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EOG Resources Reports Second Quarter 2013 Results; Increases 2013 Crude Oil Production Growth Target and Overall Total Production Estimates
PR Newswire
HOUSTON

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FOR IMMEDIATE RELEASE: August 6, 2013

HOUSTON, Aug. 6, 2013 /PRNewswire/ --

  • Delivers 35 Percent Year-Over-Year Total Company Crude Oil Production Growth
  • Raises 2013 Full Year Crude Oil Production Target to 35 Percent from 28 Percent
  • Increases Total Company Overall Production Growth Target to 7.5 Percent from 4 Percent
  • Announces Record South Texas Eagle Ford Oil Well
  • Extends Bakken/Three Forks Drilling Inventory and Posts Excellent North Dakota Well Results
  • Drives Down Costs in Key Areas of Operations

EOG Resources, Inc. (NYSE: EOG) today reported second quarter 2013 net income of $659.7 million, or $2.42 per share. This compares to second quarter 2012 net income of $395.8 million, or $1.47 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 second quarter 2013 was $573.8 million, or $2.10 per share. Adjusted non-GAAP net income for the second quarter 2012 was $312.4 million, or $1.16 per share. The results for the second quarter 2013 included net gains on asset dispositions of $9.4 million, net of tax ($0.04 per share), impairments of $2.0 million, net of tax ($0.01 per share) related to the sale of certain non-core North American assets and a previously disclosed non-cash net gain of $191.5 million ($122.6 million after tax, or $0.45 per share) on the mark-to-market of financial commodity contracts. During the quarter, the net cash inflow related to financial commodity contracts was $68.9 million ($44.1 million after tax, or $0.16 per share). (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)

EOG reported strong, sustained financial growth for the second quarter 2013. Compared to the second quarter 2012, earnings per share increased 65 percent, discretionary cash flow increased 35 percent and adjusted EBITDAX rose 34 percent. (Please refer to the attached tables for the reconciliation of 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 has captured premier positions in key U.S. onshore oil plays – the South Texas Eagle Ford, North Dakota Bakken and Delaware Basin, and we continue to enhance their profitability," said Mark G. Papa, Executive Chairman of the Board. "EOG's financial metrics reflect the superior quality of these assets, as well as our technical acumen in improving well completion design and our ongoing focus on reducing costs." 

Operational Highlights

EOG's U.S. crude oil and condensate production increased 37 percent both in the second quarter and the first half of 2013, compared to the same periods in 2012. Total company crude oil and condensate production increased 35 percent in the second quarter over the same prior year period. Total company liquids – crude oil, condensate and natural gas liquids (NGLs) – production rose 30 percent, versus the second quarter 2012.

Based on its exceptional performance during the first half of 2013, EOG is increasing its full year crude oil and condensate production growth target to 35 percent from 28 percent. Total NGL production is expected to increase 14 percent from the previous 10 percent target, while natural gas production is projected to decline 11.5 percent during 2013. Overall, EOG is targeting 7.5 percent total company production growth in 2013. EOG also anticipates certain unit costs will be lower than originally forecast.

"We have the confidence to raise the bar on EOG's performance expectations because our outstanding assets perform better and better, quarter after quarter," said President and Chief Executive Officer William R. "Bill" Thomas. "EOG expects to achieve these higher goals within our previously stated capex estimate."

At June 30, 2013, EOG's Eagle Ford net production of approximately 173,000 barrels of oil equivalent per day, continued to out-perform the rest of the industry.

Since discovering the prolific Eagle Ford, EOG has more than doubled the initial crude oil production rates from its wells in both the western and eastern parts of the play. Efficiency gains from more effective completions and reduced drilling days are resulting in excellent rates of return.

EOG recorded strong well and economic results from its western Eagle Ford acreage where more than a third of its second quarter drilling activity in the play occurred. In La Salle County, EOG's initial production rates and overall well productivity showed a marked improvement, compared to similar completions in the same area three years ago. The Keller #1H and #2H began production at rates of 1,855 and 2,050 barrels of crude oil per day (Bopd) with 75 and 50 barrels per day (Bpd) of NGLs and 430 and 300 thousand cubic feet per day (Mcfd) of natural gas, respectively. The Smart Unit #1H and #2H had initial rates of 1,495 and 2,030 Bopd with 60 and 75 Bpd of NGLs and 340 and 440 Mcfd of natural gas, respectively. The Dossett Unit #1H and #2H were completed to sales at 1,590 and 2,185 Bopd with 85 and 115 Bpd of NGLs and 490 and 655 Mcfd of natural gas, respectively. In McMullen County, the Naylor Jones B #1H started production at 1,830 Bopd with 240 Bpd of NGLs and 1.4 million cubic feet per day (MMcfd) of natural gas. EOG has 100 percent working interest in these seven wells.

