United States                    $  2.93   $ 3.27    $  2.51    $ 3.92
      Canada                              2.98     3.14       2.49      3.71
      Trinidad                            4.12     3.87       3.72      3.53
      Other International ^(B)            5.75     5.70       5.71      5.62
                   Composite              3.23     3.40       2.83      3.83
Crude Oil Equivalent Volumes (MBoed)
^(D)
      United States                      374.6    355.3      376.6     329.1
      Canada                              22.3     29.3       23.6      30.7
      Trinidad                            56.8     54.9       64.5      60.7
      Other International ^(B)            1.4      2.0        1.7       2.2
                   Total                  455.1    441.5      466.4     422.7
Total MMBoe ^(D)                          41.9     40.6       170.7     154.3



(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,
                                                2012            2011
ASSETS
Current Assets
 Cash and Cash Equivalents                      $ 876,435       $ 615,726
 Accounts Receivable, Net                         1,656,618       1,451,227
 Inventories                                      683,187         590,594
 Assets from Price Risk Management Activities     166,135         450,730
 Income Taxes Receivable                          29,163          26,609
 Other                                            178,346         119,052
              Total                               3,589,884       3,253,938
Property, Plant and Equipment
 Oil and Gas Properties (Successful Efforts       38,126,298      33,664,435
 Method)
 Other Property, Plant and Equipment              2,740,619       2,149,989
              Total Property, Plant and           40,866,917      35,814,424
              Equipment
 Less: Accumulated Depreciation, Depletion and   (17,529,236)    (14,525,600)
 Amortization
              Total Property, Plant and           23,337,681      21,288,824
              Equipment, Net
Other Assets                                      409,013         296,035
Total Assets                                    $ 27,336,578    $ 24,838,797
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
 Accounts Payable                               $ 2,078,948     $ 2,033,615
 Accrued Taxes Payable                            162,083         147,105
 Dividends Payable                                45,802          42,578
 Liabilities from Price Risk Management           7,617           -
 Activities
 Deferred Income Taxes                            22,838          135,989
 Current Portion of Long-Term Debt                406,579         -
 Other                                            200,191         163,032
              Total                               2,924,058       2,522,319
Long-Term Debt                                    5,905,602       5,009,166
Other Liabilities                                 894,758         799,189
Deferred Income Taxes                             4,327,396       3,867,219
Commitments and Contingencies
Stockholders' Equity
 Common Stock, $0.01 Par, 640,000,000 Shares
 Authorized and 271,958,495
   Shares and 269,323,084 Shares Issued at        202,720         202,693
   December 31, 2012 and 2011, respectively
 Additional Paid in Capital                       2,500,340       2,272,052
 Accumulated Other Comprehensive Income          439,895         401,746
 Retained Earnings                                10,175,631      9,789,345
 Common Stock Held in Treasury, 326,264 Shares
 and 303,633 Shares at
   December 31, 2012 and 2011, respectively       (33,822)        (24,932)
              Total Stockholders' Equity          13,284,764      12,640,904
Total Liabilities and Stockholders' Equity      $ 27,336,578    $ 24,838,797



