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EOG Resources Reports Third Quarter 2010 Results
- Records 30 Percent Total Crude Oil and Condensate Production Increase Over Third Quarter 2009
- Increases Confidence in South Texas Eagle Ford Crude Oil Potential
- Delivers Outstanding Well Results from Resource Play Drilling Programs
- Proves Up Additional Acreage in New Mexico Leonard Shale
- Targets 9 Percent Total Company Organic Production Growth in 2010
PR Newswire
HOUSTON

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FOR IMMEDIATE RELEASE: Tuesday, November 2, 2010

HOUSTON, Nov. 2, 2010 /PRNewswire/ -- EOG Resources, Inc. (NYSE: EOG) (EOG) today reported a third quarter 2010 net loss of $70.9 million, or $0.28 per share. This compares to third quarter 2009 net income of $4.2 million, or $0.02 per share.

The results for the third quarter 2010 included a $208.3 million, net of tax ($0.82 per share) impairment of certain Canadian shallow natural gas assets held for sale, $41.4 million gain, net of tax ($0.16 per share) on property dispositions and a previously disclosed non-cash net gain of $61.0 million ($39.1 million after tax, or $0.16 per share) on the mark-to-market of financial commodity transactions. During the quarter, the net cash outflow related to financial commodity contracts was $13.6 million ($8.7 million after tax, or $0.03 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 quarter was $46.6 million, or $0.18 per share. Adjusted non-GAAP net income for the third quarter 2009 was $203.9 million, or $0.81 per share. (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)  

Operational Highlights

EOG reported a 30 percent increase in total company crude oil and condensate production for the third quarter, compared to the same period in 2009. In the United States, crude and condensate production increased 29 percent.

In the South Texas Eagle Ford Play, EOG has steadily escalated the pace of both its drilling and completion operations. Results from the 77 wells drilled to date across its 120-mile, 505,000 net acre position in the mature oil window, reinforce EOG’s confidence in its estimated 900 million barrels of oil equivalent, net after royalty resource potential, 77 percent of which is crude oil.

Patterned after successful development activity in its other resource plays, EOG is drilling and completing wells in batches to optimize resource recovery. Significant production increases are expected in 2011 as numerous clusters of wells are turned to production. Currently operating a 10-rig drilling program in the Eagle Ford, EOG plans to add one more rig by year-end and average 14 rigs in 2011.

Among EOG’s South Texas Eagle Ford wells, in which EOG has a 100 percent working interest, are:

  • Cusack Clampit #1H, #2H, #3H and #4H – This cluster of Gonzales County wells began flowing to sales at rates of 860 to 1,800 barrels of oil per day (Bopd) with 1,020 to 1,770 thousand cubic feet per day (Mcfd) of rich natural gas.
  • Beynon #1H – This Karnes County well was completed at an initial peak rate of 902 Bopd with 1,110 Mcfd of rich natural gas.
  • Greenlow #5H – Drilled in Karnes County, this well began initial production at a rate of 720 Bopd with 1,030 Mcfd of rich natural gas.
 

“Well data generated throughout the year from the Eagle Ford reflects an increase in our estimates of recoveries per well relative to our April 2010 estimates. This upside not only enhances the rate of return of the play but indicates fewer wells than we originally anticipated will be needed to capture our net reserve potential of 900 million barrels of oil equivalent,” said Mark G. Papa, Chairman and Chief Executive Officer.

With an active 16-rig drilling program in the Fort Worth Barnett Combo, this key EOG asset is in full development mode. After alleviating fracture crew constraints during the first half of 2010, EOG is focusing on multi-well development patterns in Montague and western Cooke Counties. Recent drilling results in Cooke County have expanded EOG’s Core area from 150,000 to 160,000 net acres. EOG expects to exit 2010 with strong crude oil production momentum that will carry into 2011 and beyond. In the current natural gas environment, Combo economics are bolstered by the mix of oil and rich natural gas production with total liquids production contributing over 90 percent of revenue. In the past, liquids had contributed roughly 66 percent of the revenue stream from the play.

