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EOG Resources Reports Outstanding Crude Oil Production in Third Quarter 2012 and Increases Growth Rate Target

FOR IMMEDIATE RELEASE: November 5, 2012

HOUSTON, Nov. 5, 2012 /PRNewswire/ --

  • Reports Strong Year-Over-Year Growth in Adjusted Non-GAAP Earnings Per Share, Discretionary Cash Flow and Adjusted EBITDAX
  • Achieves 42 Percent Crude Oil and Condensate Production Increase and 40 Percent Increase in Total Liquids Production Over Third Quarter 2011
  • Increases 2012 Total Company Crude Oil Production Growth Target to 40 Percent from 37 Percent and Full Year Total Liquids Growth Target to 38 Percent from 35 Percent
  • Raises 2012 Total Company Production Growth Target to 10.6 Percent from 9 Percent
  • Generates Continued Momentum with Eagle Ford and Bakken/Three Forks Well Results
  • Realizes Premium Crude Oil Prices for Eagle Ford and Bakken Volumes
  • Increases 2012 Total Asset Sales Target to Approximately $1.3 Billion

EOG Resources, Inc. (NYSE: EOG) (EOG) today reported third quarter 2012 net income of $355.5 million, or $1.31 per share. This compares to third quarter 2011 net income of $540.9 million, or $2.01 per share.

Consistent with some analysts' practice of matching realizations to settlement months and making certain other adjustments in order to exclude one-time items, adjusted non-GAAP net income for the third quarter 2012 was $468.7 million, or $1.73 per share. Adjusted non-GAAP net income for the third quarter 2011 was $223.2 million, or $0.83 per share. The results for the third quarter 2012 include net gains on asset dispositions of $43.4 million, net of tax ($0.16 per share) and a previously disclosed non-cash net gain of $4.7 million ($3.0 million after tax, or $0.01 per share) on the mark-to-market of financial commodity contracts. During the third quarter, the net cash inflow related to financial commodity contracts was $249.2 million ($159.6 million after tax, or $0.59 per share). (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)

EOG's overall financial metrics were enhanced by successfully linking a significant portion of its Eagle Ford and Bakken crude oil and condensate production to markets which provide premium crude oil pricing. For the third quarter, adjusted non-GAAP net income per share increased 108 percent, discretionary cash flow increased 37 percent and adjusted EBITDAX increased 39 percent as compared to the third quarter 2011. (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income per share to GAAP net income per share, non-GAAP discretionary cash flow to net cash provided by operating activities (GAAP) and adjusted EBITDAX (non-GAAP) to income before interest expense and income taxes (GAAP).)

EOG exceeded its third quarter crude oil and condensate production forecasts by continuing to modify completion techniques in its South Texas Eagle Ford; North Dakota Bakken and Three Forks; and Permian Basin Wolfcamp and Leonard plays. In North America, crude oil production increased 45 percent in the third quarter and 51 percent for the first nine months of 2012 compared to prior year periods. Total North American liquids (crude oil, condensate and natural gas liquids) production increased 42 percent for the third quarter and 48 percent for the first three quarters of 2012 over the same periods a year ago. On a total company basis, total crude oil and condensate production increased 42 percent and total liquids production rose 40 percent for the third quarter compared to the same period in 2011.

"With especially strong, consistent individual well results, EOG's best plays have become even better," said Mark G. Papa, Chairman and Chief Executive Officer. "Therefore, based on nine months of robust crude oil production, we are setting the bar higher for the third time this year. EOG has increased its 2012 crude oil production growth target to 40 percent from 37 percent. Because our outstanding oil results also impact total liquids production, we are also raising our total liquids production growth target to 38 percent from 35 percent and increasing our total company production target to 10.6 percent from 9 percent."

Operational Highlights

"Simply put, EOG's excellent third quarter performance reflects the success of our groundwork. Over the last few years, we captured the best crude oil acreage in the United States.  Now we are executing a development program that has exceeded our initial expectations. In addition, we implemented innovative marketing logistics such as our crude-by-rail transportation system," Papa said. "During the third quarter, higher volumes combined with higher realized crude oil prices and good unit cost control added substantial value to EOG's bottom line."