EOG RESOURCES, INC.
SUMMARY STATEMENTS OF CASH FLOWS
(Unaudited; in thousands)
                                                  Twelve Months Ended
                                                  December 31,
                                                  2012           2011
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
 Net Income                                      $ 570,279      $ 1,091,123
 Items Not Requiring (Providing) Cash
                Depreciation, Depletion and         3,169,703      2,516,381
                Amortization
                Impairments                        1,270,735      1,031,037
                Stock-Based Compensation Expenses   127,778        128,345
                Deferred Income Taxes               292,938        499,300
                Gains on Asset Dispositions, Net    (192,660)      (492,909)
                Other, Net                          672            15,139
 Dry Hole Costs                                     14,970         53,230
 Mark-to-Market Commodity Derivative Contracts
                Total Gains                         (393,744)      (626,053)
                Realized Gains                      711,479        180,701
 Excess Tax Benefits from Stock-Based               (67,035)       -
 Compensation
 Other, Net                                         14,411         26,454
 Changes in Components of Working Capital and Other Assets and Liabilities
                Accounts Receivable                 (178,683)      (339,780)
                Inventories                         (156,762)      (176,623)
                Accounts Payable                    (17,150)       351,087
                Accrued Taxes Payable               78,094         92,589
                Other Assets                        (118,520)      (23,625)
                Other Liabilities                   36,114         14,986
 Changes in Components of Working Capital
 Associated with Investing and Financing            74,158         237,028
 Activities
Net Cash Provided by Operating Activities           5,236,777      4,578,410
Investing Cash Flows
 Additions to Oil and Gas Properties                (6,735,316)    (6,294,397)
 Additions to Other Property, Plant and Equipment   (619,800)      (656,415)
 Proceeds from Sales of Assets                      1,309,776      1,433,137
 Changes in Components of Working Capital           (73,923)       (237,267)
 Associated with Investing Activities
Net Cash Used in Investing Activities               (6,119,263)    (5,754,942)
Financing Cash Flows
 Common Stock Sold                                  -              1,388,265
 Long-Term Debt Borrowings                          1,234,138      -
 Long-Term Debt Repayments                          -              (220,000)
 Dividends Paid                                     (181,080)      (167,169)
 Excess Tax Benefits from Stock-Based               67,035         -
 Compensation
 Treasury Stock Purchased                           (58,592)       (23,922)
 Proceeds from Stock Options Exercised and          82,887         35,913
 Employee Stock Purchase Plan
 Debt Issuance Costs                                (1,578)        (4,787)
 Repayment of Capital Lease Obligation              (2,824)        -
 Other, Net                                         (235)          239
Net Cash Provided by Financing Activities           1,139,751      1,008,539
Effect of Exchange Rate Changes on Cash             3,444          (5,134)
Increase (Decrease) in Cash and Cash Equivalents    260,709        (173,127)
Cash and Cash Equivalents at Beginning of Period    615,726        788,853
Cash and Cash Equivalents at End of Period        $ 876,435      $ 615,726



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, 2012 and 2011 reported Net Income (Loss) (GAAP) to reflect
actual net cash realized from financial commodity price transactions by
eliminating the unrealized mark-to-market gains from these transactions,
to add back charges related to impairments of certain of EOG's North
American assets in 2012 and 2011, to add back the write-off of fees
associated with revolving credit facilities cancelled in connection with
the establishment of a new revolving credit facility in the fourth quarter
of 2011 and to eliminate the net gains (losses) on asset dispositions
primarily in North America in 2012 and 2011. 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,
                     2012         2011         2012            2011
Reported Net Income  $ (504,999)  $ 120,698    $ 570,279       $ 1,091,123
(Loss) (GAAP)
Mark-to-Market (MTM)
Commodity Derivative
Contracts Impact
   Total Gains         (66,416)     (145,514)    (393,744)       (626,053)
   Realized Gains     155,533      96,936       711,479         180,701
            Subtotal   89,117       (48,578)     317,735         (445,352)
   After-Tax MTM       57,058       (31,101)     203,430         (285,136)
   Impact
Add: Impairments of
Certain North          849,371      249,084      887,946         516,198
American Assets, Net
of Tax
Add: Write-off of
Fees Associated with
Revolving Credit       -            3,656        -               3,656
Facilities, Net of
Tax
Less: Net (Gains)
Losses on Asset        35,599       (33,337)     (126,053)       (317,342)
Dispositions, Net of
Tax
Adjusted Net Income  $ 437,029    $ 309,000    $ 1,535,602     $ 1,008,499
(Non-GAAP)
Net Income (Loss)
Per Share (GAAP)
   Basic             $ (1.88)     $ 0.45       $ 2.13          $ 4.15
   Diluted           $ (1.88)     $ 0.45       $ 2.11          $ 4.10
Adjusted Net Income
Per Share (Non-GAAP)
   Basic             $ 1.62       $ 1.16       $ 5.74          $ 3.84
   Diluted           $ 1.61       $ 1.15       $ 5.67      (a) $ 3.79      (b)
Percentage Increase                              50%
- [(a) - (b)] / (b)
Average Number of
Common Shares
(GAAP)
   Basic               268,941      266,277      267,577         262,735
   Diluted             268,941      269,524      270,762         266,268
Average Number of
Shares (Non-GAAP)
   Basic               268,941      266,277      267,577         262,735
   Diluted             271,921      269,524      270,762         266,268