EOG again achieved excellent well results in Gonzales County, the northeastern area of its Eagle Ford acreage. The Burrow Unit #3H, #4H and #5H were completed to sales in May at initial production rates of 2,990, 3,030 and 7,515 Bopd with 385, 370 and 860 Bpd of NGLs and 2.2, 2.1 and 5.0 MMcfd of natural gas, respectively. After 30 days, the Burrow Unit #5H, EOG's best Eagle Ford well to date, had an average production rate of 4,265 Bopd. The Wilde Trust Unit #1H, #2H and #3H began production in early June at rates of 5,475, 6,520 and 5,525 Bopd with 880, 710 and 775 Bpd of NGLs and 5.1, 4.1 and 4.5 MMcfd of natural gas, respectively. EOG has 100 percent working interest in these six Gonzales County wells.

"With wells in our western drilling program following the same trend as those in the east, results from the EOG's Eagle Ford activity continue to outpace our expectations," Papa said.

Improved drilling efficiencies and completion technology also have enhanced well productivity in EOG's Bakken/Three Forks operations. During the second quarter, EOG's North Dakota drilling program focused on the Bakken formation. In the Bakken Core, results from 160-acre spacing between wells continue to be encouraging. In Mountrail County, two Core wells drilled on 160-acre spacing, the Parshall 25-3032H and 22-3032H, were completed to sales at 2,685 and 2,120 Bopd, respectively. EOG has 62 percent working interest in these wells. EOG has 78 percent working interest in the Van Hook 29-1113H and 30-1113H, which began production at 2,390 and 2,295 Bopd, respectively, which were also 160-acre spaced wells.

In the Antelope Extension, EOG's other North Dakota development target this year, the Bear Den 20-1708H was completed in the Bakken formation at 2,455 Bopd. EOG has 91 percent working interest in the well.

Based on the success of its current spacing programs, EOG has increased its drilling inventory in the Bakken/Three Forks from seven to 12 years.

EOG remains active in the Delaware Basin Leonard and Wolfcamp, although the plays are constrained by a lack of natural gas processing infrastructure that is being addressed. In Reeves County, Texas, EOG drilled its best Delaware Basin Wolfcamp well to date. EOG has 100 percent working interest in the Phillips State 56 #301H, which was completed to sales at 870 Bopd with 570 Bpd of NGLs and 3.7 MMcfd of natural gas.

EOG completed and brought to sales a number of highly economic wells in the Leonard formation in Lea County, New Mexico. The Diamond 31 Fed Com #2H, #3H and #4H came online at 1,780, 1,905 and 1,530 Bopd with 215, 165 and 150 Bpd of NGLs and 1,200, 910 and 835 Mcfd of natural gas, respectively. EOG has 91 percent working interest in these wells.

"We expect EOG's three high rate-of-return oil plays, the Eagle Ford, Bakken/Three Forks and Delaware Basin, to provide us with years of drilling inventory, as well as significant growth opportunities," Papa said. "These plays just get bigger and better."

Hedging Activity

In recent weeks, EOG has increased the amount of crude oil hedges in place for the remainder of 2013. For the period August 1 through December 31, 2013, EOG has crude oil financial price swap contracts in place for approximately 121,200 Bpd at a weighted average price of $98.82 per barrel, excluding unexercised options.

For the full year 2014, EOG has crude oil financial price swap contracts in place for approximately 51,000 Bpd at a weighted average price of $96.43 per barrel, excluding unexercised options.

EOG also has hedged some natural gas volumes for 2013 and 2014. For the period September 1 through October 31, 2013, EOG has natural gas financial price swap contracts in place for 200,000 million British thermal units per day (MMBtud) at a weighted average price of $4.72 per million British thermal units (MMBtu), excluding unexercised options. For the period November 1 through December 31, 2013, EOG has hedged 150,000 MMBtud at a weighted average price of $4.79 per MMBtu, excluding unexercised options. For the full year 2014, EOG has natural gas financial price swap contracts in place for 170,000 MMBtud at a weighted average price of $4.54 per MMBtu, excluding unexercised options. (For a comprehensive summary of crude oil and natural gas derivative contracts, please refer to the attached tables.)           

Capital Structure

To date, EOG has closed on approximately $580 million of asset sales, exceeding its stated goal for the year. At June 30, 2013, EOG's total debt outstanding was $6,313 million for a debt-to-total capitalization ratio of 31 percent. Taking into account cash on the balance sheet of $1,228 million at the end of the second quarter, EOG's net debt was $5,085 million for a net debt-to-total capitalization ratio of 26 percent. (Please refer to the attached tables for the reconciliation of net debt (non-GAAP) to current and long-term debt (GAAP) and the reconciliation of net debt-to-total capitalization ratio (non-GAAP) to debt-to-total capitalization ratio (GAAP).)

Conference Call Scheduled for August 7, 2013

EOG's second quarter 2013 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Wednesday, August 7, 2013. To listen, log on to www.eogresources.com. The webcast will be archived on EOG's website through August 21, 2013.

