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EOG Resources Reports 2011 Results, Increases Eagle Ford Reserve Potential and Increases Dividend

FOR IMMEDIATE RELEASE: February 16, 2012

HOUSTON, Feb. 16, 2012 /PRNewswire/ --

  • Achieves 9.4 Percent Year-Over-Year Total Company Production Growth
  • Reports 52 Percent North American Annual Crude Oil, Condensate and Natural Gas Liquids Growth with 48 Percent Increase in Total Company Liquids Volumes Year-Over-Year
  • Delivers Strong Year-Over-Year Growth in EPS, EBITDAX and Discretionary Cash Flow
  • Increases Eagle Ford Potential Recoverable Reserve Estimate by 78 Percent — from 900 MMboe to 1,600 MMboe, Net After Royalty
  • Realizes Continued Drilling Success in Permian Basin Wolfcamp and Leonard Shale
  • Raises Total Company Proved Reserves 5.3 Percent at Attractive Finding Costs
  • Increases 2012 Total Company Organic Liquids Growth Target from 27 Percent to 30 Percent
  • Raises Dividend on Common Stock for 13th Time in 13 Years

EOG Resources, Inc. (NYSE: EOG) (EOG) today reported fourth quarter 2011 net income of $120.7 million, or $0.45 per share. This compares to fourth quarter 2010 net income of $53.7 million, or $0.21 per share. For the full year 2011, EOG reported net income of $1,091.1 million, or $4.10 per share, as compared to $160.7 million, or $0.63 per share, for the full year 2010.

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 quarter was $309.0 million, or $1.15 per share. Adjusted non-GAAP net income for the fourth quarter 2010 was $92.0 million, or $0.36 per share. The results for the fourth quarter 2011 included a $249.1 million, net of tax ($0.93 per share) impairment of certain North American non-core natural gas assets, gains on asset dispositions of $33.3 million, net of tax ($0.12 per share), the write-off of fees associated with revolving credit facilities of $3.7 million, net of tax ($0.01 per share) and a previously disclosed non-cash net gain of $145.5 million ($93.2 million after tax, or $0.35 per share) on the mark-to-market of financial commodity contracts. During the quarter, the net cash inflow related to financial commodity contracts was $96.9 million ($62.0 million after tax, or $0.23 per share).

On a similar basis, eliminating the items detailed in the attached table, adjusted non-GAAP net income for the full year 2011 was $1,008.5 million, or $3.79 per share, and for the full year 2010 was $296.4 million, or $1.16 per share. (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)

"EOG had an exceptional year in 2011 with a 551 percent increase in earnings per share versus 2010. This solidifies the completion of our goal of becoming an oil company. These strong returns are one of the traditional hallmarks of EOG," said Mark G. Papa, Chairman and Chief Executive Officer.

Through its focus on higher margins and returns, EOG posted strong financial metrics year-over-year in adjusted non-GAAP earnings per share, adjusted EBITDAX and discretionary cash flow. Compared to 2010, adjusted non-GAAP earnings per share increased 227 percent, adjusted EBITDAX increased 55 percent and discretionary cash flow rose 52 percent. (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).)

2011 Operational Highlights

For the full year 2011, total company production increased 9.4 percent compared to 2010, driven by 52 percent organic growth in North American crude oil, condensate and natural gas liquids, and a 48 percent increase in total company liquids production. During the fourth quarter, United States crude oil and condensate production rose 68 percent compared to 2010, contributing to a 61 percent increase for the full year 2011.

Crude Oil and Liquids Activity

2011 marked a significant year in the development of EOG's single largest asset, the South Texas Eagle Ford. Production at year-end was 66 thousand barrels of oil equivalent per day, net, 78 percent of which was crude oil.

Starting 2011 with a 12-rig drilling program that ramped up to 26 rigs in December, EOG drilled and completed 244 net wells during the year with a focus on optimizing completion techniques, in addition to reducing drilling days and overall well costs. Moving into development mode early in 2011, EOG began shifting its attention to increasing recovery of the oil-in-place in the field. To test the impact of well spacing on reserve recoveries, EOG drilled eight pilot programs that included 33 total wells. Based on production analysis from these pilots and reservoir modeling, EOG is now pursuing development drilling on 65 to 90-acre spacing, significantly tighter than the original density of 130 acres between wells.

After taking into account both the excellent results from the 375 wells it has drilled to date across its 120-mile acreage position and the results from the down-spaced drilling tests, EOG has increased its estimated potential reserves in the Eagle Ford from 900 million barrels of oil equivalent (MMboe) to 1,600 MMboe, net after royalty (NAR). The 700 MMBoe, NAR, or 78 percent increase represents an estimated 6 percent recovery factor. On its 572,000 net acres in the prolific oil window, EOG has identified approximately 3,200 remaining drilling locations and increased its average per well estimate to 450 thousand barrels of oil equivalent (MBoe), NAR.

EOG's well results in the Eagle Ford continue to lead the industry. In Gonzales County, the Henkhaus Unit #1H, #2H, #3H, #4H, #6H and #7H wells were drilled on a pattern of 65-acre spacing. The six wells were completed to sales at individual initial production rates ranging from 2,424 to 3,733 barrels of oil per day (Bopd) with 442 to 679 barrels per day (Bpd) of natural gas liquids (NGLs) and 2.2 to 3.4 million cubic feet per day (MMcfd) of natural gas per well. The Mitchell Unit #3H, #4H, #5H, #6H, #7H and #8H wells, which were also drilled as down-spaced pilots, began initial production at 2,833 to 3,527 Bopd with 275 to 485 Bpd of NGLs and 1.4 to 2.4 MMcfd of natural gas per well. The Meyer #3H, #4H, #5H, #8H and #9H wells had individual peak oil rates ranging from 1,647 to 2,813 Bopd with 199 to 413 Bpd of NGLs and 1.0 to 2.1 MMcfd of natural gas. EOG has 100 percent working interest in these 17 Gonzales County wells.