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, 2012 and 2011 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,
                     2012         2011         2012            2011
Net Cash Provided by
Operating Activities $ 1,227,187  $ 1,236,887  $ 5,236,777     $ 4,578,410
(GAAP)
Adjustments
   Exploration Costs
   (excluding
   Stock-Based         42,619       24,715       159,182         145,881
   Compensation
   Expenses)
   Excess Tax
   Benefits from       17,609       -            67,035          -
   Stock-Based
   Compensation
   Changes in
   Components of
   Working Capital
   and Other Assets
   and Liabilities
        Accounts       66,509       210,815      178,683         339,780
        Receivable
        Inventories    1,996        9,012        156,762         176,623
        Accounts       100,832      (105,702)    17,150          (351,087)
        Payable
        Accrued
        Taxes          (35,303)     8,650        (78,094)        (92,589)
        Payable
        Other Assets   (1,565)      (4,975)      118,520         23,625
        Other          3,757        22,036       (36,114)        (14,986)
        Liabilities
   Changes in
   Components of
   Working Capital
   Associated with     13,550       (103,801)    (74,158)        (237,028)
   Investing and
   Financing
   Activities
Discretionary Cash   $ 1,437,191  $ 1,297,637  $ 5,745,743 (a) $ 4,568,629 (b)
Flow (Non-GAAP)
Percentage Increase                              26%
- [(a) - (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, 2012 and 2011 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 realized from financial
commodity derivative transactions by eliminating the unrealized
mark-to-market (MTM) gains from these transactions and to eliminate the
net gains (losses) on asset dispositions primarily in North America in
2012 and 2011. 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,
                2012         2011          2012              2011
Income (Loss)
Before Interest
Expense and     $ (386,468)  $ 298,223     $ 1,494,292       $ 2,120,162
Income Taxes
(GAAP)
Adjustments:
Depreciation,
Depletion and     786,344      693,527       3,169,703         2,516,381
Amortization
Exploration       48,660       31,042        185,569           171,658
Costs
Dry Hole Costs    1,965        5,999         14,970            53,230
Impairments      1,020,496    499,624       1,270,735         1,031,037
   EBITDAX        1,470,997    1,528,415     6,135,269         5,892,468
   (Non-GAAP)
Total Gains on
MTM Commodity     (66,416)     (145,514)     (393,744)         (626,053)
Derivative
Contracts
Realized Gains
on MTM
Commodity         155,533      96,936        711,479           180,701
Derivative
Contracts
Net Losses
(Gains) on        55,474       (49,928)      (192,660)         (492,909)
Asset
Dispositions
   Adjusted
   EBITDAX      $ 1,615,588  $ 1,429,909   $ 6,260,344 (a) $ 4,954,207 (b)
   (Non-GAAP)
Percentage
Increase - [(a)                              26%
- (b)] / (b)