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

This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.  All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production and costs, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements.  EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements.  In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, generate income or cash flows or pay dividends are forward-looking statements.  Forward-looking statements are not guarantees of performance.  Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct.  Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control.  Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:

  • 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, and EOG's ability to retain mineral licenses and leases;
  • 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 conditions and developments around the world (such as political instability and armed conflict), 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;
  • physical, electronic and cyber security breaches; and
  • the other factors described under Item 1A, "Risk Factors", on pages 16 through 23 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2012 and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the extent of their impact on our actual results.  Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves).  As noted above, statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines.  Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2012, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov.  In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com

For Further Information Contact: 

Investors

 

Maire A. Baldwin

 

(713) 651-6EOG (651-6364)

 

Kimberly A. Matthews

 

(713) 571-4676

   
 

Media

 

K Leonard

 

(713) 571-3870

 

 

EOG RESOURCES, INC.
FINANCIAL REPORT
(Unaudited; in millions, except per share data)

 
 

Three Months Ended

 

Six Months Ended

 

June 30,

 

June 30,

 

2013

 

2012

 

2013

 

2012

                       

Net Operating Revenues

$

3,840.2

 

$

2,909.3

 

$

7,196.7

 

$

5,716.0

Net Income 

$

659.7

 

$

395.8

 

$

1,154.4

 

$

719.8

Net Income Per Share 

                     
 

Basic

$

2.44

 

$

1.48

 

$

4.28

 

$

2.70

 

Diluted

$

2.42

 

$

1.47

 

$

4.24

 

$

2.67

Average Number of Common Shares

                     
 

Basic

 

270.0

   

266.9

   

269.7

   

266.7

 

Diluted

 

272.7

   

270.0

   

272.5

   

270.1

 
 

SUMMARY INCOME STATEMENTS
(Unaudited; in thousands, except per share data)

 
 

Three Months Ended

 

Six Months Ended

 

June 30,

 

June 30,

 

2013

 

2012

 

2013

 

2012

Net Operating Revenues

             
 

Crude Oil and Condensate

$

2,012,999

 

$

1,376,250

 

$

3,794,832

 

$

2,686,585

 

Natural Gas Liquids

 

178,457

   

150,023

   

347,986

   

348,333

 

Natural Gas

 

462,602

   

359,421

   

873,481

   

726,705

 

Gains on Mark-to-Market Commodity Derivative Contracts

 

191,490

   

188,449

   

86,534

   

322,657

 

Gathering, Processing and Marketing

 

959,413

   

710,748

   

1,882,370

   

1,428,905

 

Gains on Asset Dispositions, Net

 

13,153

   

113,290

   

177,386

   

180,758

 

Other, Net

 

22,071

   

11,138

   

34,110

   

22,027

   

Total

 

3,840,185

   

2,909,319

   

7,196,699

   

5,715,970

Operating Expenses

                     
 

Lease and Well

 

268,888

   

250,756

   

517,888

   

512,251

 

Transportation Costs

 

224,491

   

135,393

   

408,748

   

267,235

 

Gathering and Processing Costs

 

25,897

   

20,588

   

50,401

   

46,180

 

Exploration Costs

 

47,323

   

48,149

   

91,539

   

90,956

 

Dry Hole Costs

 

35,750

   

11,081

   

39,712

   

11,081

 

Impairments 

 

37,967

   

54,217

   

91,515

   

187,364

 

Marketing Costs

 

965,490

   

694,118

   

1,870,139

   

1,399,586

 

Depreciation, Depletion and Amortization

 

910,531

   

808,765

   

1,756,919

   

1,557,508

 

General and Administrative

 

80,607

   

75,727

   

158,592

   

151,996

 

Taxes Other Than Income

 

151,197

   

118,186

   

286,128

   

239,702

   

Total

 

2,748,141

   

2,216,980

   

5,271,581

   

4,463,859

 

Operating Income

 

1,092,044

   

692,339

   

1,925,118

   

1,252,111

 

Other Income (Expense), Net

 

4,833

   

4,675

   

(5,301)

   

15,306

 

Income Before Interest Expense and Income Taxes

 

1,096,877

   

697,014

   

1,919,817

   

1,267,417

 

Interest Expense, Net

 

61,647

   

50,775

   

123,568

   

101,044

 

Income Before Income Taxes

 

1,035,230

   

646,239

   

1,796,249

   

1,166,373

 

Income Tax Provision

 

375,538

   

250,461

   

641,832

   

446,586

 

Net Income

$

659,692

 

$

395,778

 

$

1,154,417

 

$

719,787

 

Dividends Declared per Common Share

$

0.1875

 

$

0.17

 

$

0.375

 

$

0.34

 

 

EOG RESOURCES, INC.