EOG’s Barnett Shale Combo well highlights from Cooke and Montague Counties include:

  • Christian C #3H – This Cooke County well, in which EOG has a 98 percent working interest, began producing to sales at a gross rate of 954 Bopd with 1,608 Mcfd of rich natural gas.
  • Strickland A #2H – Drilled horizontally, this Cooke County well began flowing to sales at a gross rate of 1,118 Bopd with 1,801 Mcfd of rich natural gas. EOG has a 90 percent working interest in the well.
  • Strickland #1 – This vertically drilled Cooke County well, in which EOG has a 96 percent working interest, began production at a gross rate of 865 Bopd with 1,212 Mcfd of rich natural gas.
  • Settle C #3H – EOG has a 91 percent working interest in this Cooke County well that was completed at a rate of 731 Bopd with 2,135 Mcfd of rich natural gas, gross.
  • Nutter #1H – Drilled in western Cooke County, this well began flowing to sales at a rate of 672 Bopd with 838 Mcfd of rich natural gas, gross. EOG has a 99 percent working interest in the well.
  • Slagle #2H and #1 – Drilled in the western part of Cooke County, these wells were completed with initial rates of 495 and 539 Bopd with 138 and 307 Mcfd of rich natural gas, respectively. The Slagle #2H was drilled and completed horizontally, while the Slagle #1 was drilled and completed vertically. EOG has a 100 percent working interest in both wells.
  • Posey C#3H – Brought to sales at a rate of 536 Bopd with 416 Mcfd of rich natural gas, this well, in which EOG has a 100 percent working interest, was drilled in western Montague County.
 

In EOG’s largest crude oil producing asset, the North Dakota Bakken, well completion operations resumed during the second quarter following the winter 2009-2010 drilling program. A significant number of wells began flowing to sales, contributing to EOG’s overall crude oil production increase. These results included a number of horizontal Mandaree wells on EOG’s 18,000 net acres in McKenzie County, North Dakota, southwest of Parshall. These wells were turned to sales in the third quarter with strong initial production rates and favorable economics.

EOG’s North Dakota and Montana Bakken well highlights are:

  • Mandaree 4-15H – This well was completed in the second quarter at a peak production rate of 1,490 Bopd, gross. EOG has a 69 percent working interest in the well.
  • Mandaree 2-9H – EOG holds an 88 percent working interest in this well, which was drilled and completed to sales at a maximum rate of 1,358 Bopd, gross.
  • Mandaree 1-10H – Maximum initial production from this well, in which EOG has a 90 percent working interest, was 1,659 Bopd, gross.
  • Ed and Paul 1-17H – EOG has an 80 percent working interest in the well, which was drilled in Richland County, Montana and was completed to sales at a maximum gross rate of over 2,000 Bopd.
 

In its sixth year of development in the Bakken, EOG is operating a 10-rig drilling program in North Dakota and Montana.

In the New Mexico Leonard Shale, EOG reported continued drilling success on an additional 18,000 acres and, combined with previous reported success on 31,000 acres, has now proven up 49,000 of its 120,000 total net acre position. The Elk Wallow 11 State #1H has been producing for over 30 days at an average rate of 337 Bopd with 3,070 Mcfd of rich natural gas. The Elk Wallow 11 State #2H has been producing for 11 days at an average rate of 505 Bopd with 4,770 Mcfd of rich natural gas. EOG has 100 percent working interest in these Eddy County wells.

“EOG is delivering remarkable organic production growth from its portfolio of crude oil and liquids resource plays. In 2011, approximately 67 percent of EOG’s North American revenue will be derived from liquids,” said Papa. “By mid-2011, EOG expects to have optimized its South Texas Eagle Ford crude oil production such that it will be a meaningful long-term crude oil producer both for EOG and for the United States.”

Based on reduced cash flows resulting from weak natural gas prices and fracture equipment delays, EOG has reduced its 2010 total company organic production growth forecast from 13 percent to 9 percent. Decreases in North American natural gas drilling activity account for 70 percent of the 2010 volume reduction. For 2011 and 2012, EOG has provided preliminary total company organic production growth forecasts of 10 percent and 12 percent, respectively. EOG expects crude oil and condensate production increases of 53 percent and 30 percent, respectively, to drive total company production growth for that two-year period.

Capital Structure

At September 30, 2010, EOG’s total debt was $3,769 million for a debt-to-total capitalization ratio of 27 percent. Taking into account cash on the balance sheet of $28 million, at the end of the quarter EOG’s net debt was $3,741 million and the net debt-to-total capitalization ratio was 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).)

To maintain a low debt-to-total capitalization ratio, during 2010 EOG has marketed certain of its properties, primarily natural gas. EOG expects to sell between $600 million and $1 billion of both producing and non-producing properties in North America. The majority of these transactions are expected to close during the fourth quarter of 2010. EOG incurred a $208.3 million, net of tax, impairment during the third quarter associated with certain of its Canadian shallow natural gas assets held for sale.