"With tremendous resource potential still remaining on our acreage, we continue to test and apply techniques that will increase the oil recovery and potential of the Eagle Ford, our crown jewel. This strategy takes us into the next inning of development. By concentrating our efforts on getting more oil out of the ground early in the development phase, we are taking a good asset and making it great," Papa said. "Looking across the industry, we believe EOG's Eagle Ford position represents the largest domestic net oil discovery in 40 years and the highest rate of return play in North America today."

In the Fort Worth Barnett Shale Combo, EOG's second largest driver of liquids growth during 2011, total liquids production increased 107 percent compared to 2010, driven by a 124 percent increase in crude oil and condensate production. In Montague County, a pattern of five horizontal wells, the Badger A Unit #1H, B Unit #2H, C Unit #3H, D Unit #4H and E Unit #5H showed initial peak oil production rates ranging from 525 to 659 Bopd with 106 to 205 Bpd of NGLs and 704 to 1,361 Mcfd (thousand cubic feet per day) of natural gas per well. EOG has 100 percent working interest in the wells, which had an average peak crude oil production rate of 604 Bopd per well. A series of 10 McKown wells drilled in Cooke County, began producing to sales at an average oil rate of 689 Bopd, with 210 Bpd of NGLs and 1.4 MMcfd of natural gas per well. EOG has 93 percent working interest in these wells.  

During 2011, EOG expanded its core holdings in the Barnett Combo by approximately 25,000 acres to 200,000 net acres. Following the success of its drilling program last year, EOG expects the Barnett Combo to be its second largest liquids production growth contributor again in 2012.

In the West Texas Permian Basin, EOG increased drilling activity in the Wolfcamp formation during the second half of 2011 in preparation for a more active year in 2012. EOG reported success from the upper Wolfcamp zone. The University 9 #2803H in Reagan County, 25 miles west of its current middle Wolfcamp activity began production at 883 Bopd with 68 Bpd of NGLs and 388 Mcfd of natural gas. EOG has a 100 percent working interest in the well. In Irion County, the University 43 #0902H and 40A #0402H were completed in the middle Wolfcamp zone at initial oil rates of 1,088 and 1,076 Bopd, respectively. In addition to the strong oil production, the wells were turned to sales with 86 and 129 Bpd of NGLs and 489 and 736 Mcfd of natural gas, respectively. EOG has 90 and 85 percent working interest in the wells, respectively. On the border between Irion and Crockett counties, the University 40 #1309H and 38 #0601H began production at 1,738 and 1,077 Bopd with 137 and 119 Bpd of NGLs and 779 and 678 Mcfd of natural gas, respectively. EOG has 88 percent working interest in these wells. EOG plans to operate a four-rig drilling program in the Wolfcamp during 2012.

In the New Mexico Leonard Shale, EOG reported drilling success from Lea County with the Caballo 23 Fed #4H and #6H. The wells, in which EOG has 86 percent working interest, initially produced at 932 and 750 Bopd with 116 and 99 Bpd of NGLs and 636 and 545 Mcfd of natural gas, respectively. During 2012, EOG is positioned to increase its drilling activity in the Leonard Shale with a year-long two-rig program.

Consistent with its game plan to increase recovery rates in existing fields, during 2011 EOG continued infill drilling on its core acreage in the North Dakota Bakken Parshall Field, which it discovered in 2006. Although originally developed on 640-acre spacing, EOG has successfully tested 320-acre down-spacing in various areas and around the perimeters of the field. A recent well in Mountrail County, the Fertile 48-0905H, in which EOG has a 96 percent working interest, was completed at an initial rate of 1,324 Bopd. Also in Mountrail County, the Liberty 24-2531H and Liberty LR 20-26H were drilled on 320-acre spacing. The wells, in which EOG has 82 and 95 percent working interest, respectively, were turned to sales at initial crude oil rates of 1,507 and 1,165 Bopd, respectively. Over the course of 2012, EOG will continue its efforts to increase recovery of the oil-in-place on its Bakken acreage through further down-spacing tests and the initiation of a secondary recovery pilot project.

Reserves

EOG's total company net proved reserves for 2011 increased 5.3 percent over the prior year from 1,950 to 2,054 MMBoe, all organic. Total liquids proved reserves increased 39 percent year-over-year. Excluding the impact of property dispositions, total company and total North American net proved developed reserves increased 8.8 percent and 8.2 percent, respectively. Total liquids proved reserves, as a percentage of total company proved reserves, increased from 28 percent to 36 percent.

In 2011:

  • Total reserve replacement from all sources — the ratio of net reserve additions from drilling, acquisitions, total revisions and dispositions to total production — was 167 percent at a total reserve replacement cost of $19.68 per barrel of oil equivalent (Boe), based on exploration and development expenditures of $6,466 million. (For the calculation of total reserve replacement and total reserve replacement costs, please refer to the attached tables.)  
  • Total liquids reserve replacement from all sources — the ratio of net reserve additions from drilling, acquisitions, total revisions and dispositions to total production — was 465 percent. (For the calculation of total liquids reserve replacement, please refer to the attached tables.)  
  • Reserve replacement from drilling — the ratio of extensions, discoveries and other additions to total production — was 248 percent. (Pease refer to the attached tables.)  
  • In the United States, total reserve replacement from all sources was 216 percent at a reserve replacement cost of $18.00 per Boe based on exploration and development expenditures of $5,969 million. (For the calculation of U.S. total reserve replacement and total reserve replacement costs, please refer to the attached tables.) In the United States, 72 percent of the reserve additions were liquids.