OPERATING HIGHLIGHTS

(Unaudited)

 
 

Three Months Ended

 

Six Months Ended

 

June 30,

 

June 30,

 

2013

 

2012

 

2013

 

2012

Wellhead Volumes and Prices

     

Crude Oil and Condensate Volumes (MBbld) (A)

     
 

United States

 

206.5

   

150.5

   

192.4

   

140.7

 

Canada

 

6.4

   

6.4

   

7.1

   

7.0

 

Trinidad

 

1.4

   

1.7

   

1.3

   

1.9

 

Other International (B)

 

0.1

   

0.1

   

0.1

   

0.1

   

Total

 

214.4

   

158.7

   

200.9

   

149.7

 

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

                     
 

United States

$

103.73

 

$

95.80

 

$

105.04

 

$

98.61

 

Canada

 

89.66

   

82.78

   

87.29

   

86.33

 

Trinidad

 

86.96

   

88.68

   

90.36

   

94.76

 

Other International (B)

 

92.28

   

91.20

   

93.56

   

96.49

   

Composite

 

103.19

   

95.20

   

104.31

   

98.00

 

Natural Gas Liquids Volumes (MBbld) (A)

                     
 

United States

 

63.7

   

54.6

   

61.2

   

52.4

 

Canada

 

1.0

   

0.9

   

0.9

   

0.9

   

Total

 

64.7

   

55.5

   

62.1

   

53.3

 

Average Natural Gas Liquids Prices ($/Bbl) ©

                     
 

United States

$

30.19

 

$

33.54

 

$

30.87

 

$

38.12

 

Canada

 

39.49

   

42.89

   

40.62

   

46.54

   

Composite

 

30.33

   

33.72

   

31.02

   

38.27

 

Natural Gas Volumes (MMcfd) (A)

                     
 

United States

 

928

   

1,070

   

931

   

1,067

 

Canada

 

79

   

96

   

79

   

100

 

Trinidad

 

346

   

422

   

349

   

396

 

Other International (B)

 

8

   

10

   

8

   

10

   

Total

 

1,361

   

1,598

   

1,367

   

1,573

 

Average Natural Gas Prices ($/Mcf) ©

                     
 

United States

$

3.73

 

$

2.09

 

$

3.41

 

$

2.28

 

Canada

 

3.17

   

2.21

   

3.21

   

2.33

 

Trinidad

 

3.82

   

3.42

   

3.86

   

3.21

 

Other International (B)

 

6.81

   

5.64

   

6.78

   

5.72

   

Composite

 

3.73

   

2.47

   

3.53

   

2.54

 

Crude Oil Equivalent Volumes (MBoed) (D)

                     
 

United States 

 

424.8

   

383.3

   

408.8

   

370.9

 

Canada

 

20.6

   

23.4

   

21.2

   

24.6

 

Trinidad

 

59.0

   

72.0

   

59.4

   

67.9

 

Other International (B)

 

1.5

   

1.8

   

1.4

   

1.8

   

Total

 

505.9

   

480.5

   

490.8

   

465.2

 

Total MMBoe (D)

 

46.0

   

43.7

   

88.8

   

84.7

 

(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.

© 

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)

 
 

June 30,

 

December 31,

 

2013

 

2012

 

ASSETS

Current Assets

         
 

Cash and Cash Equivalents

$

1,228,016

 

$

876,435

 

Accounts Receivable, Net

 

1,808,954

   

1,656,618

 

Inventories

 

657,400

   

683,187

 

Assets from Price Risk Management Activities

 

105,667

   

166,135

 

Income Taxes Receivable

 

23,450

   

29,163

 

Deferred Income Taxes

 

157,012

   

-

 

Other

 

260,341

   

178,346

     

Total

 

4,240,840

   

3,589,884

 

Property, Plant and Equipment

         
 

Oil and Gas Properties (Successful Efforts Method)

 

40,262,580

   

38,126,298

 

Other Property, Plant and Equipment

 

2,846,971

   

2,740,619

     

Total Property, Plant and Equipment

 

43,109,551

   

40,866,917

 

Less:  Accumulated Depreciation, Depletion and Amortization

 

(18,529,163)

   

(17,529,236)

     

Total Property, Plant and Equipment, Net

 

24,580,388

   

23,337,681

Other Assets

 

255,924

   

409,013

Total Assets

$

29,077,152

 

$

27,336,578

 

LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities

         
 

Accounts Payable

$

2,201,940

 

$

2,078,948

 

Accrued Taxes Payable

 

161,608

   

162,083

 

Dividends Payable

 

50,614

   

45,802

 

Liabilities from Price Risk Management Activities

 

5,482

   

7,617

 

Deferred Income Taxes

 

4,310

   

22,838

 

Current Portion of Long-Term Debt

 

406,579

   

406,579

 

Other

 

189,770

   

200,191

     

Total

 

3,020,303

   

2,924,058

 
 

Long-Term Debt

 

5,906,210

   

5,905,602

Other Liabilities

 

795,308

   