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 February 13, 2013, with notional volumes expressed in
Bbld and MMBtud and prices expressed in $/Bbl and $/MMBtu. EOG accounts for
financial commodity derivative contracts using the mark-to-market accounting
method.
CRUDE OIL DERIVATIVE CONTRACTS
                                                                 Weighted
                                                  Volume ^(1)   Average Price
                                                  (Bbld)        ($/Bbl)
    2013
    January 2013 (closed)                         101,000        $99.29
    February 1, 2013 through April 30, 2013       109,000        99.17
    May 1, 2013 through June 30, 2013             101,000        99.29
    July 1, 2013 through December 31, 2013        93,000         98.44
    EOG has entered into crude oil derivative contracts which give
    counterparties the option to extend certain current derivative contracts
    for additional three-month or six-month periods. Options covering a
    notional volume of 8,000 Bbld are exercisable on April 30, 2013. If the
    counterparties exercise all such options, the notional volume of EOG's
    existing crude oil derivative contracts will increase by 8,000 Bbld at an
    average price of $97.66 per barrel for the period May 1, 2013 through July
    31, 2013. Options covering a notional volume of 62,000 Bbld are
(1) exercisable on June 28, 2013. If the counterparties exercise all such
    options, the notional volume of EOG's existing crude oil derivative
    contracts will increase by 62,000 Bbld at an average price of $100.24 per
    barrel for the period July 1, 2013 through December 31, 2013. Options
    covering a notional volume of 54,000 Bbld are exercisable on December 31,
    2013. If the counterparties exercise all such options, the notional
    volume of EOG's existing crude oil derivative contracts will increase by
    54,000 Bbld at an average price of $98.91 per barrel for the period
    January 1, 2014 through June 30, 2014.
NATURAL GAS DERIVATIVE CONTRACTS
                                                                 Weighted
                                                  Volume         Average Price
                                                  (MMBtud)      ($/MMBtu)
    2013^(2)
    January 1, 2013 through February 28, 2013     150,000        $4.79
    (closed)
    March 1, 2013 through December 31, 2013       150,000        4.79
    2014^(3)
    EOG has entered into natural gas derivative contracts which give
    counterparties the option of entering into derivative contracts at future
    dates. Such options are exercisable monthly up until the settlement date
(2) 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 150,000 MMBtud at an average price of $4.79 per
    MMBtu for the period from March 1, 2013 through December 31, 2013.
    In July 2012, EOG settled its natural gas financial price swap contracts
    for the period January 1, 2014 through December 31, 2014. In connection
    with these contracts, the counterparties retain an option of entering into
(3) derivative contracts at future dates. Such options are exercisable
    monthly up until the settlement date of each monthly contract. If the
    counterparties exercise all such options, the notional volume of EOG's
    existing natural gas derivative contracts will increase by 150,000 MMBtud
    at an average price of $4.79 per MMBtu for each month of 2014.
    Bbld                      Barrels per day.
    $/Bbl                     Dollars per barrel.
    MMBtud                    Million British thermal units per day.
    $/MMBtu                   Dollars per million British thermal units.
    MMBtu                     Million British thermal units.



EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF NET DEBT (NON-GAAP) AND TOTAL
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.
                                         December 31,
                                         2012
Total Stockholders' Equity - (a)         $           13,285
Current and Long-Term Debt - (b)                     6,312
Less: Cash                                          (876)
Net Debt (Non-GAAP) - (c)                            5,436
Total Capitalization (GAAP) - (a) + (b)  $           19,597
Total Capitalization (Non-GAAP) - (a) +  $           18,721
(c)
Debt-to-Total Capitalization (GAAP) -                32%
(b) / [(a) + (b)]
Net Debt-to-Total Capitalization                     29%
(Non-GAAP) - (c) / [(a) + (c)]