For the 24th 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 2011, D&M prepared a complete independent engineering analysis of properties containing 85 percent of EOG's proved reserves on a Boe basis.

Natural Gas Activity

EOG is continuing to de-emphasize dry natural gas drilling activity on its Haynesville, Marcellus and Horn River acreage to pursue higher rate of return opportunities in its crude oil and liquids-rich unconventional resource plays. Since 2008, EOG's North American natural gas production has declined annually, with a 7 percent reduction from 2010 to 2011. Because EOG's outlook for natural gas prices is weak for the next several years, EOG plans to invest the minimum amount of capital expenditures necessary to hold its core acreage positions. During 2012, approximately 10 percent of EOG's exploration and development capital expenditures is expected to be allocated to dry natural gas drilling activity, a significant decrease from 2011.

Capital Structure

During 2011, total cash proceeds from asset sales were $1.43 billion. At December 31, 2011, EOG's total debt outstanding was $5,009 million for a debt-to-total capitalization ratio of 28 percent. Taking into account cash on the balance sheet of $616 million at year-end, EOG's net debt was $4,393 million for a net debt-to-total capitalization ratio of 26 percent. (Please refer to the attached tables for the reconciliation of net debt (non-GAAP) to current and long-term debt (GAAP) and the reconciliation of net debt-to-total capitalization ratio (non-GAAP) to debt-to-total capitalization ratio (GAAP).)

"EOG hit a series of home runs during 2011. We exceeded our crude oil production growth targets and increased the estimated reserves in the Eagle Ford by increasing individual per well reserves and improving the overall recovery factor in the field," Papa said. "The business model we set in motion several years ago is working, evidenced by the outstanding operational and financial metrics EOG achieved in 2011."

2012 Operational Plans and Targets

EOG is targeting total company production growth of 5.5 percent in 2012 and has increased its total organic liquids production growth forecast from the previously stated 27 percent to 30 percent. Total liquids growth is expected to be comprised of a 30 percent increase in crude oil and condensate production and a 30 percent increase in natural gas liquids production. In North America, natural gas production is expected to decrease 11 percent from 2011, reflecting additional producing property sales and a further de-emphasis on natural gas drilling in a weak price environment.

Estimated exploration and production expenditures for 2012 are expected to range from $7.4 to $7.6 billion, including exploration and development, production facilities and midstream expenditures. To offset any funding gap between estimated cash flows and capital expenditures, EOG expects to sell approximately $1.2 billion of assets during 2012, including crude oil, liquids-rich and natural gas producing properties, of which $340 million has closed to date. With a continued focus on the balance sheet in 2012, EOG plans to maintain a net debt-to-total capitalization ratio below 30 percent at year-end.

EOG has hedged approximately 23 percent of its North American crude oil production for 2012. For the period February 1 through June 30, 2012, EOG has crude oil financial price swap contracts in place for approximately 33 percent of its production at a weighted average price of $105.36 per barrel, excluding unexercised options. For the period July 1 through December 31, 2012, EOG has 14 percent of its production hedged at a weighted average price of $104.26 per barrel, excluding unexercised options.

For 2012, EOG has hedged approximately 45 percent of its North American natural gas production. For the period March 1 through December 31, 2012, EOG has natural gas financial price swap contracts in place for 525,000 million British thermal units per day (MMBtud) at a weighted average price of $5.44 per million British thermal units (MMBtu), excluding unexercised options. For each of the years 2013 and 2014, EOG has natural gas financial price swap contracts of 150,000 MMBtud in place at a weighted average price of $4.79 per MMBtu, excluding unexercised options. (For a comprehensive summary of crude oil and natural gas derivative contracts, please refer to the attached tables.)

Dividend Increase

Following an increase in the common stock dividend in 2011, EOG's Board of Directors has again increased the cash dividend on the common stock. Effective with the dividend payable on April 30, 2012, to holders of record as of April 16, 2012, the quarterly dividend on the common stock will be $0.17 per share, an increase of 6.25 percent over the previous indicated annual rate. The indicated annual rate of $0.68 per share reflects the 13th increase in 13 years.

Conference Call Scheduled for February 17, 2012

EOG's full year 2011 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Friday, February 17, 2012. To listen, log on to www.eogresources.com. The webcast will be archived on EOG's website through March 2, 2012.

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 or generate income or cash flows 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:

  • the timing and extent of changes in prices for, and demand for, crude oil, natural gas and related commodities;
  • the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
  • the extent to which EOG can optimize reserve recovery and economically develop its plays utilizing horizontal and vertical drilling and advanced completion technologies;
  • the 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 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;
  • the extent to which EOG is successful in its efforts to market its crude oil, natural gas and related commodity production;
  • the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities;
  • the 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;
  • the 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 and hydraulic fracturing and laws and regulations imposing conditions and restrictions on drilling and completion operations;
  • EOG'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;
  • the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully and economically;
  • competition 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;
  • the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
  • weather, 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;
  • the 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;
  • EOG'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;
  • the extent and effect of any hedging activities engaged in by EOG;
  • the 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;
  • political developments around the world, including in the areas in which EOG operates;
  • the timing and impact of liquefied natural gas imports and exports;
  • the use of competing energy sources and the development of alternative energy sources;
  • the extent to which EOG incurs uninsured losses and liabilities;
  • acts of war and terrorism and responses to these acts; and
  • the other factors described under Item 1A, "Risk Factors", on pages 14 through 20 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2010 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, 2010, 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.  