894,758

Deferred Income Taxes

 

4,970,705

   

4,327,396

Commitments and Contingencies

         
                 

Stockholders' Equity

         
 

Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 272,611,848 Shares Issued at June 30, 2013 and 271,958,495 Shares Issued at December 31, 2012 

         
   

202,726

   

202,720

 

Additional Paid in Capital

 

2,576,441

   

2,500,340

 

Accumulated Other Comprehensive Income 

 

408,257

   

439,895

 

Retained Earnings

 

11,228,011

   

10,175,631

 

Common Stock Held in Treasury, 277,274 Shares at June 30, 2013 and 326,264 Shares at December 31, 2012 

 

(30,809)

   

(33,822)

     

Total Stockholders' Equity

 

14,384,626

   

13,284,764

Total Liabilities and Stockholders' Equity

$

29,077,152

 

$

27,336,578

 

 

EOG RESOURCES, INC.

SUMMARY STATEMENTS OF CASH FLOWS

(Unaudited; in thousands)

 
 

Six Months Ended

 

June 30,

 

2013

 

2012

Cash Flows from Operating Activities

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

 

Net Income 

$

1,154,417

 

$

719,787

 

Items Not Requiring (Providing) Cash

     

Depreciation, Depletion and Amortization

 

1,756,919

   

1,557,508

     

Impairments 

 

91,515

   

187,364

     

Stock-Based Compensation Expenses

 

57,724

   

55,466

     

Deferred Income Taxes

 

488,632

   

278,826

     

Gains on Asset Dispositions, Net

 

(177,386)

   

(180,758)

     

Other, Net

 

8,747

   

(3,404)

 

Dry Hole Costs

 

39,712

   

11,081

 

Mark-to-Market Commodity Derivative Contracts

     

Total Gains

 

(86,534)

   

(322,657)

     

Realized Gains

 

135,959

   

306,780

 

Excess Tax Benefits from Stock-Based Compensation

 

(21,869)

   

(22,115)

 

Other, Net

 

7,759

   

9,890

 

Changes in Components of Working Capital and Other Assets and Liabilities

     

Accounts Receivable

 

(164,809)

   

115,419

     

Inventories

 

22,085

   

(103,576)

     

Accounts Payable

 

141,369

   

176,355

     

Accrued Taxes Payable

 

24,816

   

14,363

     

Other Assets

 

(92,305)

   

(102,303)

     

Other Liabilities

 

(51,400)

   

(27,355)

 

Changes in Components of Working Capital Associated with Investing and

 

Financing Activities

 

(19,639)

   

(97,453)

Net Cash Provided by Operating Activities

 

3,315,712

   

2,573,218

           

Investing Cash Flows

 

Additions to Oil and Gas Properties

 

(3,250,091)

   

(3,748,278)

 

Additions to Other Property, Plant and Equipment

 

(183,516)

   

(315,542)

 

Proceeds from Sales of Assets

 

579,941

   

1,111,517

 

Changes in Restricted Cash

 

(52,322)

   

-

 

Changes in Components of Working Capital Associated with Investing Activities

 

19,358

   

97,746

Net Cash Used in Investing Activities

 

(2,886,630)

   

(2,854,557)

           

Financing Cash Flows

 

Dividends Paid

 

(97,006)

   

(88,892)

 

Excess Tax Benefits from Stock-Based Compensation

 

21,869

   

22,115

 

Treasury Stock Purchased

 

(21,094)

   

(22,663)

 

Proceeds from Stock Options Exercised and Employee Stock Purchase Plan

 

20,773

   

32,986

 

Repayment of Capital Lease Obligation

 

(2,866)

   

-

 

Other, Net

 

281

   

(293)

Net Cash Used in Financing Activities

 

(78,043)

   

(56,747)

           

Effect of Exchange Rate Changes on Cash

 

542

   

2,734

           

Increase (Decrease) in Cash and Cash Equivalents

 

351,581

   

(335,352)

Cash and Cash Equivalents at Beginning of Period

 

876,435

   

615,726

Cash and Cash Equivalents at End of Period

$

1,228,016

 

$

280,374

 

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 six-month periods ended June 30, 2013 and 2012 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 eliminate the net gains on asset dispositions in North America in 2013 and 2012 and to add back impairment charges related to certain of EOG's North American assets in 2013 and 2012.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match realizations to production settlement months and make certain other adjustments to exclude non-recurring items.  EOG management uses this information for comparative purposes within the industry.