EOG RESOURCES, INC.
RESERVES SUPPLEMENTAL DATA
(Unaudited)
2012 NET PROVED RESERVES RECONCILIATION SUMMARY
               United             North                Other  Total
               States   Canada  America  Trinidad  Int'l  Int'l  Total
CRUDE OIL &
CONDENSATE
(MMBbls)
Beginning      495.3      18.6      513.9      3.5         0.1      3.6      517.5
Reserves
Revisions     4.1        (2.5)     1.6        0.1         -        0.1      1.7
Purchases in   1.0        -         1.0        -           -        -        1.0
place
Extensions,
discoveries    241.2      5.7       246.9      -           8.8      8.8      255.7
and other
additions
Sales in place (16.0)     (1.3)     (17.3)     -           -        -        (17.3)
Production    (54.6)     (2.6)     (57.2)     (0.6)       -        (0.6)    (57.8)
Ending         671.0      17.9      688.9      3.0         8.9      11.9     700.8
Reserves
NATURAL GAS
LIQUIDS
(MMBbls)
Beginning      226.6      1.2       227.8      -           -        -        227.8
Reserves
Revisions     47.3       0.6       47.9       -           -        -        47.9
Purchases in   0.6        -         0.6        -           -        -        0.6
place
Extensions,
discoveries    71.4       0.2       71.6       -           -        -        71.6
and other
additions
Sales in place (7.3)      (0.1)     (7.4)      -           -        -        (7.4)
Production    (20.2)     (0.3)     (20.5)     -           -        -        (20.5)
Ending         318.4      1.6       320.0      -           -        -        320.0
Reserves
NATURAL GAS
(Bcf)
Beginning      6,045.8    1,035.9   7,081.7    750.7       18.5     769.2    7,850.9
Reserves
Revisions     (1,736.0)  (894.5)   (2,630.5)  (24.1)      1.6      (22.5)   (2,653.0)
Purchases in   14.8       -         14.8       -           -        -        14.8
place
Extensions,
discoveries    477.8      -         477.8      -           0.3      0.3      478.1
and other
additions
Sales in place (386.2)    (8.5)     (394.7)    -           -        -        (394.7)
Production    (380.2)    (34.6)    (414.8)    (138.4)     (3.4)    (141.8)  (556.6)
Ending         4,036.0    98.3      4,134.3    588.2       17.0     605.2    4,739.5
Reserves
OIL
EQUIVALENTS
(MMBoe)
Beginning      1,729.5    192.5     1,922.0    128.6       3.2      131.8    2,053.8
Reserves
Revisions     (237.9)    (151.0)   (388.9)    (3.9)       0.2      (3.7)    (392.6)
Purchases in   4.1        -         4.1        -           -        -        4.1
place
Extensions,
discoveries    392.2      5.8       398.0      -           8.9      8.9      406.9
and other
additions
Sales in place (87.6)     (2.8)     (90.4)     -           -        -        (90.4)
Production    (138.2)    (8.7)     (146.9)    (23.6)      (0.6)    (24.2)   (171.1)
Ending         1,662.1    35.8      1,697.9    101.1       11.7     112.8    1,810.7
Reserves
Net Proved
Developed
Reserves
(MMBoe)
 At
December 31,   877.3      58.5      935.8      103.7       3.2      106.9    1,042.7
2011
 At
December 31,   840.6      24.3      864.9      81.8        3.1      84.9     949.8
2012
2012 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ Millions)
               United             North                Other  Total
               States   Canada  America  Trinidad  Int'l  Int'l  Total
Acquisition
Cost of        $  471.3  $        $         $        $       $       $  505.3