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

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,


2011


2010


2011


2010













Net Operating Revenues

$

2,773.0


$

1,789.2


$

10,126.1


$

6,099.9

Net Income

$

120.7


$

53.7


$

1,091.1


$

160.7


Basic

$

0.45


$

0.21


$

4.15


$

0.64


Diluted

$

0.45


$

0.21


$

4.10


$

0.63

Average Number of Common Shares













Basic


266.3



251.4



262.7



250.9


Diluted


269.5



254.7



266.3



254.5



























SUMMARY INCOME STATEMENTS

(Unaudited; in thousands, except per share data)























Three Months Ended


Twelve Months Ended



December 31,


December 31,



2011


2010


2011


2010

Net Operating Revenues













Crude Oil and Condensate

$

1,189,250


$

630,433


$

3,838,284


$

1,998,771


Natural Gas Liquids


240,260



147,595



779,364



462,345


Natural Gas


479,825



587,521



2,240,540



2,420,099


Gains (Losses) on Mark-to-Market Commodity Derivative Contracts


145,514



(43,904)



626,053



61,912


Gathering, Processing and Marketing


654,489



307,890



2,115,792



909,680


Gains on Asset Dispositions, Net


49,928



151,097



492,909



223,538


Other, Net


13,749



8,528



33,173



23,551



Total


2,773,015



1,789,160



10,126,115



6,099,896

Operating Expenses













Lease and Well


261,244



190,783



941,954



698,430


Transportation Costs


122,046



98,871



430,322



385,189


Gathering and Processing Costs


25,283



19,405



80,727



66,758


Exploration Costs


31,042



38,746



171,658



187,381


Dry Hole Costs


5,999



27,391



53,230



72,486


Impairments


499,624



239,782



1,031,037



742,647


Marketing Costs


644,687



292,477



2,072,137



884,212


Depreciation, Depletion and Amortization


693,527



543,789



2,516,381



1,941,926


General and Administrative


85,108



74,004



304,811



280,474


Taxes Other Than Income


101,880



89,301



410,549



317,074



Total


2,470,440



1,614,549



8,012,806



5,576,577















Operating Income



302,575



174,611



2,113,309



523,319














Other Income (Expense), Net


(4,352)



6,333



6,853



14,243














Income Before Interest Expense and Income Taxes


298,223



180,944



2,120,162



537,562














Interest Expense, Net



56,591



41,371



210,363



129,586














Income Before Income Taxes


241,632



139,573



1,909,799



407,976

















Income Tax Provision



120,934



85,900



818,676



247,322

















Net Income

$

120,698


$

53,673


$

1,091,123


$

160,654

















Dividends Declared per Common Share

$

0.160


$

0.155


$

0.640


$

0.620





EOG RESOURCES, INC.

OPERATING HIGHLIGHTS

(Unaudited)





















Three Months Ended


Twelve Months Ended






December 31,


December 31,






2011


2010


2011


2010

Wellhead Volumes and Prices












Crude Oil and Condensate Volumes (MBbld) (A)











United States



124.8



74.4



102.0



63.2


Canada



7.6



8.6



7.9



6.7


Trinidad



2.8



4.7



3.4



4.7


Other International (B)


0.1



0.1



0.1



0.1



Total



135.3



87.8



113.4



74.7

















Average Crude Oil and Condensate Prices ($/Bbl) (C)










United States


$

96.33


$

80.38


$

92.92


$

74.88


Canada



89.32



75.47



91.92



72.66


Trinidad



87.02



74.36



90.62



68.80


Other International (B)


103.46



74.29



100.11



73.11



Composite



95.75



79.55



92.79



74.29

















Natural Gas Liquids Volumes (MBbld) (A)













United States



49.6



35.7



41.5



29.5


Canada



1.1



0.8



0.9



0.9



Total



50.7



36.5



42.4



30.4

















Average Natural Gas Liquids Prices ($/Bbl) (C)











United States


$

51.58


$

43.95


$

50.37


$

41.68


Canada



49.16



44.98



52.69



43.40



Composite



51.53



43.97



50.41



41.73

















Natural Gas Volumes (MMcfd) (A)













United States



1,085



1,241



1,113



1,133


Canada



124



185



132



200


Trinidad



313



340



344



341


Other International (B)


11



12



13



14



Total



1,533



1,778



1,602



1,688

















Average Natural Gas Prices ($/Mcf) (C)













United States


$

3.27


$

3.78


$

3.92


$

4.30


Canada



3.14



3.30



3.71



3.91


Trinidad



3.87



2.99



3.53



2.65


Other International (B)


5.70



5.91



5.62



4.90



Composite



3.40



3.59



3.83



3.93

















Crude Oil Equivalent Volumes (MBoed) (D)













United States



355.3



317.0



329.1



281.5


Canada



29.3



40.3



30.7



40.9


Trinidad



54.9



61.3



60.7



61.5


Other International (B)


2.0



2.0



2.2



2.5



Total



441.5



420.6



422.7



386.4

















Total MMBoe (D)



40.6



38.7



154.3



141.1

















(A)

Thousand barrels per day or million cubic feet per day, as applicable.

(B)

Other International includes EOG's United Kingdom and China operations.

(C)

Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments.

(D)

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 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,






2011


2010












ASSETS

Current Assets








Cash and Cash Equivalents


$

615,726


$

788,853


Accounts Receivable, Net



1,451,227



1,113,279


Inventories



590,594



415,792


Assets from Price Risk Management Activities



450,730



48,153


Income Taxes Receivable



26,609



54,916


Deferred Income Taxes



-



9,260


Other




119,052



97,193


      Total



3,253,938



2,527,446











Property, Plant and Equipment








Oil and Gas Properties (Successful Efforts Method)



33,664,435



29,263,809


Other Property, Plant and Equipment



2,149,989



1,733,073


      Total Property, Plant and Equipment



35,814,424



30,996,882


Less:  Accumulated Depreciation, Depletion and Amortization



(14,525,600)



(12,315,982)