 
 

Three Months Ended 

 

Six Months Ended

 

June 30,

 

June 30,

 

2013

 

2012

 

2013

 

2012

 

Reported Net Income (GAAP)

$

659,692

 

$

395,778

 

$

1,154,417

 

$

719,787

 

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

                     
 

Total Gains

 

(191,490)

   

(188,449)

   

(86,534)

   

(322,657)

 

Realized Gains 

 

68,909

   

173,179

   

135,959

   

306,780

   

Subtotal

 

(122,581)

   

(15,270)

   

49,425

   

(15,877)

 
 

After-Tax MTM Impact

 

(78,482)

   

(9,776)

   

31,645

   

(10,165)

 

Less: Net Gains on Asset Dispositions, Net of Tax

 

(9,382)

   

(75,087)

   

(124,375)

   

(118,298)

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

 

2,003

   

1,526

   

2,003

   

38,575

 

Adjusted Net Income (Non-GAAP)

$

573,831

 

$

312,441

 

$

1,063,690

 

$

629,899

                           

Net Income Per Share (GAAP)

                     
 

Basic

 

$

2.44

 

$

1.48

 

$

4.28

 

$

2.70

 

Diluted

$

2.42

 (a) 

$

1.47

 (b) 

$

4.24

 

$

2.67

                           

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

 

65%

                 
 

Adjusted Net Income Per Share (Non-GAAP)

                       
 

Basic

 

$

2.13

 

$

1.17

 

$

3.94

 

$

2.36

 

Diluted

$

2.10

 

$

1.16

 

$

3.90

 

$

2.33

 

Average Number of Common Shares  

                     
 

Basic

   

270,016

   

266,874

   

269,665

   

266,718

 

Diluted

 

272,739

   

269,985

   

272,473

   

270,083

 

 

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 six-month periods ended June 30, 2013 and 2012 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP).  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities.  EOG management uses this information for comparative purposes within the industry.

 
 

Three Months Ended

 

Six Months Ended

 

June 30,

 

June 30,

 

2013

 

2012

 

2013

 

2012

 

Net Cash Provided by Operating Activities (GAAP)

$

1,890,777

 

$

1,495,613

 

$

3,315,712

 

$

2,573,218

                       

Adjustments

 

Exploration Costs (excluding Stock-Based Compensation Expenses) 

 

40,930

   

41,890

   

77,575

   

78,078

 

Excess Tax Benefits from Stock-Based Compensation

 

10,196

   

5,464

   

21,869

   

22,115

 

Changes in Components of Working Capital and Other Assets and Liabilities

                     
     

Accounts Receivable

 

(71,948)

   

(205,367)

   

164,809

   

(115,419)

     

Inventories

 

(37,143)

   

113,784

   

(22,085)

   

103,576

     

Accounts Payable

 

44,696

   

60,270

   

(141,369)

   

(176,355)

     

Accrued Taxes Payable

 

(15,812)

   

(19,526)

   

(24,816)

   

(14,363)

     

Other Assets

 

45,112

   

(6,537)

   

92,305

   

102,303

     

Other Liabilities

 

(1,533)

   

22,296

   

51,400

   

27,355

 

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

                     
   

(37,782)

   

(126,222)

   

19,639

   

97,453

 

Discretionary Cash Flow (Non-GAAP)

$

1,867,493

 (a) 

$

1,381,665

 (b) 

$

3,555,039

 

$

2,697,961

                             

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

 

35%

                 

 

 

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 six-month periods ended June 30, 2013 and 2012 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 2013 and 2012.  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

   

Six Months Ended 

 

June 30,

   

June 30,

 

2013

 

2012

   

2013

 

2012

                         

Income Before Interest Expense and Income Taxes (GAAP)

$

1,096,877

 

$

697,014

   

$

1,919,817

 

$

1,267,417

                         

Adjustments:

                       

Depreciation, Depletion and Amortization

 

910,531

   

808,765

     

1,756,919

   

1,557,508

Exploration Costs

 

47,323

   

48,149

     

91,539

   

90,956

Dry Hole Costs

 

35,750

   

11,081

     

39,712

   

11,081

Impairments 

 

37,967

   

54,217

     

91,515

   

187,364

     EBITDAX (Non-GAAP)

 

2,128,448

   

1,619,226

     

3,899,502

   

3,114,326

Total Gains on MTM Commodity Derivative Contracts 

 

(191,490)

   

(188,449)

     

(86,534)

   

(322,657)

Realized Gains on MTM Commodity Derivative Contracts 

 

68,909

   

173,179

     

135,959

   

306,780

Net Gains on Asset Dispositions

 

(13,153)

   

(113,290)

     

(177,386)

   

(180,758)

     Adjusted EBITDAX (Non-GAAP)

$

1,992,714

 (a) 

$

1,490,666

 (b) 

 

$

3,771,541

 

$

2,917,691

                         

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

 

34%

                   

 

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 August 6, 2013, with notional volumes expressed in Bbld and MMBtud and prices expressed in $/Bbl and $/MMBtu.  EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method.