In the South Texas Eagle Ford, EOG continued to post outstanding well results. In Gonzales County, the Baker-DeForest Unit #4H came on line at 4,598 barrels of oil per day (Bopd) with 488 barrels per day (Bpd) of natural gas liquids (NGLs) and 2.9 million cubic feet per day (MMcfd) of natural gas. The Baker-DeForest Unit #1H, #2H, #3H and #12H were turned to sales at initial rates ranging from 3,346 to 4,216 Bopd with 457 to 537 Bpd of NGLs and 2.7 to 3.2 MMcfd of natural gas. EOG has 100 percent working interest in these five Baker-DeForest wells.

Drilled in Gonzales County near the DeWitt County line, a new area for EOG, the Reilly Unit #1H had an initial oil production rate of 3,579 Bopd with 483 Bpd of NGLs and 2.9 MMcfd of natural gas. EOG has 70 percent working interest in this well. Also in the new area northeast of the Reilly, the Boysen Unit #1H and Baird Heirs Unit #4H were completed at 2,540 and 2,242 Bopd with 268 and 181 Bpd of NGLs and 1.6 and 1.1 MMcfd of natural gas, respectively. EOG has 100 percent working interest in both wells. EOG also has 100 percent working interest in the Henkhaus Unit #8H, which was completed offsetting the previously drilled Henkhaus Unit #10H and #11H. The #8H had an initial production rate of 4,012 Bopd with 495 Bpd of NGLs and 3.0 MMcfd of natural gas.

In the western region of its Eagle Ford acreage where EOG increased drilling activity in the second half of the year, the Lowe Pasture #9H and #10H were completed in McMullen County at initial production rates of 1,905 and 2,075 Bopd with 112 and 115 Bpd of NGLs and 673 and 688 thousand cubic feet per day (Mcfd) of natural gas, respectively. The Martindale L&C #1H and #2H in La Salle County began sales at 1,522 and 1,876 Bopd with 220 and 208 Bpd of NGLs and 1.3 and 1.2 MMcfd of natural gas, respectively. EOG has 100 percent working interest in these four wells.

EOG focused its third quarter North Dakota drilling activity in the Bakken Core and Antelope Extension, an area 25 miles southwest of the Core. Two recent wells further validated the success of EOG's 320-acre infill drilling program in the Bakken Core where EOG introduced refined completion techniques simultaneously with tighter spacing tests. In Mountrail County, the Fertile 46-1608H was turned to sales at an initial rate of 1,732 Bopd with 90 Bpd of NGLs and 363 Mcfd of natural gas. The Fertile 47-0712H began sales at 1,258 Bopd with 83 Bpd of NGLs and 332 Mcfd of natural gas. EOG has 92 and 78 percent working interest, respectively, in these wells. EOG plans to test denser drilling in the Core before year-end.

In the Antelope Extension where EOG is developing its acreage on 320-acre spacing, both the Bakken and Three Forks formations have proven to be highly productive and economic. In McKenzie County, the Clarks Creek 15-0805H and Bear Den 19-2116H were drilled in the Bakken with initial maximum rates of 1,067 and 1,886 Bopd, respectively, with associated rich natural gas. EOG has 85 and 76 percent working interest, respectively, in these wells. In the Three Forks, EOG completed the Mandaree 101-20H, Bear Den 104-2116H and Hawkeye 100-2501H at maximum rates of 1,285, 2,226 and 3,196 Bopd, respectively, with associated rich natural gas. EOG has 90 percent, 76 percent and 73 percent working interest, respectively, in these wells.

EOG posted favorable ongoing results from its Leonard and Wolfcamp shale activities in the West Texas and southeast New Mexico Permian Basin by drilling economic wells that produce crude oil with a liquids-rich natural gas stream. In the New Mexico Delaware Basin, the Diamond 8 Fed Com #3H, #4H and #5H were completed in the Leonard shale at initial production rates of 962, 1,148 and 1,162 Bopd with 134, 171 and 188 Bpd of NGLs and 963, 941 and 1,036 Mcfd of natural gas, respectively. EOG has 96 percent working interest in these Lea County wells.