Unproved                  33.6     504.9     1.0         (0.6)    0.4
Properties
Exploration    333.6      38.5      372.1      19.6        53.9     73.5     445.6
Costs
Development    5,576.9    245.7     5,822.6    31.1        135.9    167.0    5,989.6
Costs
Total Drilling 6,381.8    317.8     6,699.6    51.7        189.2    240.9    6,940.5
Acquisition
Cost of Proved 0.7        -         0.7        -           -        -        0.7
Properties
Total
Exploration &  6,382.5    317.8     6,700.3    51.7        189.2    240.9    6,941.2
Development
Expenditures
Gathering,
Processing and 633.4      50.2      683.6      0.2         1.8      2.0      685.6
Other
Asset
Retirement     80.5       33.3      113.8      1.5         11.7     13.2     127.0
Costs
Total          7,096.4    401.3     7,497.7    53.4        202.7    256.1    7,753.8
Expenditures
Proceeds from  (1,182.3)  (127.5)   (1,309.8)  -           -        -        (1,309.8)
Sales in Place
Net            $5,914.1   $        $ 6,187.9  $   53.4  $202.7   $256.1   $6,444.0
Expenditures              273.8
RESERVE
REPLACEMENT
COSTS ($ / Boe
) *
Total
Drilling,      $  16.22  $        $         $       $21.26   $27.07   $  17.01
Before                    54.79     16.78     -
Revisions
All-in Total,             $                   $ 
Net of         $  40.17  (2.19)    $ 506.06  (13.26)     $20.79   $46.33   $ 376.14
Revisions
All-in Total,
Excluding      $  11.82  $        $         $          $20.79   $41.53   $  12.60
Revisions Due             62.31     12.29     (15.67)
to Price
RESERVE
REPLACEMENT *
Drilling Only  284%       67%       271%       0%          1,483%   37%      238%
All-in Total,
Net of         51%        -1,701%   -53%       -17%        1,517%   21%      -42%
Revisions &
Dispositions
All-in Total,
Excluding      326%       26%       308%       -14%        1,517%   24%      268%
Revisions Due
to Price
All-in Total,  458%       90%       444%       17%         0%       1,483%   452%
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. The following chart also reconciles
Total Expenditures (GAAP) to Total Cash Expenditures (Non-GAAP) in respect of
EOG's 2012 capital expenditure program.
             United            North                Other  Total
             States  Canada  America  Trinidad  Int'l  Int'l  Total
Total Costs
Incurred in
Exploration            $ 
and          $6,463.0  351.1     $ 6,814.1  $   53.2  $200.9   $254.1   $7,068.2
Development
Activities
(GAAP)
Less: Asset
Retirement   (80.5)    (33.3)    (113.8)    (1.5)       (11.7)   (13.2)   (127.0)
Costs
 Non-Cash
 Acquisition
 Costs of    (20.3)    -         (20.3)     -           -        -        (20.3)
 Unproved
 Properties
 Acquisition
 Cost of     (0.7)     -         (0.7)      -           -        -        (0.7)
 Proved
 Properties
Total
Exploration
&
Development            $ 
Expenditures $6,361.5  317.8     $ 6,679.3  $   51.7  $189.2   $240.9   $6,920.2
for Drilling
Only
(Non-GAAP)
(a)
Total Costs
Incurred in
Exploration            $ 
and          $6,463.0  351.1     $ 6,814.1  $   53.2  $200.9   $254.1   $7,068.2
Development
Activities
(GAAP)
Less: Asset
Retirement   (80.5)    (33.3)    (113.8)    (1.5)       (11.7)   (13.2)   (127.0)
Costs
 Non-Cash
 Acquisition
 Costs of    (20.3)    -         (20.3)     -           -        -        (20.3)
 Unproved
 Properties
Total
Exploration
&                      $ 