 

CRUDE OIL DERIVATIVE CONTRACTS

 

Weighted

 

Volume 

 

Average Price

 

(Bbld) 

 

($/Bbl) 

 

2013(1)

 

January 2013 (closed)

101,000

 

$99.29

 

February 1, 2013 through April 30, 2013 (closed)

109,000

 

99.17

 

May 1, 2013 through June 30, 2013 (closed)

101,000

 

99.29

 

July 2013 (closed)

111,000

 

98.25

 

August 1, 2013 through September 30, 2013

126,000

 

98.80

 

October 1, 2013 through December 31, 2013

118,000

 

98.84

 
 

2014 (2)

 

January 1, 2014 through March 31, 2014

103,000

 

$96.48

 

April 1, 2014 through June 30, 2014

93,000

 

96.47

 

July 1, 2014 through December 31, 2014

5,000

 

95.43

 

(1)

EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional three-month and six-month periods.  Options covering a notional volume of 8,000 Bbld are exercisable on September 30, 2013.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 8,000 Bbld at an average price of $98.11 per barrel for each month during the period October 1, 2013 through December 31, 2013.  Options covering a notional volume of 64,000 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 64,000 Bbld at an average price of $99.58 per barrel for each month during the period January 1, 2014 through June 30, 2014.  

(2)

EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional six-month and nine-month periods.  Options covering a notional volume of 10,000 Bbld are exercisable on or about March 31, 2014.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 10,000 Bbld at an average price of $96.60 per barrel for each month during the period April 1, 2014 through December 31, 2014.  Options covering a notional volume of 93,000 Bbld are exercisable on or about June 30, 2014.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 93,000 Bbld at an average price of $96.47 per barrel for each month during the period July 1, 2014 through December 31, 2014.  Options covering a notional volume of 5,000 Bbld are exercisable on December 31, 2014.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 5,000 Bbld at an average price of $95.43 per barrel for each month during the period January 1, 2015 through June 30,2015.

 

NATURAL GAS DERIVATIVE CONTRACTS

 

Weighted

 

Volume

 

Average Price

 

(MMBtud) 

 

($/MMBtu) 

 

2013(3)

 

January 1, 2013 through April 30, 2013 (closed)

150,000

 

$4.79

 

May 1, 2013 through August 31, 2013 (closed)

200,000

 

4.72

 

September 1, 2013 through October 31, 2013

200,000

 

4.72

 

November 1, 2013 through December 31, 2013 

150,000

 

4.79

 
 

2014(4)

 

January 1, 2014 through December 31, 2014

170,000

 

$4.54

 

(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.  For the period September 1, 2013 through October 31, 2013, if the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 200,000 MMBtud at an average price of $4.72 per MMBtu for each month during that period.  For the period November 1, 2013 through December 31, 2013, 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 during that period.

(4)

EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates.  Additionally, in connection with certain natural gas derivative contracts settled in July 2012, counterparties retain an option of entering into derivative contracts at future dates.  All 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 320,000 MMBtud at an average price of $4.66 per MMBtu for each month during the period January 1, 2014 through December 31, 2014.

 
 

Bbld

 

Barrels per day

 
 

$/Bbl

 

Dollars per barrel

 
 

MMBtud

Million British thermal units per day

 
 

$/MMBtu

Dollars per million British thermal units

 
 

MMBtu

 

Million British thermal units

 

 

 

EOG RESOURCES, INC.

QUANTITATIVE RECONCILIATION OF NET DEBT (NON-GAAP) AND TOTAL 

CAPITALIZATION (NON-GAAP) AS USED IN THE CALCULATION OF 

THE NET DEBT-TO-TOTAL CAPITALIZATION RATIO (NON-GAAP) TO

CURRENT AND LONG-TERM DEBT (GAAP) AND TOTAL CAPITALIZATION (GAAP)

(Unaudited; in millions, except ratio data)

       

The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation.  A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation.  EOG management uses this information for comparative purposes within the industry.

       
     

At

   

June 30,

   

2013

       

Total Stockholders' Equity - (a)

$

14,385

 

Current and Long-Term Debt - (b)

 

6,313

Less: Cash 

 

(1,228)

Net Debt (Non-GAAP) - (c)

 

5,085

 

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

$

20,698

 

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

$

19,470

 

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

 

31%

 

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

 

26%

 

 

EOG RESOURCES, INC.

THIRD QUARTER AND FULL YEAR 2013 FORECAST AND BENCHMARK COMMODITY PRICING

 
 

(a)  Third Quarter and Full Year 2013 Forecast

           
 

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

 
 

(b)  Benchmark Commodity Pricing

           
 

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

 

EOG bases United States and Canada natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month.