In the West Texas Wolfcamp, EOG tested multiple zones across its acreage to determine their prospectivity. The Mayer SL #5013LH was completed to sales at 1,290 Bopd with 95 Bpd of NGLs and 539 Mcfd of natural gas in the lower Wolfcamp. EOG has 77 percent working interest in this Irion County well. In Crockett County, the University 40-B #1602H, in which EOG has 80 percent working interest, began production from the middle Wolfcamp at an initial rate of 916 Bopd with 127 Bpd of NGLs and 726 Mcfd of natural gas. The University 43 #0911H, 43 #1009H and 43 #1011H were completed in the same zone at initial production rates ranging from 840 to 1,212 Bopd with 60 to 110 Bpd of NGLs and 330 to 600 Mcfd of natural gas. EOG has 75 percent working interest in these three Irion County wells.

EOG also reported positive results from its Fort Worth Barnett Combo play, another prominent contributor to the company's 2012 liquids production. EOG extended the boundaries of the play by completing the Nunnely A-#1H, B-#2H, B-#3H and C-#1H at initial rates ranging from 412 Bopd to 705 Bopd with 43 to 57 Bpd of NGLs and 240 to 316 Mcfd of natural gas. EOG has 100 percent working interest in these Montague County wells.

"EOG's current position as a crude oil producer at the forefront of the large cap independent peer group indicates the exceptional quality of our asset portfolio," Papa said. 

Hedging Activity

EOG has hedged approximately 26 percent of its North American crude oil production for the period November and December 2012. From November 1 through December 31, 2012, EOG has crude oil financial price swap contracts in place for an average of 42,000 Bopd at a weighted average price of $105.19 per barrel, excluding unexercised options.

With the goal of maintaining a strong balance sheet while minimizing the gap between capital expenditures and cash flow, EOG is pursuing an opportunistic hedging strategy for 2013. For the period January 1 through June 30, 2013, EOG has crude oil financial price swap contracts in place for an average of 98,000 Bopd at a weighted average price of $99.39 per barrel, excluding unexercised options. For the period July 1 through December 31, 2013, EOG has an average of 68,000 Bopd hedged at a weighted average price of $99.45 per barrel, excluding unexercised options.

Although EOG plans to pursue very minimal natural gas drilling activity in 2013, financial price swap contracts are in place for 150,000 million British thermal units per day of natural gas at a weighted 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.)  

Capital Structure

Through September 30, 2012, EOG's cash proceeds from asset sales were approximately $1.2 billion. EOG is targeting an additional $100 million of asset sales for a full-year total of approximately $1.3 billion. EOG revised its 2012 total capital expenditure program to approximately $7.6 billion.

At September 30, 2012, EOG's total debt outstanding was $6,312 million for a debt-to-total capitalization ratio of 31 percent. Taking into account cash on the balance sheet of $1,113 million at the end of the third quarter, EOG's net debt was $5,199 million for a net debt-to-total capitalization ratio of 27 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).)

Conference Call Scheduled for Tuesday, November 6, 2012

EOG's third quarter 2012 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Tuesday, November 6, 2012. To listen, log on to www.eogresources.com. The webcast will be archived on EOG's website through November 20, 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, 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:

  • the timing and extent of changes in prices for, and demand for, crude oil and condensate, natural gas liquids, 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, advanced completion technologies and hydraulic fracturing;
  • 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 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;
  • 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, 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;
  • 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, and to otherwise satisfy its capital expenditure requirements;
  • 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 use of competing energy sources and the development of alternative energy sources;
  • the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;
  • acts of war and terrorism and responses to these acts; and
  • the 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.   

For Further Information Contact:                  

Investors


Maire A. Baldwin


(713) 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


Nine Months Ended


September 30,


September 30,


2012


2011


2012


2011













Net Operating Revenues

$

2,954.9


$

2,885.7


$

8,670.8


$

7,353.1

Net Income

$

355.5


$

540.9


$

1,075.3


$

970.4

Net Income Per Share 












        Basic

$

1.33


$

2.03


$

4.03


$

3.71

        Diluted

$

1.31


$

2.01


$

3.98


$

3.66

Average Number of Common Shares












        Basic


267.9



266.1



267.1



261.7

        Diluted


271.0



269.3



270.3



265.2

























SUMMARY INCOME STATEMENTS

(Unaudited; in thousands, except per share data)


