      Total Property, Plant and Equipment, Net



21,288,824



18,680,900

Other Assets



296,035



415,887

Total Assets


$

24,838,797


$

21,624,233












LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities








Accounts Payable


$

2,033,615


$

1,664,944


Accrued Taxes Payable



147,105



82,168


Dividends Payable



42,578



38,962


Liabilities from Price Risk Management Activities



-



28,339


Deferred Income Taxes



135,989



41,703


Current Portion of Long-Term Debt



-



220,000


Other




163,032



143,983


      Total



2,522,319



2,220,099





















Long-Term Debt



5,009,166



5,003,341

Other Liabilities



799,189



667,455

Deferred Income Taxes



3,867,219



3,501,706

Commitments and Contingencies

















Stockholders' Equity








Common Stock, $0.01 Par, 640,000,000 Shares Authorized and








  269,323,084 Shares and 254,223,521 Shares Issued at








  December 31, 2011 and 2010, respectively



202,693



202,542


Additional Paid In Capital



2,272,052



729,992


Accumulated Other Comprehensive Income



401,746



440,071


Retained Earnings



9,789,345



8,870,179


Common Stock Held in Treasury, 303,633 Shares and 146,186 Shares








  at December 31, 2011 and 2010, respectively



(24,932)



(11,152)


      Total Stockholders' Equity



12,640,904



10,231,632

Total Liabilities and Stockholders' Equity


$

24,838,797


$

21,624,233






EOG RESOURCES, INC.


SUMMARY STATEMENTS OF CASH FLOWS


(Unaudited; in thousands)










Twelve Months Ended



December 31,



2011


2010

Cash Flows from Operating Activities






Reconciliation of Net Income to Net Cash Provided by Operating Activities:







Net Income

$

1,091,123


$

160,654


Items Not Requiring (Providing) Cash








Depreciation, Depletion and Amortization


2,516,381



1,941,926



Impairments


1,031,037



742,647



Stock-Based Compensation Expenses


128,345



107,378



Deferred Income Taxes


499,300



76,245



Gains on Asset Dispositions, Net


(492,909)



(223,538)



Other, Net


15,139



(468)


Dry Hole Costs


53,230



72,486


Mark-to-Market Commodity Derivative Contracts








Total Gains


(626,053)



(61,912)



Realized Gains


180,701



7,033


Other, Net


26,454



17,273


Changes in Components of Working Capital and Other Assets and Liabilities








Accounts Receivable


(339,780)



(339,126)



Inventories


(176,623)



(171,791)



Accounts Payable


351,087



654,688



Accrued Taxes Payable


92,589



(53,098)



Other Assets


(23,625)



(32,169)



Other Liabilities


14,986



19,342


Changes in Components of Working Capital Associated with Investing and







    Financing Activities


237,028



(208,968)

Net Cash Provided by Operating Activities


4,578,410



2,708,602








Investing Cash Flows







Additions to Oil and Gas Properties


(6,294,397)



(5,210,612)


Additions to Other Property, Plant and Equipment


(656,415)



(370,770)


Acquisition of Galveston LNG Inc.


-



(210,000)


Proceeds from Sales of Assets


1,433,137



672,593


Changes in Components of Working Capital Associated with Investing







    Activities


(237,267)



208,933


Other, Net


-



7,082

Net Cash Used in Investing Activities


(5,754,942)



(4,902,774)








Financing Cash Flows







Common Stock Sold


1,388,265



-


Long-term Debt Borrowings


-



2,478,659


Long-term Debt Repayments


(220,000)



(37,000)


Dividends Paid


(167,169)



(153,240)


Treasury Stock Purchased


(23,922)



(11,295)


Proceeds from Stock Options Exercised and Employee Stock Purchase Plan


35,913



34,560


Debt Issuance Costs


(4,787)



(8,300)


Other, Net


239



35

Net Cash Provided by Financing Activities


1,008,539



2,303,419








Effect of Exchange Rate Changes on Cash


(5,134)



(6,145)








(Decrease) Increase in Cash and Cash Equivalents


(173,127)



103,102

Cash and Cash Equivalents at Beginning of Period


788,853



685,751

Cash and Cash Equivalents at End of Period

$

615,726


$

788,853





EOG RESOURCES, INC.


QUANTITATIVE RECONCILIATION OF ADJUSTED NET


INCOME (NON-GAAP) TO NET INCOME (GAAP)


(Unaudited; in thousands, except per share data)
































The following chart adjusts the three-month and twelve-month periods ended December 31, 2011 and 2010 reported Net Income (GAAP) to reflect actual net cash realized from financial commodity derivative transactions by eliminating the unrealized mark-to-market (gains) losses from these transactions, to add back impairment charges related to certain of EOG's North American assets in 2011 and in 2010, 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, to eliminate the net gains on asset dispositions primarily in North America in 2011 and 2010, and to eliminate the change in the estimated fair value of a contingent consideration liability in 2010 related to EOG's previously disclosed acquisition of Haynesville and Bossier Shale unproved acreage.  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,





2011


2010


2011


2010

















Reported Net Income (GAAP)

$

120,698


$

53,673


$

1,091,123


$

160,654

















Mark-to-Market (MTM) Commodity Derivative Contracts Impact














Total (Gains) Losses


(145,514)



43,904



(626,053)



(61,912)



Realized Gains (Losses)


96,936



(18,147)



180,701



7,033



  Subtotal



(48,578)



25,757



(445,352)



(54,879)


















After-Tax MTM Impact


(31,101)



16,424



(285,136)



(35,203)

















Add: Impairment of Certain North American Assets, Net of Tax


249,084



122,344



516,198



330,675


Add: Write-off of Fees Associated with Revolving Credit Facilities, Net of Tax

3,656



-



3,656



-


Less: Net Gains on Asset Dispositions, Net of Tax


(33,337)



(98,835)



(317,342)



(145,216)


Less: Change in Fair Value of Contingent Consideration Liability, Net of Tax

-



(1,580)



-



(14,521)

















Adjusted Net Income (Non-GAAP)

$

309,000


$

92,026


$

1,008,499


$

296,389

















Net Income Per Share (GAAP)














Basic


$

0.45


$

0.21


$

4.15


$

0.64



Diluted


$

0.45


$

0.21


$

4.10

(a)

$

0.63

(b)
















Percentage Increase - [(a) - (b)] / (b)








551%




















Adjusted Net Income Per Share (Non-GAAP)














Basic


$

1.16


$

0.37


$

3.84


$

1.18



Diluted


$

1.15


$

0.36


$

3.79

(c)

$

1.16

(d)
















Percentage Increase - [(c) - (d)] / (d)








227%




















Average Number of Common Shares














Basic



266,277



251,365



262,735



250,876



Diluted



269,524



254,716



266,268



254,500






EOG RESOURCES, INC.