2011 Strategy

Following a comparison of its inventory of attractive rate of return, liquids-rich drilling opportunities against depressed natural gas prices, EOG has elected to pursue additional natural gas asset sales in 2011. Proceeds from these sales will be used primarily to offset any funding gap between planned capital expenditures and estimated cash flows. While previously targeting a maximum net debt-to-total capitalization ratio of 25 percent, EOG has set the maximum net debt-to-total capitalization ratio at 30 percent to 35 percent in order to optimally fund its portfolio of liquids-rich drilling opportunities.

“EOG remains committed to its long-term philosophy of delivering strong returns to shareholders and maintaining a conservative balance sheet,” Mr. Papa said. “However, EOG does not intend to sell-down or joint venture any of its crude oil resource plays as we continue our strategic shift from natural gas to liquids. The growth potential of these robust assets is expected to accelerate EOG’s shift toward liquids, while increasing our margins in the coming years.”

Conference Call Scheduled for November 3, 2010

EOG’s third quarter 2010 results conference call will be available via live audio webcast at 8 a.m. Central Daylight Time (9 a.m. Eastern Daylight Time) on Wednesday, November 3, 2010. To listen, log on to www.eogresources.com. The webcast will be archived on EOG’s website through November 17, 2010.

EOG Resources, Inc. is one of the largest independent (non-integrated) 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, including the accompanying forecast and benchmark commodity pricing information, 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 natural gas, crude oil and related commodities;
  • changes in demand for natural gas, crude oil and related commodities, including ammonia and methanol;
  • the extent to which EOG is successful in its efforts to discover and  market reserves and to acquire natural gas and crude oil properties;
  • 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 natural gas and crude oil exploration and development projects, given the risks and uncertainties inherent in drilling, completing and operating natural gas and crude oil wells and the potential for interruptions of production, whether involuntary or intentional as a result of market or other conditions;
  • 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;
  • changes in government policies, laws and regulations, including environmental and tax laws and regulations;
  • 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;
  • EOG's ability to obtain access to surface locations for drilling and production facilities;
  • the extent to which EOG's third-party-operated natural gas and crude oil properties are operated successfully and economically;
  • EOG's ability to effectively integrate acquired natural gas and crude oil 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;
  • weather, including its impact on natural gas and crude oil 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 accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
  • 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 extent and effect of any hedging activities engaged in by EOG;
  • the timing and impact of liquefied natural gas imports;
  • 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 19 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2009.
 

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) now 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 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, 2009, 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)

Media and Investors
Elizabeth M. Ivers
(713) 651-7132

EOG RESOURCES, INC.

 

FINANCIAL REPORT

 

(Unaudited; in millions, except per share data)

 
                   
                       
           

Three Months Ended

 

Nine Months Ended

 
           

September 30,

 

September 30,

 
           

2010

 

2009

 

2010

 

2009

 
                                   

Net Operating Revenues

$

1,582.1

 

$

1,006.8

 

$

4,310.7

 

$

3,026.1

 

Net Income (Loss)

   

$

(70.9)

 

$

4.2

 

$

107.0

 

$

146.2

 

Net Income (Loss) Per Share

                       
 

Basic

     

$

(0.28)

 

$

0.02

 

$

0.43

 

$

0.59

 
 

Diluted

     

$

(0.28)

 

$

0.02

 

$

0.42

 

$

0.58

 

Average Number of Shares Outstanding

                       
 

Basic

       

251.0

   

249.5

   

250.7

   

248.6

 
 

Diluted

       

251.0

   

252.4

   

254.4

   

251.3

 
                                   
                                 

 

SUMMARY INCOME STATEMENTS

 

(Unaudited; in thousands, except per share data)

 
                     
           

Three Months Ended

 

Nine Months Ended

 
           

September 30,

 

September 30,

 
           

2010

 

2009

 

2010

 

2009

 

Net Operating Revenues

                       
 

Natural Gas

   

$

602,242

 

$

450,304

 

$

1,832,578

 

$

1,477,926

 
 

Crude Oil, Condensate and Natural Gas Liquids

 

613,850

   

398,806

   

1,683,088

   

886,268

 
 

Gains on Mark-to-Market Commodity Derivative Contracts

 

60,998

   

20,877

   

105,816

   

405,830

 
 

Gathering, Processing and Marketing

 

233,971

   

134,553

   

601,790

   

249,679

 
 

Gains (Losses) on Property Dispositions

 

64,809

   

(232)

   

72,441

   

510

 
 

Other, Net

     

6,205

   

2,541

   

15,023

   

5,884

 
   

Total

     

1,582,075

   

1,006,849

   

4,310,736

   

3,026,097

 

Operating Expenses

                         
 

Lease and Well

   

180,921

   

142,183

   

507,647

   

422,288

 
 

Transportation Costs

 

103,262

   

70,971

   