Three Months Ended


Nine Months Ended


September 30,


September 30,


2012


2011


2012


2011

Net Operating Revenues












        Crude Oil and Condensate

$

1,512,168


$

953,154


$

4,198,753


$

2,649,034

        Natural Gas Liquids


170,351



206,572



518,684



539,104

        Natural Gas


426,728



576,803



1,153,433



1,760,715

        Gains on Mark-to-Market Commodity Derivative Contracts


4,671



357,664



327,328



480,539

        Gathering, Processing and Marketing


764,385



578,022



2,193,290



1,461,303

        Gains on Asset Dispositions, Net


67,376



207,468



248,134



442,981

        Other, Net


9,176



6,061



31,203



19,424

              Total


2,954,855



2,885,744



8,670,825



7,353,100

Operating Expenses












        Lease and Well


253,452



248,926



765,703



680,710

        Transportation Costs


164,407



108,678



431,642



308,276

        Gathering and Processing Costs


26,223



18,532



72,403



55,444

        Exploration Costs


45,953



48,469



136,909



140,616

        Dry Hole Costs


1,924



22,604



13,005



47,231

        Impairments 


62,875



83,431



250,239



531,413

        Marketing Costs


755,457



572,604



2,155,043



1,427,450

        Depreciation, Depletion and Amortization


825,851



651,684



2,383,359



1,822,854

        General and Administrative


92,870



82,260



244,866



219,703

        Taxes Other Than Income


120,096



98,526



359,798



308,669

              Total


2,349,108



1,935,714



6,812,967



5,542,366













Operating Income 


605,747



950,030



1,857,858



1,810,734













Other Income, Net


7,596



1,377



22,902



11,205













Income Before Interest Expense and Income Taxes


613,343



951,407



1,880,760



1,821,939













Interest Expense, Net


53,154



52,186



154,198



153,772













Income Before Income Taxes


560,189



899,221



1,726,562



1,668,167













Income Tax Provision


204,698



358,343



651,284



697,742













Net Income 

$

355,491


$

540,878


$

1,075,278


$

970,425













Dividends Declared per Common Share

$

0.17


$

0.16


$

0.51


$

0.48



EOG RESOURCES, INC.

OPERATING HIGHLIGHTS

(Unaudited)














Three Months Ended


Nine Months Ended


September 30,


September 30,


2012


2011


2012


2011

Wellhead Volumes and Prices












Crude Oil and Condensate Volumes (MBbld) (A)












      United States


161.3



108.9



147.6



94.3

      Canada


6.7



6.8



6.9



8.0

      Trinidad


1.2



3.1



1.7



3.6

      Other International (B)


0.1



0.1



0.1



0.1

          Total


169.3



118.9



156.3



106.0













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












      United States

$

97.64


$

87.22


$

98.26


$

91.40

      Canada


86.09



90.54



86.25



92.76

      Trinidad


90.84



89.70



93.85



91.56

      Other International (B)


83.59



110.84



90.34



98.77

          Composite


97.13



87.49



97.68



91.52













Natural Gas Liquids Volumes (MBbld) (A)












      United States


58.1



43.2



54.3



38.7

      Canada


0.9



0.8



0.9



0.8

          Total


59.0



44.0



55.2



39.5













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












      United States

$

30.95


$

50.90


$

35.43


$

49.85

      Canada


41.09



57.69



44.61



54.36

          Composite


31.11



51.02



35.58



49.93













Natural Gas Volumes (MMcfd) (A)












      United States


1,022



1,122



1,051



1,123

      Canada


94



123



98



135

      Trinidad


387



330



393



354

      Other International (B)


9



12



10



13

          Total


1,512



1,587



1,552



1,625













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












      United States

$

2.61


$

4.06


$

2.39


$

4.13

      Canada


2.39



3.81



2.35



3.88

      Trinidad


4.38



3.59



3.60



3.42

      Other International (B)


5.67



5.54



5.70



5.60

          Composite


3.07



3.95



2.71



3.97













Crude Oil Equivalent Volumes (MBoed) (D)












      United States 


389.7



339.4



377.2



320.3

      Canada


23.2



27.9



24.1



31.2

      Trinidad


65.7



58.0



67.1



62.7

      Other International (B)