QUANTITATIVE RECONCILIATION OF ADJUSTED EARNINGS BEFORE INTEREST EXPENSE,


INCOME TAXES, DEPRECIATION, DEPLETION AND AMORTIZATION, EXPLORATION


COSTS, DRY HOLE COSTS AND IMPAIRMENTS (ADJUSTED EBITDAX) (NON-GAAP)


TO INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES (GAAP)


(Unaudited; in thousands)










The following chart adjusts the twelve-month period ended December 31, 2011 and 2010 reported Income Before Interest Expense and Income Taxes (GAAP) to Earnings Before Interest Expense, Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and to further adjust 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 on asset dispositions primarily in North America in 2011 and 2010.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Income Before Interest Expense and Income Taxes (GAAP) to add back Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust 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.












Twelve Months Ended




December 31,




2011


2010










Income Before Interest Expense and Income Taxes (GAAP)

$

2,120,162


$

537,562










Adjustments:







Depreciation, Depletion and Amortization


2,516,381



1,941,926


Exploration Costs


171,658



187,381


Dry Hole Costs


53,230



72,486


Impairments


1,031,037



742,647



EBITDAX (Non-GAAP)


5,892,468



3,482,002


Total Gains on MTM Commodity Derivative Contracts


(626,053)



(61,912)


Realized Gains on MTM Commodity Derivative Contracts


180,701



7,033


Net Gains on Asset Dispositions


(492,909)



(223,538)



Adjusted EBITDAX (Non-GAAP)

$

4,954,207

(a)

$

3,203,585

(b)









Percentage Increase - [(a) - (b)] / (b)


55%









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, 2011 and 2010 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), 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,





2011


2010


2011


2010

















Net Cash Provided by Operating Activities (GAAP)

$

1,236,887


$

622,875


$

4,578,410


$

2,708,602

















Adjustments














Exploration Costs (excluding Stock-Based Compensation Expenses)


24,715



32,676



145,881



163,274



Changes in Components of Working Capital and Other Assets and Liabilities















Accounts Receivable


210,815



214,313



339,780



339,126




Inventories


9,012



37,610



176,623



171,791




Accounts Payable


(105,702)



(127,270)



(351,087)



(654,688)




Accrued Taxes Payable


8,650



12,994



(92,589)



53,098




Other Assets


(4,975)



16,118



23,625



32,169




Other Liabilities


22,036



25,006



(14,986)



(19,342)



Changes in Components of Working Capital Associated















with Investing and Financing Activities


(103,801)



(7,727)



(237,028)



208,968

















Discretionary Cash Flow (Non-GAAP)

$

1,297,637


$

826,595


$

4,568,629

(a)

$

3,002,998

(b)
















Percentage Increase - [(a) - (b)] / (b)








52%









EOG RESOURCES, INC.

RESERVES SUPPLEMENTAL DATA

(Unaudited)















2011 NET PROVED RESERVES RECONCILIATION SUMMARY  








United




North




Other


Total



CRUDE OIL & CONDENSATE (MMBbls )

States


Canada


America


Trinidad


Int'l


Int'l


Total















Beginning Reserves

355.5


25.6


381.1


4.7


0.1


4.8


385.9

Revisions

(21.2)


(4.6)


(25.8)


0.1


-


0.1


(25.7)

Purchases in place

-


-


-


-


-


-


-

Extensions, discoveries and other additions

202.5


0.5


203.0


-


-


-


203.0

Sales in place

(4.3)


-


(4.3)


-


-


-


(4.3)

Production

(37.2)


(2.9)


(40.1)


(1.3)


-


(1.3)


(41.4)















Ending Reserves

495.3


18.6


513.9


3.5


0.1


3.6


517.5















NATURAL GAS LIQUIDS (MMBbls )














Beginning Reserves

150.4


1.5


151.9


-


-


-


151.9

Revisions

36.1


-


36.1


-


-


-


36.1

Purchases in place

-


-


-


-


-


-


-

Extensions, discoveries and other additions

65.3


-


65.3


-


-


-


65.3

Sales in place

(10.0)


-


(10.0)


-


-


-


(10.0)

Production

(15.2)


(0.3)


(15.5)


-


-


-


(15.5)















Ending Reserves

226.6


1.2


227.8


-


-


-


227.8















NATURAL GAS (Bcf)














Beginning Reserves

6,491.5


1,133.8


7,625.3


827.6


17.3


844.9


8,470.2

Revisions

(344.0)


(49.8)


(393.8)


(24.2)


1.3


(22.9)


(416.7)

Purchases in place

3.0


-


3.0


-


-


-


3.0

Extensions, discoveries and other additions

634.6


-


634.6


74.7


4.5


79.2


713.8

Sales in place

(323.6)


-


(323.6)


-


-


-


(323.6)

Production

(415.7)


(48.1)


(463.8)


(127.4)


(4.6)


(132.0)


(595.8)