                               
           

 

ESTIMATED RANGES

           

 

(Unaudited)

           

3Q 2013

   

Full Year 2013

Daily Production

                     
 

Crude Oil and Condensate Volumes (MBbld)

                     
   

United States

 

207.0

-

 

224.0

   

201.0

-

 

211.0

   

Canada

 

6.2

-

 

6.8

   

6.0

-

 

7.0

   

Trinidad

 

1.1

-

 

1.6

   

1.0

-

 

1.6

   

Other International

 

0.0

-

 

0.0

   

0.0

-

 

0.0

     

Total

 

214.3

-

 

232.4

   

208.0

-

 

219.6

 
 

Natural Gas Liquids Volumes (MBbld)

                     
   

United States

 

62.0

-

 

66.0

   

58.9

-

 

66.9

   

Canada

 

0.6

-

 

1.1

   

0.7

-

 

0.8

     

Total

 

62.6

-

 

67.1

   

59.6

-

 

67.7

                               
 

Natural Gas Volumes (MMcfd)

                     
   

United States

 

850

-

 

900

   

890

-

 

910

   

Canada

 

69

-

 

76

   

70

-

 

80

   

Trinidad

 

340

-

 

360

   

348

-

 

368

   

Other International

 

7

-

 

9

   

7

-

 

9

     

Total

 

1,266

-

 

1,345

   

1,315

-

 

1,367

 
 

Crude Oil Equivalent Volumes (MBoed)  

                     
   

United States

 

410.7

-

 

440.0

   

408.2

-

 

429.6

   

Canada

 

18.3

-

 

20.6

   

18.4

-

 

21.1

   

Trinidad

 

57.8

-

 

61.6

   

59.0

-

 

62.9

   

Other International

 

1.2

-

 

1.5

   

1.2

-

 

1.5

     

Total

 

488.0

-

 

523.7

   

486.8

-

 

515.1

 

Operating Costs

                     
 

Unit Costs ($/Boe)

                     
   

Lease and Well

$

6.37

-

$

6.62

 

$

6.05

-

$

6.25

   

Transportation Costs

$

4.57

-

$

4.82

 

$

4.45

-

$

4.85

   

Depreciation, Depletion and Amortization

$

19.50

-

$

20.00

 

$

19.60

-

$

20.10

 

Expenses ($MM)

                     
 

Exploration, Dry Hole and Impairment

$

130.0

-

$

170.0

 

$

510.0

-

$

540.0

 

General and Administrative

$

105.0

-

$

115.0

 

$

360.0

-

$

390.0

 

Gathering and Processing 

$

25.0

-

$

35.0

 

$

100.0

-

$

130.0

 

Capitalized Interest

$

12.0

-

$

15.0

 

$

40.0

-

$

50.0

 

Net Interest

$

58.0

-

$

60.0

 

$

226.0

-

$

246.0

 

Taxes Other Than Income (% of Wellhead Revenue)

 

5.9%

-

 

6.3%

   

5.5%

-

 

6.5%

 

Income Taxes

                     
 

Effective Rate 

 

30%

-

 

40%

   

35%

-

 

40%

 

Current Taxes ($MM)

$

80

-

$

90

 

$

305

-

$

325

 

Capital Expenditures ($MM) - FY 2013 (Excluding Acquisitions)

                     
 

Exploration and Development, Excluding Facilities

           

$

5,900

-

$

6,000

 

Exploration and Development Facilities

           

$

730

-

$

790

 

Gathering, Processing and Other

           

$

415

-

$

445

 

Pricing - (Refer to Benchmark Commodity Pricing in text)

                     
 

Crude Oil and Condensate ($/Bbl)

                     
   

Differentials

                     
     

United States - (above) below WTI

$

(2.00)

-

$

(3.50)

 

$

(5.40)

-

$

(7.40)

     

Canada - (above) below WTI

$

6.50

-

$

9.00

 

$

7.00

-

$

9.00

     

Trinidad - (above) below WTI

$

5.00

-

$

7.00

 

$

4.00

-

$

6.00

 
 

Natural Gas Liquids

                     
   

Realizations as % of WTI

                     
     

United States

 

28%

-

 

32%

   

28%

-

 

32%

     

Canada

 

40%

-

 

45%

   

39%

-

 

43%

 
 

Natural Gas ($/Mcf)

                     
   

Differentials

                     
     

United States - (above) below NYMEX Henry Hub

$

0.32

-

$

0.40

 

$

0.24

-

$

0.50

     

Canada - (above) below NYMEX Henry Hub

$

0.75

-

$

0.85

 

$

0.47

-

$

0.77

 
   

Realizations

                     
     

Trinidad

$

2.75

-

$

3.25

 

$

3.00

-

$

3.50

     

Other International

$

4.95

-

$

5.45

 

$

5.35

-

$

6.35

 

Definitions

                       

$/Bbl 

 

U.S. Dollars per barrel

         

$/Boe

U.S. Dollars per barrel of oil equivalent

         

$/Mcf 

 

U.S. Dollars per thousand cubic feet

         

$MM

 

U.S. Dollars in millions

         

MBbld

Thousand barrels per day

         

MBoed

Thousand barrels of oil equivalent per day

         

MMcfd

Million cubic feet per day

         

NYMEX

New York Mercantile Exchange

         

WTI

 

West Texas Intermediate

         

 

SOURCE EOG Resources, Inc.

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