1.7



2.0



1.8



2.2

          Total


480.3



427.3



470.2



416.4













Total MMBoe (D)


44.2



39.3



128.8



113.7













(A)

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

(B)

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

(C)

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

(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)










September 30,


December 31,


2012


2011







ASSETS

Current Assets






     Cash and Cash Equivalents

$

1,112,623


$

615,726

     Accounts Receivable, Net


1,579,841



1,451,227

     Inventories


657,880



590,594

     Assets from Price Risk Management Activities


248,698



450,730

     Income Taxes Receivable


54,049



26,609

     Deferred Income Taxes


120,967



-

     Other


226,104



119,052

            Total


4,000,162



3,253,938







Property, Plant and Equipment






     Oil and Gas Properties (Successful Efforts Method)


37,021,216



33,664,435

     Other Property, Plant and Equipment


2,609,467



2,149,989

            Total Property, Plant and Equipment


39,630,683



35,814,424

     Less:  Accumulated Depreciation, Depletion and Amortization


(15,944,233)



(14,525,600)

            Total Property, Plant and Equipment, Net


23,686,450



21,288,824

Other Assets


345,879



296,035

Total Assets

$

28,032,491


$

24,838,797







LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities






     Accounts Payable

$

2,151,093


$

2,033,615

     Accrued Taxes Payable


168,691



147,105

     Dividends Payable


45,653



42,578

     Deferred Income Taxes


2,793



135,989

     Other


210,153



163,032

            Total


2,578,383



2,522,319













Long-Term Debt


6,305,277



5,009,166

Other Liabilities


842,173



799,189

Deferred Income Taxes


4,513,188



3,867,219

Commitments and Contingencies












Stockholders' Equity






     Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 271,323,486 Shares Issued at September 30, 2012 and 269,323,084 Shares Issued at December 31, 2011 


202,713



202,693

     Additional Paid in Capital


2,459,531



2,272,052

     Accumulated Other Comprehensive Income 


451,399



401,746

     Retained Earnings


10,726,811



9,789,345

     Common Stock Held in Treasury, 473,624 Shares at September 30, 2012 and 303,633 Shares at December 31, 2011


(46,984)



(24,932)

            Total Stockholders' Equity


13,793,470



12,640,904

Total Liabilities and Stockholders' Equity

$

28,032,491


$

24,838,797



EOG RESOURCES, INC.

SUMMARY STATEMENTS OF CASH FLOWS

(Unaudited; in thousands)








Nine Months Ended


September 30,


2012


2011

Cash Flows from Operating Activities






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






     Net Income 

$

1,075,278


$

970,425

     Items Not Requiring (Providing) Cash






          Depreciation, Depletion and Amortization


2,383,359



1,822,854

          Impairments 


250,239



531,413

          Stock-Based Compensation Expenses


101,337



95,057

          Deferred Income Taxes


385,878



499,279

          Gains on Asset Dispositions, Net


(248,134)



(442,981)

          Other, Net


(10,266)



2,270

     Dry Hole Costs


13,005



47,231

     Mark-to-Market Commodity Derivative Contracts






          Total Gains


(327,328)



(480,539)

          Realized Gains


555,946



83,765

     Excess Tax Benefits from Stock-Based Compensation


(49,426)



-

     Other, Net


12,675



21,052

     Changes in Components of Working Capital and Other Assets and Liabilities






          Accounts Receivable


(112,174)



(128,965)

          Inventories


(154,766)



(167,611)

          Accounts Payable


83,682



245,385

          Accrued Taxes Payable


42,791



101,239

          Other Assets


(120,085)



(28,600)

          Other Liabilities


39,871



37,022

     Changes in Components of Working Capital Associated with Investing and Financing Activities


87,708



133,227

Net Cash Provided by Operating Activities


4,009,590



3,341,523







Investing Cash Flows






     Additions to Oil and Gas Properties


(5,326,884)



(4,665,535)

     Additions to Other Property, Plant and Equipment


(477,351)



(502,112)

     Proceeds from Sales of Assets


1,213,550



1,294,627

     Changes in Components of Working Capital Associated with Investing Activities


(87,654)



(133,512)

Net Cash Used in Investing Activities


(4,678,339)



(4,006,532)