Ending Reserves

6,045.8


1,035.9


7,081.7


750.7


18.5


769.2


7,850.9















OIL EQUIVALENTS (MMBoe)














Beginning Reserves

1,587.8


216.1


1,803.9


142.7


2.9


145.6


1,949.5

Revisions

(42.5)


(12.9)


(55.4)


(4.0)


0.2


(3.8)


(59.2)

Purchases in place

0.5


-


0.5


-


-


-


0.5

Extensions, discoveries and other additions

373.6


0.5


374.1


12.4


0.8


13.2


387.3

Sales in place

(68.2)


-


(68.2)


-


-


-


(68.2)

Production

(121.7)


(11.2)


(132.9)


(22.5)


(0.7)


(23.2)


(156.1)















Ending Reserves

1,729.5


192.5


1,922.0


128.6


3.2


131.8


2,053.8





























Net Proved Developed Reserves (MMBoe)  














  At December 31, 2010

839.9


79.7


919.6


90.4


3.0


93.4


1,013.0

  At December 31, 2011

877.3


58.5


935.8


103.7


3.2


106.9


1,042.7















EOG RESOURCES, INC.

RESERVES SUPPLEMENTAL DATA (CONTINUED)

(Unaudited)















2011 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ Millions)








United




North




Other


Total




States


Canada


America


Trinidad


Int'l


Int'l


Total















Acquisition Cost of Unproved Properties

$    295.2


$       6.2


$     301.4


$             -


$     (0.6)


$   (0.6)


$    300.8

Exploration Costs

311.3


31.5


342.8


2.6


18.1


20.7


363.5

Development Costs

5,358.6


232.8


5,591.4


132.1


74.0


206.1


5,797.5















Total Drilling

5,965.1


270.5


6,235.6


134.7


91.5


226.2


6,461.8















Acquisition Cost of Proved Properties

4.2


-


4.2


-


-


-


4.2















Total Exploration & Development Expenditures

5,969.3


270.5


6,239.8


134.7


91.5


226.2


6,466.0















Gathering, Processing and Other

604.0


52.1


656.1


0.1


0.2


0.3


656.4

Asset Retirement Costs

51.8


69.8


121.6


6.8


4.8


11.6


133.2















Total Expenditures

6,625.1


392.4


7,017.5


141.6


96.5


238.1


7,255.6















Proceeds from Sales in Place

(1,252.0)


(177.9)


(1,429.9)


(3.3)


-


(3.3)


(1,433.2)















Net Expenditures

$ 5,373.1


$   214.5


$  5,587.6


$     138.3


$     96.5


$ 234.8


$ 5,822.4





























RESERVE REPLACEMENT COSTS ($ / Boe ) *














Total Drilling, Before Revisions

$    15.97


$ 541.00


$     16.67


$     10.86


$ 114.38


$ 17.14


$    16.68

All-in Total, Net of Revisions

$    18.00


$  (21.81)


$     19.55


$     16.04


$   91.50


$ 24.06


$    19.68















RESERVE REPLACEMENT *














Drilling Only

307%


4%


281%


55%


114%


57%


248%

All-in Total, Net of Revisions & Dispositions  

216%


-111%


189%


37%


143%


41%


167%















*  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














 Development Activities (GAAP)

$ 6,021.1


$   340.3


$  6,361.4


$     141.5


$     96.3


$ 237.8


$ 6,599.2















Less: Asset Retirement Costs

(51.8)


(69.8)


(121.6)


(6.8)


(4.8)


(11.6)


(133.2)

         Acquisition Cost of Proved Properties

(4.2)


-


(4.2)


-


-


-


(4.2)















Total Exploration & Development Expenditures














 for Drilling Only (Non-GAAP) (a)

$ 5,965.1


$   270.5


$  6,235.6


$     134.7


$     91.5


$ 226.2


$ 6,461.8















Total Costs Incurred in Exploration and














 Development Activities (GAAP)

$ 6,021.1


$   340.3


$  6,361.4


$     141.5


$     96.3


$ 237.8


$ 6,599.2















Less: Asset Retirement Costs

(51.8)


(69.8)


(121.6)


(6.8)


(4.8)


(11.6)


(133.2)















Total Exploration & Development Expenditures (Non-GAAP) (b)

$ 5,969.3


$   270.5


$  6,239.8


$     134.7


$     91.5


$ 226.2


$ 6,466.0















Net Proved Reserve Additions From All Sources














- Oil Equivalents (MMBoe)














Revisions due to price (c)

(11.7)


(3.0)


(14.7)


(1.7)


-


(1.7)


(16.4)

Revisions other than price

(30.8)


(9.9)


(40.7)


(2.3)

-

0.2


(2.1)


(42.8)

Purchases in place

0.5


-


0.5


-


-


-


0.5

Extensions, discoveries and other additions (d)

373.6


0.5


374.1


12.4


0.8


13.2


387.3















Total Proved Reserve Additions (e)

331.6


(12.4)


319.2


8.4


1.0


9.4


328.6















Sales in place

(68.2)


-


(68.2)


-


-


-


(68.2)















Net Proved Reserve Additions From All Sources (f)

263.4


(12.4)


251.0


8.4


1.0


9.4


260.4















Production (g)

121.7


11.2


132.9


22.5


0.7


23.2


156.1















RESERVE REPLACEMENT COSTS ($ / BOE)














Total Drilling, Before Revisions (a / d )

$    15.97


$ 541.00


$     16.67


$     10.86


$ 114.38


$ 17.14


$    16.68

All-in Total, Net of Revisions (b / e)  

$    18.00


$  (21.81)


$     19.55


$     16.04


$   91.50


$ 24.06


$    19.68

All-in Total, Excluding Revisions Due to Price (b / (e - c ))

$    17.39


$  (28.78)