Development  $6,362.2  317.8     $ 6,680.0  $   51.7  $189.2   $240.9   $6,920.9
Expenditures
(Non-GAAP)
(b)
Total                  $ 
Expenditures $7,096.4  401.3     $ 7,497.7  $   53.4  $202.7   $256.1   $7,753.8
(GAAP)
Less: Asset
Retirement   (80.5)    (33.3)    (113.8)    (1.5)       (11.7)   (13.2)   (127.0)
Costs
 Non-Cash
 Gathering,
 Processing
 & Other     (65.8)    -         (65.8)     -           -        -        (65.8)
 Costs
 (Capital
 Lease)
 Non-Cash
 Acquisition
 Costs of    (20.3)    -         (20.3)     -           -        -        (20.3)
 Unproved
 Properties
Total Cash             $ 
Expenditures $6,929.8  368.0     $ 7,297.8  $   51.9  $191.0   $242.9   $7,540.7
(Non-GAAP)
Net Proved
Reserve
Additions
From All
Sources -
Oil
Equivalents
(MMBoe)
Revisions
due to price (379.9)   (150.3)   (530.2)    (0.6)       -        (0.6)    (530.8)
(c)
Revisions
other than   142.0     (0.7)     141.3      (3.3)       0.2      (3.1)    138.2
price
Purchases in 4.1       -         4.1        -           -        -        4.1
place
Extensions,
discoveries
and other    392.2     5.8       398.0      -           8.9      8.9      406.9
additions
(d)
Total Proved
Reserve      158.4     (145.2)   13.2       (3.9)       9.1      5.2      18.4
Additions
(e)
Sales in     (87.6)    (2.8)     (90.4)     -           -        -        (90.4)
place
Net Proved
Reserve
Additions    70.8      (148.0)   (77.2)     (3.9)       9.1      5.2      (72.0)
From All
Sources (f)
Production   138.2     8.7       146.9      23.6        0.6      24.2     171.1
(g)
RESERVE
REPLACEMENT
COSTS ($ /
BOE)
Total
Drilling,    $        $        $         $                         $ 
Before       16.22     54.79     16.78     -           $21.26   $27.07   17.01
Revisions (a
/ d)
All-in
Total, Net   $        $        $ 506.06  $          $20.79   $46.33   $ 376.14
of Revisions 40.17     (2.19)               (13.26)
(b / e)
All-in
Total,
Excluding    $        $        $         $                            $ 
Revisions    11.82     62.31     12.29     (15.67)     $20.79   $41.53   12.60
Due to Price
(b / (e -
c))
RESERVE
REPLACEMENT
Drilling
Only (d /    284%      67%       271%       0%          1,483%   37%      238%
g)
All-in
Total, Net
of Revisions 51%       -1,701%   -53%       -17%        1,517%   21%      -42%
&
Dispositions
(f / g)
All-in
Total,
Excluding
Revisions    326%      26%       308%       -14%        1,517%   24%      268%
Due to Price
((f - c ) /
g)
Net Proved
Reserve
Additions
From All
Sources -
Liquids
(MMBbls)
Revisions    51.4      (1.9)     49.5       0.1         -        0.1      49.6
Purchases in 1.6       -         1.6        -           -        -        1.6
place
Extensions,
discoveries
and other    312.6     5.9       318.5      -           8.8      8.8      327.3
additions
(h)
Total Proved
Reserve      365.6     4.0       369.6      0.1         8.8      8.9      378.5
Additions
Sales in     (23.3)    (1.4)     (24.7)     -           -        -        (24.7)
place
Net Proved
Reserve
Additions    342.3     2.6       344.9      0.1         8.8      8.9      353.8
From All
Sources (i)
Production   74.8      2.9       77.7       0.6         -        0.6      78.3
(j)
RESERVE
REPLACEMENT
- LIQUIDS
Drilling
Only (h /    418%      203%      410%       0%          0%       1,467%   418%
j)
All-in
Total, Net
of Revisions 458%      90%       444%       17%         0%       1,483%   452%
&
Dispositions
(i / j)