Financing Cash Flows






     Common Stock Sold


-



1,388,270

     Long-Term Debt Borrowings


1,234,138



-

     Dividends Paid


(134,412)



(124,133)

     Excess Tax Benefits from Stock-Based Compensation


49,426



-

     Treasury Stock Purchased


(44,799)



(21,357)

     Proceeds from Stock Options Exercised and Employee Stock Purchase Plan


59,714



26,887

     Debt Issuance Costs


(1,771)



-

     Repayment of Capital Lease Obligation


(1,407)



-

     Other, Net


(54)



285

Net Cash Provided by Financing Activities


1,160,835



1,269,952







Effect of Exchange Rate Changes on Cash


4,811



(7,068)







Increase in Cash and Cash Equivalents


496,897



597,875

Cash and Cash Equivalents at Beginning of Period


615,726



788,853

Cash and Cash Equivalents at End of Period

$

1,112,623


$

1,386,728



EOG RESOURCES, INC.

QUANTITATIVE RECONCILIATION OF ADJUSTED NET INCOME (NON-GAAP) 

TO NET INCOME (GAAP)

(Unaudited; in thousands, except per share data)

























The following chart adjusts the three-month and nine-month periods ended September 30, 2012 and 2011 reported Net Income (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 impairment charges related to certain of EOG's North American assets in 2012 and 2011 and to eliminate the net gains 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 


Nine Months Ended


September 30,


September 30,


2012


2011


2012


2011













Reported Net Income (GAAP)

$

355,491


$

540,878


$

1,075,278


$

970,425













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












       Total Gains


(4,671)



(357,664)



(327,328)



(480,539)

       Realized Gains 


249,166



52,480



555,946



83,765

         Subtotal


244,495



(305,184)



228,618



(396,774)













       After-Tax MTM Impact


156,537



(195,394)



146,372



(254,035)













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


-



10,654



38,575



267,114

Less: Net Gains on Asset Dispositions, Net of Tax


(43,354)



(132,895)



(161,652)



(284,005)













Adjusted Net Income (Non-GAAP)

$

468,674


$

223,243


$

1,098,573


$

699,499













Net Income Per Share (GAAP)












       Basic

$

1.33


$

2.03


$

4.03


$

3.71

       Diluted

$

1.31


$

2.01


$

3.98


$

3.66













Adjusted Net Income Per Share (Non-GAAP)












       Basic

$

1.75


$

0.84


$

4.11


$

2.67

       Diluted

$

1.73

(a)

$

0.83

(b)

$

4.06


$

2.64













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


108%






















Average Number of Common Shares 












       Basic


267,941



266,053



267,136



261,664

       Diluted


270,982



269,292



270,328



265,245



EOG RESOURCES, INC.

QUANTITATIVE RECONCILIATION OF DISCRETIONARY CASH FLOW (NON-GAAP)

TO NET CASH PROVIDED BY OPERATING ACTIVITIES (GAAP)

(Unaudited; in thousands)













The following chart reconciles the three-month and nine-month periods ended September 30, 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


Nine Months Ended


September 30,


September 30,


2012


2011


2012


2011













Net Cash Provided by Operating Activities (GAAP)

$

1,436,372


$

1,272,283


$

4,009,590


$

3,341,523













Adjustments












     Exploration Costs (excluding Stock-Based Compensation Expenses) 


38,485



40,624



116,563



121,166

     Excess Tax Benefits from Stock-Based Compensation


27,311



-



49,426



-

     Changes in Components of Working Capital and Other Assets and Liabilities











          Accounts Receivable


227,593



(36,335)



112,174



128,965

          Inventories


51,190



40,549



154,766



167,611

          Accounts Payable


92,673



(56,135)



(83,682)



(245,385)

          Accrued Taxes Payable


(28,428)



(6,928)



(42,791)



(101,239)

          Other Assets


17,782



23,804



120,085



28,600

          Other Liabilities


(67,226)



(49,039)



(39,871)



(37,022)

     Changes in Components of Working Capital Associated with Investing and Financing Activities


(185,161)



(56,587)



(87,708)



(133,227)













Discretionary Cash Flow (Non-GAAP)

$

1,610,591

(a)

$

1,172,236

(b)

$

4,308,552


$

3,270,992













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


37%












EOG RESOURCES, INC.