286,318

   

205,844

 
 

Gathering and Processing Costs

 

18,472

   

13,318

   

47,353

   

44,552

 
 

Exploration Costs

   

47,307

   

44,910

   

148,635

   

128,840

 
 

Dry Hole Costs

   

2,700

   

3,016

   

45,095

   

39,653

 
 

Impairments

   

352,908

   

69,404

   

502,865

   

181,921

 
 

Marketing Costs

   

231,758

   

131,816

   

591,735

   

237,819

 
 

Depreciation, Depletion and Amortization

 

500,888

   

385,330

   

1,398,137

   

1,150,251

 
 

General and Administrative

 

81,310

   

62,775

   

206,470

   

179,481

 
 

Taxes Other Than Income

 

74,244

   

47,823

   

227,773

   

118,715

 
   

Total

     

1,593,770

   

971,546

   

3,962,028

   

2,709,364

 
                                   

Operating Income (Loss)

 

(11,695)

   

35,303

   

348,708

   

316,733

 
                                   

Other Income (Expense), Net

 

5,772

   

(339)

   

7,910

   

2,637

 
                                   

Income (Loss) Before Interest Expense and Income Taxes

 

(5,923)

   

34,964

   

356,618

   

319,370

 
                                   

Interest Expense, Net

   

32,890

   

30,407

   

88,215

   

73,594

 
                                   

Income (Loss) Before Income Taxes

 

(38,813)

   

4,557

   

268,403

   

245,776

 
                                   

Income Tax Provision

   

32,093

   

361

   

161,422

   

99,576

 
                                   

Net Income (Loss)

 

$

(70,906)

 

$

4,196

 

$

106,981

 

$

146,200

 
                                   

Dividends Declared per Common Share

$

0.155

 

$

0.145

 

$

0.465

 

$

0.435

 
                                 

 

EOG RESOURCES, INC.

 

OPERATING HIGHLIGHTS

 

(Unaudited)

 
                             
       

Three Months Ended

 

Nine Months Ended

 
       

September 30,

 

September 30,

 
       

2010

 

2009

 

2010

 

2009

 

Wellhead Volumes and Prices

                       

Natural Gas Volumes (MMcfd) (A)

                       
 

United States

 

1,175

   

1,128

   

1,096

   

1,153

 
 

Canada

 

200

   

219

   

205

   

224

 
 

Trinidad

 

333

   

268

   

342

   

266

 
 

Other International (B)

 

14

   

13

   

15

   

15

 
   

Total

 

1,722

   

1,628

   

1,658

   

1,658

 
                               

Average Natural Gas Prices ($/Mcf) ©

                       
 

United States

$

4.21

 

$

3.27

 

$

4.50

 

$

3.57

 
 

Canada

 

3.42

   

3.15

   

4.09

   

3.67

 
 

Trinidad

 

2.53

   

1.77

   

2.54

   

1.54

 
 

Other International (B)

 

5.41

   

3.53

   

4.64

   

4.45

 
   

Composite

 

3.80

   

3.01

   

4.05

   

3.27

 
                               

Crude Oil and Condensate Volumes (MBbld) (A)

                       
 

United States

 

66.6

   

51.7

   

59.5

   

46.5

 
 

Canada

 

5.9

   

4.7

   

6.1

   

3.6

 
 

Trinidad

 

4.8

   

3.0

   

4.7

   

3.0

 
 

Other International (B)

 

0.1

   

0.1

   

0.1

   

0.1

 
   

Total

 

77.4

   

59.5

   

70.4

   

53.2

 
                               

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

                       
 

United States

$

71.54

 

$

60.79

 

$

72.58

 

$

49.54

 
 

Canada

 

69.12

   

61.43

   

71.32

   

51.91

 
 

Trinidad

 

65.06

   

57.07

   

66.91

   

46.13

 
 

Other International (B)

 

74.14

   

57.93

   

72.80

   

50.11

 
   

Composite

 

70.96

   

60.65

   

72.09

   

49.51

 
                               

Natural Gas Liquids Volumes (MBbld) (A)

                       
 

United States

 

31.1

   

23.1

   

27.4

   

22.2

 
 

Canada

 

0.8

   

1.0

   

0.9

   

1.1

 
   

Total

 

31.9

   

24.1

   

28.3

   

23.3

 
                               

Average Natural Gas Liquids Prices ($/Bbl) ©

                       
 

United States

$

36.56

 

$

31.15

 

$

40.68

 

$

26.42

 
 

Canada

 

40.34

   

30.96

   

42.90

   

27.29

 
   

Composite

 

36.66

   

31.14

   

40.75

   

26.46

 
                               

Natural Gas Equivalent Volumes (MMcfed) (D)

                       
 

United States

 

1,761

   

1,577

   

1,617

   

1,566

 
 

Canada

 

240

   

253

   

247

   

252

 
 

Trinidad

 

362

   

286

   

370

   

284

 
 

Other International (B)

 

15

   

13

   

16

   

15

 
   

Total

 

2,378

   

2,129

   

2,250

   

2,117

 
                               

Total Bcfe (D)

 

218.8

   

195.9

   

614.1

   

578.1

 
                               

(A)

Million cubic feet per day or thousand barrels per day, as applicable.