$     18.69


$     13.34


$   91.50


$ 20.38


$    18.74















RESERVE REPLACEMENT














Drilling Only (d / g )

307%


4%


281%


55%


114%


57%


248%

All-in Total, Net of Revisions & Dispositions (f / g )

216%


-111%


189%


37%


143%


41%


167%

All-in Total, Excluding Revisions Due to Price ((f - c ) / g )

226%


-84%


200%


45%


143%


48%


177%





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,




2011






Total Stockholders' Equity - (a)

$

12,641






Current and Long-Term Debt - (b)


5,009


Less: Cash


(616)


Net Debt (Non-GAAP) - (c)


4,393






Total Capitalization (GAAP) - (a) + (b)

$

17,650






Total Capitalization (Non-GAAP) - (a) + (c)

$

17,034






Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]


28%






Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)]


26%





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 as of February 16, 2012 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)

2012 (1)








January 2012 (closed)




34,000


$104.95

February 2012





34,000


104.95

March 1, 2012 through June 30, 2012



49,000


105.42

July 1, 2012 through August 31, 2012



32,000


104.95

September 1, 2012 through December 31, 2012



17,000


103.59



















(1)

EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for an additional six-month period.  Options covering a notional volume of 17,000 Bbld are exercisable on June 29, 2012.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 17,000 Bbld at an average price of $106.31 per barrel for the period July 1, 2012 through December 31, 2012.  Options covering a notional volume of 15,000 Bbld are exercisable on August 31, 2012.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 15,000 Bbld at an average price of $106.50 per barrel for the period September 1, 2012 through February 28, 2013.











NATURAL GAS DERIVATIVE CONTRACTS










Weighted




Volume


Average Price







(MMBtud)


($/MMBtu)

2012 (2)








January 1, 2012 through February 29, 2012 (closed)



525,000


$5.44

March 1, 2012 through December 31, 2012



525,000


5.44










2013 (3)








January 1, 2013 through December 31, 2013



150,000


$4.79










2014 (3)








January 1, 2014 through December 31, 2014



150,000


$4.79



















(2)

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 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 425,000 MMBtud at an average price of $5.44 per MMBtu for the period from March 1, 2012 through December 31, 2012.  

(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 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 2013 and 2014.










Definitions









Bbld

Barrels per day.


$/Bbl

Dollars per barrel.


MMBtud

Million British thermal units per day.


$/MMBtu

Dollars per million British thermal units.




EOG RESOURCES, INC.

 FIRST QUARTER AND FULL YEAR 2012 FORECAST AND BENCHMARK COMMODITY PRICING
















    (a)  First Quarter and Full Year 2012 Forecast


The forecast items for the first quarter and full year 2012 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 2012


Full Year 2012

Daily Production










Crude Oil and Condensate Volumes (MBbld)











United States


118.0

-

133.0


130.0

-

147.5



Canada


6.5

-

7.5


5.5

-

7.8



Trinidad


2.0

-

2.8


1.0

-

2.0



Other International


0.0

-

0.0


0.1

-

0.2




Total


126.5

-

143.3


136.6

-

157.5















Natural Gas Liquids Volumes (MBbld)











United States


46.0

-

53.0


49.2

-

59.2



Canada


0.6

-

1.0


0.6

-

1.0




Total


46.6

-

54.0


49.8

-

60.2















Natural Gas Volumes (MMcfd)











United States


1,015

-

1,045


995

-

1,035



Canada


90

-

107


82

-

102



Trinidad


315

-

345


335

-

363



Other International


9

-

11


8

-

10




Total


1,429

-

1,508


1,420

-

1,510















Crude Oil Equivalent Volumes (MBoed)  











United States


333.2

-

360.2


345.0

-

379.2



Canada


22.1

-

26.3


19.8

-

25.8



Trinidad


54.5

-

60.3


56.8

-

62.5



Other International


1.4

-

1.8


1.4

-

1.9




Total


411.2

-

448.6


423.0

-

469.4




















ESTIMATED RANGES







(Unaudited)







1Q 2012


Full Year 2012

Operating Costs










Unit Costs ($/Boe)











Lease and Well


$   6.48

-

$   7.08


$   6.48

-

$   7.08



Transportation Costs


$   3.12

-

$   3.48


$   3.24

-

$   3.66



Depreciation, Depletion and Amortization


$ 17.22

-

$ 18.42


$ 17.70

-

$ 18.60














Expenses ($MM)










Exploration, Dry Hole and Impairment


$ 101.5

-

$ 120.0


$ 450.0

-

$ 490.0


General and Administrative


$   78.0

-

$   84.0


$ 338.0

-

$ 358.0


Gathering and Processing


$   19.0

-

$   23.0


$   72.0

-

$   90.0


Capitalized Interest


$   13.0

-

$   17.0


$   60.0

-

$   72.0


Net Interest


$   45.0

-

$   51.0


$ 175.0

-

$ 195.0














Taxes Other Than Income (% of Revenue)


6.1%

-

6.5%


5.5%

-

6.5%














Income Taxes











Effective Rate


35%

-

50%


35%

-

45%


Current Taxes ($MM)


$      70

-

$      85


$    290

-

$    310














Capital Expenditures ($MM) - FY 2012 (Excluding Acquisitions)









Exploration and Development, Excluding Facilities






$ 6,200

-

$ 6,300


Exploration and Development Facilities






$    630

-

$    675


Gathering, Processing and Other






$    570

-

$    600














Pricing - (Refer to Benchmark Commodity Pricing in text)










Crude Oil and Condensate ($/Bbl)











Differentials












United States - below WTI


$   0.50

-

$   3.00


$   0.25

-

$   1.75




Canada - below WTI


$   7.00

-

$ 11.00


$   5.00

-

$   8.00




Trinidad - below WTI


$   2.50

-

$   3.50


$   6.00

-