EOG RESOURCES, INC.
 FIRST QUARTER AND FULL YEAR 2013 FORECAST AND BENCHMARK COMMODITY PRICING
 (a) First Quarter and Full Year 2013 Forecast

The forecast items for the first quarter and full year 2013 set forth below
for EOG Resources, Inc. (EOG) are based on current available information and
expectations as of the date of the accompanying press release. EOG undertakes
no obligation, other than as required by applicable law, to update or revise
this forecast, whether as a result of new information, subsequent events,
anticipated or unanticipated circumstances or otherwise. This forecast, which
should be read in conjunction with the accompanying press release and EOG's
related Current Report on Form 8-K filing, replaces and supersedes any
previously issued guidance or forecast.

 (b) Benchmark Commodity Pricing

EOG bases United States, Canada and Trinidad crude oil and condensate price
differentials upon the West Texas Intermediate crude oil price at Cushing,
Oklahoma, using the simple average of the NYMEX settlement prices for each
trading day within the applicable calendar month.

EOG bases United States and Canada natural gas price differentials upon the
natural gas price at Henry Hub, Louisiana, using the simple average of the
NYMEX settlement prices for the last three trading days of the applicable
month.
                                         ESTIMATED RANGES
                                                 (Unaudited)
                           1Q 2013                           Full Year 2013
Daily Production
 Crude Oil and Condensate Volumes (MBbld)
 United States    160.0    -    172.0               180.0  -   197.0
 Canada           6.5      -    7.5                 6.0    -   7.0
 Trinidad         0.8      -    1.5                 1.0    -   2.0
 Other            0.0      -    0.0                 5.0    -   6.0
International
 Total       167.3    -    181.0               192.0  -   212.0
 Natural Gas Liquids Volumes (MBbld)
 United States    52.0     -    56.0                55.5   -   66.0
 Canada           0.5      -    0.9                 0.5    -   0.8
 Total       52.5     -    56.9                56.0   -   66.8
 Natural Gas Volumes (MMcfd)
 United States    900      -    930                 865    -   905
 Canada           70       -    85                  64     -   80
 Trinidad         335      -    365                 350    -   375
 Other            8        -    11                  8      -   10
International
 Total       1,313    -    1,391               1,287  -   1,370
 Crude Oil Equivalent Volumes
(MBoed)
 United           362.0    -    383.0               379.7  -   413.8
States
 Canada           18.7     -    22.6                17.2   -   21.1
 Trinidad         56.6     -    62.3                59.3   -   64.5
 Other            1.3      -    1.8                 6.3    -   7.7
International
 Total       438.6    -    469.7               462.5  -   507.1
Operating Costs
 Unit Costs ($/Boe)
 Lease and   $    6.27     -  $ 6.57          $     6.20   - $ 6.75
Well
             $    4.55     -  $ 4.80          $     4.40   - $ 4.80
Transportation Costs

Depreciation,         $    20.75    -  $ 21.55         $     20.15  - $ 21.15
Depletion and
Amortization
Expenses ($MM)
 Exploration, Dry $    127.0    -  $ 142.0         $     500.0  - $ 550.0
Hole and Impairment
 General and      $    85.0     -  $ 90.0          $     365.0  - $ 385.0
Administrative
 Gathering and    $    28.0     -  $ 32.0          $     100.0  - $ 130.0
Processing
 Capitalized      $    12.0     -  $ 18.0          $     50.0   - $ 62.0
Interest
 Net Interest     $    55.0     -  $ 60.0          $     205.0  - $ 225.0
Taxes Other Than
Income (% of Wellhead      6.2%     -    6.6%                5.6%   -   6.6%
Revenue)
Income Taxes
 Effective Rate       35%      -    45%                 35%    -   45%
 Current Taxes    $    50       -  $ 65            $     230    - $ 250
($MM)
Capital Expenditures ($MM) - FY 2013 (Excluding
Non-cash Items)
 Exploration and Development, Excluding            $     5,900  - $ 6,000
Facilities
 Exploration and Development                       $     710    - $ 770
Facilities
 Gathering, Processing and Other                   $     435    - $ 465
Pricing - (Refer to Benchmark Commodity Pricing
in text)
 Crude Oil and Condensate ($/Bbl)

Differentials
 United $    (8.50)   -  $ (12.50)       $     (4.50) - $ (9.50)
States - above WTI
 Canada $    9.50     -  $ 11.50         $     7.85   - $ 10.85
- below WTI
        $    1.05     -  $ 3.05          $     1.25   - $ 4.25
Trinidad - below WTI
 Natural Gas Liquids
 Realizations as % of WTI
            35%      -    37%                 34%    -   38%
United States
            50%      -    52%                 50%    -   54%
Canada
 Natural Gas ($/Mcf)

Differentials
 United
States - below NYMEX  $    0.35     -  $ 0.55          $     0.30   - $ 0.60
Henry Hub
 Canada
- below NYMEX Henry   $    0.11     -  $ 0.21          $     0.17   - $ 0.42
Hub

Realizations
        $    3.12     -  $ 3.62          $     2.55   - $ 3.25
Trinidad
 Other  $    4.80     -  $ 5.30          $     4.70   - $ 5.60
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