 

(B)

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

 

©

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

 

(D)

Million cubic feet equivalent per day or billion cubic feet equivalent, as applicable; includes natural gas, crude oil and condensate and natural gas liquids.  Natural gas equivalents are determined using the ratio of 6.0 thousand cubic feet of natural gas to 1.0 barrel of crude oil and condensate or natural gas liquids.  Bcfe is calculated by multiplying the MMcfed 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,

 
         

2010

 

2009

 
                     
 

ASSETS

 

Current Assets

             
 

Cash and Cash Equivalents

 

$

27,832

 

$

685,751

 
 

Accounts Receivable, Net

   

897,732

   

771,417

 
 

Inventories

   

381,263

   

261,723

 
 

Assets from Price Risk Management Activities

   

60,728

   

20,915

 
 

Income Taxes Receivable

   

89,357

   

37,009

 
 

Other

     

77,533

   

62,726

 
 

    Total

   

1,534,445

   

1,839,541

 
                     

Property, Plant and Equipment

             
 

Oil and Gas Properties (Successful Efforts Method)

   

28,208,613

   

24,614,311

 
 

Other Property, Plant and Equipment

   

1,598,453

   

1,350,132

 
 

   Total Property, Plant and Equipment

   

29,807,066

   

25,964,443

 
 

Less:  Accumulated Depreciation, Depletion and Amortization

   

(11,557,256)

   

(9,825,218)

 
 

   Total Property, Plant and Equipment, Net

   

18,249,810

   

16,139,225

 

Other Assets

   

160,604

   

139,901

 

Total Assets

 

$

19,944,859

 

$

18,118,667

 
                     
 

LIABILITIES AND STOCKHOLDERS' EQUITY

 

Current Liabilities

             
 

Accounts Payable

 

$

1,541,268

 

$

979,139

 
 

Accrued Taxes Payable

   

114,763

   

92,858

 
 

Dividends Payable

   

38,946

   

36,286

 
 

Liabilities from Price Risk Management Activities

   

29,144

   

27,218

 
 

Deferred Income Taxes

   

45,367

   

35,414

 
 

Current Portion of Long-Term Debt

   

-

   

37,000

 
 

Other

     

168,812

   

137,645

 
 

    Total

   

1,938,300

   

1,345,560

 
                     
                     

Long-Term Debt

   

3,768,638

   

2,760,000

 

Other Liabilities

   

695,855

   

632,652

 

Deferred Income Taxes

   

3,423,942

   

3,382,413

 

Commitments and Contingencies

             
                     

Stockholders' Equity

             
 

Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 253,985,680 Shares Issued at September 30, 2010 and 252,627,177 Shares Issued at December 31, 2009

   

202,540

   

202,526

 
 

Additional Paid In Capital

   

695,046

   

596,702

 
 

Accumulated Other Comprehensive Income

   

375,847

   

339,720

 
 

Retained Earnings

   

8,855,869

   

8,866,747

 
 

Common Stock Held in Treasury, 145,613 Shares at September 30, 2010 and 118,525 Shares at December 31, 2009

   

(11,178)

   

(7,653)

 
   

    Total Stockholders' Equity

   

10,118,124

   

9,998,042

 

Total Liabilities and Stockholders’ Equity

 

$

19,944,859

 

$

18,118,667

 
                   

 
 

EOG RESOURCES, INC.