QUANTITATIVE RECONCILIATION OF ADJUSTED EARNINGS BEFORE INTEREST EXPENSE, 

INCOME TAXES, DEPRECIATION, DEPLETION AND AMORTIZATION, EXPLORATION COSTS, 

DRY HOLE COSTS, IMPAIRMENTS AND ADDITIONAL ITEMS (ADJUSTED EBITDAX)

 (NON-GAAP) TO INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES (GAAP)

(Unaudited; in thousands)














The following chart adjusts the three-month and nine-month periods ended September 30, 2012 and 2011 reported Income Before Interest Expense and Income Taxes (GAAP) to Earnings Before Interest Expense, Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash realized from financial commodity derivative transactions by eliminating the unrealized mark-to-market (MTM) gains from these transactions and to eliminate the net gains 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 Before Interest Expense and Income Taxes (GAAP) to add back Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring items.  EOG management uses this information for comparative purposes within the industry.















Three Months Ended



Nine Months Ended 


September 30,



September 30,


2012


2011



2012


2011














Income Before Interest Expense and Income Taxes (GAAP)

$

613,343


$

951,407



$

1,880,760


$

1,821,939














Adjustments:













Depreciation, Depletion and Amortization


825,851



651,684




2,383,359



1,822,854

Exploration Costs


45,953



48,469




136,909



140,616

Dry Hole Costs


1,924



22,604




13,005



47,231

Impairments 


62,875



83,431




250,239



531,413

     EBITDAX (Non-GAAP)


1,549,946



1,757,595




4,664,272



4,364,053

Total Gains on MTM Commodity Derivative Contracts 


(4,671)



(357,664)




(327,328)



(480,539)

Realized Gains on MTM Commodity Derivative Contracts 


249,166



52,480




555,946



83,765

Net Gains on Asset Dispositions


(67,376)



(207,468)




(248,134)



(442,981)

     Adjusted EBITDAX (Non-GAAP)

$

1,727,065

 (a) 

$

1,244,943

 (b) 


$

4,644,756


$

3,524,298














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


39%





















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 November 5, 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  (1)


Average Price









(Bbld) 


($/Bbl) 




2012










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

34,000


$104.95




March 1, 2012 through June 30, 2012 (closed)


52,000


105.80




July 1, 2012 through August 31, 2012 (closed) 


50,000


106.90




September 2012 (closed)



32,000


106.61




October 2012 (closed)



42,000


105.19




November 1, 2012 through December 31, 2012


42,000


105.19















2013










January 1, 2013 through June 30, 2013


98,000


$99.39




July 1, 2013 through December 31, 2013


68,000


99.45
























(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 25,000 Bbld are exercisable on December 31, 2012.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 25,000 Bbld at an average price of $106.27 per barrel for the period January 1, 2013 through June 30, 2013. Options covering a notional volume of 59,000 Bbld are 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 59,000 Bbld at an average price of $100.45 per barrel for the period July 1, 2013 through December 31, 2013. Options covering a notional volume of 29,000 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 29,000 Bbld at an average price of $101.69 per barrel for the period January 1, 2014 through June 30, 2014.  

























NATURAL GAS DERIVATIVE CONTRACTS






















Weighted






Volume


Average Price









(MMBtud) 


($/MMBtu) 




2012(2)










January 1, 2012 through November 30, 2012 (closed)

525,000


$5.44




December 2012




525,000


5.44















2013(3)










January 1, 2013 through December 31, 2013


150,000


$4.79















2014(4)






























(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 December 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.



(4)

In July 2012, EOG settled its natural gas financial price swap contracts for the period January 1, 2014 through December 31, 2014 and received proceeds of $36.6 million.  In connection with these contracts, the counterparties retain an 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 2014.












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.

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.








September 30,




2012








Total Stockholders' Equity - (a)

$

13,793








Current and Long-Term Debt - (b)


6,312



Less: Cash 


(1,113)



Net Debt (Non-GAAP) - (c)


5,199








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

$

20,105








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

$

18,992








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


31%








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


27%




EOG RESOURCES, INC.