 
 

SUMMARY STATEMENTS OF CASH FLOWS

 
 

(Unaudited; in thousands)

 
                   
       

Nine Months Ended

 
       

September 30,

 
       

2010

 

2009

 

Cash Flows from Operating Activities

           

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

           
 

Net Income

$

106,981

 

$

146,200

 
 

Items Not Requiring (Providing) Cash

             
   

Depreciation, Depletion and Amortization

 

1,398,137

   

1,150,251

 
   

Impairments

 

502,865

   

181,921

 
   

Stock-Based Compensation Expenses

 

81,700

   

74,532

 
   

Deferred Income Taxes

 

53,067

   

39,793

 
   

Gains on Property Dispositions, Net

 

(72,441)

   

(510)

 
   

Other, Net

 

(2,317)

   

3,248

 
 

Dry Hole Costs

 

45,095

   

39,653

 
 

Mark-to-Market Commodity Derivative Contracts

           
   

Total Gains

 

(105,816)

   

(405,830)

 
   

Realized Gains

 

25,180

   

986,980

 
 

Excess Tax Benefits from Stock-Based Compensation

 

-

   

(34,052)

 
 

Other, Net

 

13,354

   

9,385

 
 

Changes in Components of Working Capital and Other Assets and Liabilities

           
   

Accounts Receivable

 

(124,813)

   

119,099

 
   

Inventories

 

(134,181)

   

(23,592)

 
   

Accounts Payable

 

527,418

   

(361,698)

 
   

Accrued Taxes Payable

 

(40,104)

   

16,097

 
   

Other Assets

 

(16,051)

   

(4,255)

 
   

Other Liabilities

 

44,348

   

9,357

 
 

Changes in Components of Working Capital Associated with Investing and

           
 

    Financing Activities

 

(216,695)

   

147,097

 

Net Cash Provided by Operating Activities

 

2,085,727

   

2,093,676

 
                   

Investing Cash Flows

           
 

Additions to Oil and Gas Properties

 

(3,740,883)

   

(2,267,884)

 
 

Additions to Other Property, Plant and Equipment

 

(223,072)

   

(240,614)

 
 

Proceeds from Sales of Assets

 

126,371

   

2,515

 
 

Changes in Components of Working Capital Associated with Investing

           
 

    Activities

 

216,546

   

(146,783)

 
 

Other, Net

 

(4,206)

   

1,405

 

Net Cash Used in Investing Activities

 

(3,625,244)

   

(2,651,361)

 
                   

Financing Cash Flows

           
 

Net Commercial Paper Borrowings

 

33,700

   

-

 
 

Long-Term Debt Borrowings

 

991,395

   

900,000

 
 

Long-Term Debt Repayments

 

(37,000)

   

-

 
 

Dividends Paid

 

(114,277)

   

(105,989)

 
 

Excess Tax Benefits from Stock-Based Compensation

 

-

   

34,052

 
 

Treasury Stock Purchased

 

(10,298)

   

(9,888)

 
 

Proceeds from Stock Options Exercised and Employee Stock Purchase Plan

 

24,527

   

13,691

 
 

Debt Issuance Costs

 

(6,469)

   

(8,887)

 
 

Other, Net

 

149

   

(314)

 

Net Cash Provided by Financing Activities

 

881,727

   

822,665

 
                   

Effect of Exchange Rate Changes on Cash

 

(129)

   

12,220

 
                   

(Decrease) Increase in Cash and Cash Equivalents

 

(657,919)

   

277,200

 

Cash and Cash Equivalents at Beginning of Period

 

685,751

   

331,311

 

Cash and Cash Equivalents at End of Period

$

27,832

 

$

608,511

 
                 

 

EOG RESOURCES, INC.

 

QUANTITATIVE RECONCILIATION OF ADJUSTED NET INCOME (NON-GAAP)

 

TO NET INCOME (LOSS) (GAAP)

 

(Unaudited; in thousands, except per share data)

 
                           
                           

The following chart adjusts three-month and nine-month periods ended September 30, 2010 and 2009 reported Net Income (Loss) (GAAP) to reflect actual net cash realized from financial commodity price transactions by eliminating the unrealized mark-to-market gains from these transactions, to add back the loss on the impairment of certain of EOG's Canadian shallow natural gas assets in the third quarter of 2010, to eliminate the change in the estimated fair value of a contingent consideration liability related to EOG's previously disclosed acquisition of Haynesville and Bossier Shale unproved acreage and to eliminate the gains on property dispositions primarily in the Rocky Mountain area.  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 one-time items.  EOG management uses this information for comparative purposes within the industry.