  FOURTH QUARTER AND FULL YEAR 2012 FORECAST AND BENCHMARK COMMODITY PRICING













(a)  Fourth Quarter and Full Year 2012 Forecast

 

The forecast items for the fourth 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)



4Q 2012



Full Year 2012

Daily Production












     Crude Oil and Condensate Volumes (MBbld)












          United States


149.8

-


162.2



148.2

-


151.3

          Canada


7.0

-


9.0



6.8

-


7.4

          Trinidad


0.8

-


1.0



1.3

-


1.6

          Other International


0.0

-


0.2



0.1

-


0.2

               Total


157.6

-


172.4



156.4

-


160.5













     Natural Gas Liquids Volumes (MBbld)












          United States


57.0

-


63.0



54.5

-


56.5

          Canada


0.6

-


1.0



0.7

-


0.9

               Total


57.6

-


64.0



55.2

-


57.4













     Natural Gas Volumes (MMcfd)












          United States


968

-


994



1,030

-


1,037

          Canada


75

-


95



92

-


97

          Trinidad


320

-


365



374

-


386

          Other International


9

-


11



9

-


11

               Total


1,372

-


1,465



1,505

-


1,531













     Crude Oil Equivalent Volumes (MBoed)  












          United States


368.1

-


390.9



374.4

-


380.6

          Canada


20.1

-


25.8



22.8

-


24.5

          Trinidad


54.1

-


61.8



63.6

-


65.9

          Other International


1.5

-


2.0



1.6

-


2.0

               Total


443.8

-


480.5



462.4

-


473.0


























ESTIMATED RANGES


(Unaudited)


4Q 2012


Full Year 2012

Operating Costs












     Unit Costs ($/Boe)












          Lease and Well

$

6.18

-

$

6.54


$

6.00

-

$

6.24

          Transportation Costs

$

3.78

-

$

4.02


$

3.36

-

$

3.60

          Depreciation, Depletion and Amortization

$

18.72

-

$

20.00


$

18.60

-

$

18.90













Expenses ($MM)












     Exploration, Dry Hole and Impairment

$

140.0

-

$

162.0


$

480.0

-

$

502.0

     General and Administrative

$

85.0

-

$

90.0


$

330.0

-

$

335.0

     Gathering and Processing 

$

29.0

-

$

33.0


$

101.0

-

$

105.5

     Capitalized Interest

$

12.0

-

$

16.0


$

48.7

-

$

52.7

     Net Interest

$

58.0

-

$

62.0


$

212.3

-

$

216.3













Taxes Other Than Income (% of Wellhead Revenue)


5.8%

-


6.2%



6.0%

-


6.2%













Income Taxes












     Effective Rate 


35%

-


40%



35%

-


40%

     Current Taxes ($MM)

$

100

-

$

115


$

360

-

$

380













Capital Expenditures ($MM) - FY 2012 (Excluding Non-cash Items)












     Exploration and Development, Excluding Facilities








Approximately


$

6,260

     Exploration and Development Facilities








Approximately


$

700

     Gathering, Processing and Other








Approximately


$

640













Pricing - (Refer to Benchmark Commodity Pricing in text)












     Crude Oil and Condensate ($/Bbl)












          Differentials












               United States - (above) below WTI

$

(5.00)

-

$

(10.00)


$

(2.90)

-

$

(4.15)

               Canada - (above) below WTI

$

2.50

-

$

6.00


$

8.00

-

$

9.20

               Trinidad - (above) below WTI

$

3.00

-

$

8.00


$

2.00

-

$

3.25













     Natural Gas Liquids












          Realizations as % of WTI












                United States


32%

-


38%



36%

-


37%

                Canada


50%

-


57%



48%

-


49%













     Natural Gas ($/Mcf)












          Differentials












               United States - (above) below NYMEX Henry Hub

$

0.15

-

$

0.30


$

0.21

-

$

0.25

               Canada - (above) below NYMEX Henry Hub

$

0.60

-

$

0.80


$

0.35

-

$

0.40













          Realizations












               Trinidad

$

3.50

-

$

4.00


$

3.55

-

$

3.70

               Other International

$

5.00

-

$

5.50


$

5.53

-

$

5.65














Definitions












$/Bbl      

U.S. Dollars per barrel

$/Boe      

U.S. Dollars per barrel of oil equivalent

$/Mcf      

U.S. Dollars per thousand cubic feet