 
                           
                       
   

Three Months Ended

 

Nine Months Ended

 
   

September 30,

 

September 30,

 
   

2010

 

2009

 

2010

 

2009

 
                           

Reported Net Income (Loss) (GAAP)

$

(70,906)

 

$

4,196

 

$

106,981

 

$

146,200

 
                           

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

                       
 

Total Gains

 

(60,998)

   

(20,877)

   

(105,816)

   

(405,830)

 
 

Realized Gains (Losses)

 

(13,647)

   

331,240

   

25,180

   

986,980

 
 

  Subtotal

 

(74,645)

   

310,363

   

(80,636)

   

581,150

 
                           
 

After-Tax MTM Impact

 

(47,791)

   

199,719

   

(51,627)

   

373,970

 
                           

Add: Impairment of Canadian Shallow Natural Gas Assets, Net of Tax

 

208,331

   

-

   

208,331

   

-

 

Less: Gains on Property Dispositions, Net of Tax

 

(41,494)

   

-

   

(46,381)

   

-

 

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

 

(1,587)

   

-

   

(12,941)

   

-

 
                           

Adjusted Net Income (Non-GAAP)

$

46,553

 

$

203,915

 

$

204,363

 

$

520,170

 
                           

Net Income (Loss) Per Share (GAAP)

                       
 

Basic

$

(0.28)

 

$

0.02

 

$

0.43

 

$

0.59

 
 

Diluted

$

(0.28)

 

$

0.02

 

$

0.42

 

$

0.58

 
                           

Adjusted Net Income Per Share (Non-GAAP)

                       
 

Basic

$

0.19

 

$

0.82

 

$

0.82

 

$

2.09

 
 

Diluted

$

0.18

 

$

0.81

 

$

0.80

 

$

2.07

 
                           

Average Number of Shares (GAAP)

                       
 

Basic

 

251,015

   

249,535

   

250,719

   

248,647

 
 

Diluted

 

251,015

   

252,422

   

254,444

   

251,288

 
                           

Average Number of Shares (Non-GAAP)

                       
 

Basic

 

251,015

   

249,535

   

250,719

   

248,647

 
 

Diluted

 

254,572

   

252,422

   

254,444

   

251,288

 
                         

 

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 three-month and nine-month periods ended September 30, 2010 and 2009 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,

 
     

2010

 

2009

 

2010

 

2009

 
                             

Net Cash Provided by Operating Activities (GAAP)

$

784,387

 

$

816,458

 

$

2,085,727

 

$

2,093,676

 
                             

Adjustments

                       
 

Exploration Costs (excluding Stock-Based Compensation Expenses)

 

40,095

   

39,814

   

130,598

   

113,644

 
 

Excess Tax Benefits from Stock-Based Compensation

 

-

   

12,178

   

-

   

34,052

 
 

Changes in Components of Working Capital and Other Assets and Liabilities

                       
   

Accounts Receivable

 

85,538

   

29,922

   

124,813

   

(119,099)

 
   

Inventories

 

66,818

   

1,441

   

134,181

   

23,592

 
   

Accounts Payable

 

(272,540)

   

(53,125)

   

(527,418)

   

361,698

 
   

Accrued Taxes Payable

 

34,093

   

(11,966)

   

40,104

   

(16,097)

 
   

Other Assets

 

(8,448)

   

(3,232)

   

16,051

   

4,255

 
   

Other Liabilities

 

(55,278)

   

(34,199)

   

(44,348)

   

(9,357)

 
 

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

 

80,722

   

22,086

   

216,695

   

(147,097)

 
                             
                             

Discretionary Cash Flow (Non-GAAP)

$

755,387

 

$

819,377

 

$

2,176,403

 

$

2,339,267

 
                           

 

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,

 
   

2010

 
         
 

Total Stockholders' Equity - (a)

$

10,118

 
         
 

Current and Long-Term Debt - (b)

 

3,769

 
 

Less: Cash

 

(28)

 
 

Net Debt (Non-GAAP) - (c)

 

3,741

 
         
 

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

$

13,887

 
         
 

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

$

13,859

 
         
 

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

 

27%

 
         
 

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

 

27%

 
       

 

EOG RESOURCES, INC.

   

 FOURTH QUARTER AND FULL YEAR 2010 FORECAST AND BENCHMARK COMMODITY PRICING

   
                             

    (a)  Fourth Quarter and Full Year 2010 Forecast

 

The forecast items for the fourth quarter and full year 2010 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. This forecast replaces and supersedes any previously issued guidance or forecast.

 

    (b) Benchmark Commodity Pricing

 

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.

 

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.

 
         

ESTIMATED RANGES

 
         

(Unaudited)

 
           

4Q 2010

 

Full Year 2010

   

Daily Production

                   
 

Natural Gas Volumes (MMcfd)

                   
   

United States

 

1,200

-

1,290

 

1,122

-

1,145

   
   

Canada

 

165

-

200

 

195

-

205

   
   

Trinidad

 

265

-

335

 

322

-

340

   
   

Other International

 

10

-

14

 

13

-

15

   
     

Total

 

1,640

-

1,839

 

1,652

-

1,705

   
                             
 

Crude Oil and Condensate Volumes (MBbld)

                   
   

United States

 

71.0

-

84.0

 

62.4

-

65.7

   
   

Canada

 

7.0

-

9.0

 

6.3

-

6.8

   
   

Trinidad

 

4.0

-

5.0

 

4.5

-

4.8

   
     

Total

 

82.0

-

98.0

 

73.2

-

77.3

   
                             
 

Natural Gas Liquids Volumes (MBbld)

                   
   

United States

 

28.0

-

40.0

 

27.5

-

30.5

   
   

Canada

 

0.5

-

1.0

 

0.8

-

1.0

   
     

Total

 

28.5

-

41.0

 

28.3

-

31.5

   
                             
 

Natural Gas Equivalent Volumes (MMcfed)

                   
   

United States

 

1,794

-

2,034

 

1,661

-

1,722

   
   

Canada

 

210

-

260

 

238

-

252

   
   

Trinidad

 

289

-

365

 

349

-

369

   
   

Other International

 

10

-

14

 

13

-

15

   
     

Total

 

2,303

-

2,673

 

2,261

-

2,358

   
                             

Operating Costs

                   
 

Unit Costs ($/Mcfe)

                   
   

Lease and Well

 

$      0.80

-

$      0.85

 

$        0.81

-

$       0.84

   
   

Transportation Costs

 

$      0.45

-

$      0.50

 

$        0.45

-

$       0.48

   
   

Depreciation, Depletion and Amortization

 

$      2.38

-

$      2.48

 

$        2.31

-

$       2.38

   
                             

Expenses ($MM)

                   
 

Exploration, Dry Hole and Impairment

 

$    160.0

-

$    175.0

 

$      577.0

-

$     592.0

*

 
 

General and Administrative

 

$      75.0

-

$      80.0

 

$      280.0

-

$     288.0

   
 

Gathering and Processing

 

$      16.5

-

$      19.0

 

$        64.0

-

$       66.5

   
 

Capitalized Interest

 

$      19.0

-

$      21.5

 

$        75.0

-

$       78.5

   
 

Net Interest

 

$      35.0

-

$      37.0

 

$      122.0

-

$     125.0

   
                             

Taxes Other Than Income (% of Revenue)

 

6.3%

-

6.6%

 

6.4%

-

6.7%

   
                             

Income Taxes

                     
 

Effective Rate

 

30%

-

45%

 

40%

-

50%

   
 

Current Taxes ($MM)

 

$         75

-

$         90

 

$         180

-

$        200

   
                             

Capital Expenditures ($MM) - FY 2010 (Excluding Acquisitions)

                 
 

Exploration and Development, Excluding Facilities

       

Approximately

 

$     4,970

   
 

Exploration and Development Facilities

       

Approximately

 

$        380

   
 

Gathering, Processing and Other

       

Approximately

 

$        400

   
                             

Pricing - (Refer to Benchmark Commodity Pricing in text)

                   
 

Natural Gas ($/Mcf)

                   
   

Differentials (include the effect of physical contracts)

                 
     

United States - below NYMEX Henry Hub

 

$      0.15

-

$      0.25

 

$        0.14

-

$       0.18

   
     

Canada - below NYMEX Henry Hub

 

$      0.26

-

$      0.36

 

$        0.45

-

$       0.50

   
                             
   

Realizations

                   
     

Trinidad

 

$      1.90

-

$      2.60

 

$        2.34

-

$       2.62

   
     

Other International

 

$      4.00

-

$      6.50

 

$        4.25

-

$       5.25

   
                             
 

Crude Oil and Condensate ($/Bbl)

                   
   

Differentials

                   
     

United States - below WTI

 

$      4.00

-

$      6.50

 

$        4.45

-

$       5.00

   
     

Canada - below WTI

 

$      6.25

-

$      7.50

 

$        5.90

-

$       6.50

   
     

Trinidad - below WTI

 

$    10.00

-

$    12.80

 

$      10.00

-

$     11.75

   
                             

* Excludes $280 million impairment of certain Canadian shallow natural gas assets held for sale.

         
                             

Definitions

                   
 

$/Bbl

 

U.S. Dollars per barrel

         
 

$/Mcf

 

U.S. Dollars per thousand cubic feet

           
 

$/Mcfe

 

U.S. Dollars per thousand cubic feet equivalent

           
 

$MM

 

U.S. Dollars in millions

           
 

MBbld

 

Thousand barrels per day

           
 

MMcfd

 

Million cubic feet per day

           
 

MMcfed

 

Million cubic feet equivalent per day

           
 

NYMEX

 

New York Mercantile Exchange

           
 

WTI

 

West Texas Intermediate

           
                           

 

SOURCE EOG Resources, Inc.

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