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EOG Resources Reports Second Quarter 2012 Results and Increases 2012 Crude Oil Production Growth Target to 37 Percent
PR Newswire
HOUSTON

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FOR IMMEDIATE RELEASE: August 2, 2012

HOUSTON, Aug. 2, 2012 /PRNewswire/ --

  • Reports Strong Year-Over-Year Growth in Earnings Per Share, Discretionary Cash Flow and Adjusted EBITDAX
  • Achieves 52 Percent Crude Oil and Condensate Production Increase and 49 Percent Increase in Total Liquids Production Over Second Quarter 2011
  • Increases 2012 Total Company Crude Oil Production Growth Target to 37 Percent from 33 Percent and Full Year Total Company Total Liquids Growth Target to 35 Percent from 33 Percent
  • Raises 2012 Total Company Production Growth Target to 9 Percent from 7 Percent with Unchanged 2012 Capital Expenditure Budget
  • Realizes Premium Crude Oil Prices from Rail Offloading Facility at St. James, Louisiana
  • Attains New Marketing Opportunities for Eagle Ford Volumes Through Recently Completed Third-Party Crude Oil Pipeline and Natural Gas Processing Plant and Pipelines
  • Delivers Best Crude Oil Well to Date as Solid Execution of Eagle Ford Drilling Program Continues
  • Sustains Successful Bakken Drilling Program in Core, Antelope Extension and Stateline Areas
  • Closes on $1.1 Billion of Asset Sales through June 30, 2012; Targets $1.2 to $1.25 Billion of Sales for Full Year 2012

EOG Resources, Inc. (NYSE: EOG) (EOG) today reported second quarter 2012 net income of $395.8 million, or $1.47 per share. This compares to second quarter 2011 net income of $295.6 million, or $1.10 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 2012 was $312.4 million, or $1.16 per share. Adjusted non-GAAP net income for the second quarter 2011 was $299.2 million, or $1.11 per share. The results for the second quarter 2012 included impairments of $1.5 million, net of tax ($0.01 per share) related to certain non-core North American assets, net gains on asset dispositions of $75.1 million, net of tax ($0.28 per share) and a previously disclosed non-cash net gain of $188.4 million ($120.7 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 $173.2 million ($110.9 million after tax, or $0.41 per share). (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)

With 86 percent of North American wellhead revenues currently derived from crude oil, condensate and natural gas liquids, EOG delivered strong earnings per share growth of 64 percent for the first half of 2012 compared to the same period in 2011. Discretionary cash flow increased 29 percent and adjusted EBITDAX rose 28 percent over the first half of 2011. (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's financial and operating results get better and better. We are achieving this consistent string of home runs because EOG has captured the finest inventory of onshore crude oil assets in the entire United States and has the technical acumen to maximize reserve recoveries," said Mark G. Papa, Chairman and Chief Executive Officer. "EOG is the largest crude oil producer in the South Texas Eagle Ford and North Dakota Bakken with the sweet spot positions in both plays. In addition, we are uniquely positioned to market a significant portion of this crude oil at robust Brent-type pricing through our own rail offloading facility at St. James, Louisiana, and to reach the Houston Gulf Coast market via the recently completed Enterprise Eagle Ford pipeline."

Operational Highlights

Due to robust operational results from the Eagle Ford and Bakken plays, EOG's total crude oil and condensate production for the second quarter 2012 increased 52 percent compared to the second quarter 2011. Total crude oil, condensate and natural gas liquids production increased 49 percent over the same period in 2011. Based on these outstanding results, together with contributions from its West Texas Wolfcamp and New Mexico Leonard horizontal shale plays, EOG has increased its 2012 total company crude oil and condensate production growth target to 37 percent from 33 percent and its total liquids production growth target to 35 percent from 33 percent. Overall, EOG has increased its total company full year 2012 production growth target to 9 percent from 7 percent with no changes to its capital expenditure budget.

In the South Texas Eagle Ford, EOG drilled its best well to date. The Boothe Unit #10H in Gonzales County began initial production at 4,820 barrels of oil per day (Bopd) while an offset well, the Boothe Unit #9H, had an initial production rate of 3,708 Bopd. The Boothe wells produced 972 and 527 barrels per day (Bpd) of natural gas liquids (NGLs) and 4.5 and 2.4 million cubic feet per day (MMcfd) of associated natural gas production, respectively.

"We continually focus on making better wells and with an initial flow rate in excess of 4,800 barrels of crude oil per day, EOG's Boothe Unit #10H is clearly the top producing oil well in the entire Eagle Ford play to date," Papa added.

Drilled from the same pad as the Boothe wells to minimize costs, the Dreyer Unit #19H and #20H were turned to sales at initial rates of 3,703 and 2,650 Bopd with 460 and 300 Bpd of NGLs and 2.1 and 1.4 MMcfd of natural gas, respectively. EOG has 100 percent working interest in these four wells.

Also in Gonzales County, the Henkhaus Unit #9H, #10H and #11H flowed at individual initial well rates of 4,184, 3,546, and 4,140 Bopd, with 633, 730 and 670 Bpd of NGLs and 2.9, 3.4 and 3.1 MMcfd of natural gas, respectively. The Guadalupe Unit #5H, #6H, #7H and #8H were turned to sales early in the second quarter at initial individual crude oil production rates ranging from 2,675 to 3,900 Bopd with 175 to 590 Bpd of NGLs and 800 thousand cubic feet per day (Mcfd) to 2.7 MMcfd of natural gas. EOG has 100 percent working interest in these seven wells.

In Karnes County, the Crews Unit #1H, #2H, #3H, #4H and #5H initially produced at individual well rates ranging from 2,645 to 2,986 Bopd with 193 to 390 Bpd of NGLs and 900 Mcfd to 1.8 MMcfd of natural gas. EOG has 100 percent working interest in these five wells.

EOG's marketing options for its prolific Eagle Ford production expanded in July when Enterprise Products Partners L.P. (Enterprise) began first commercial operation of the first phase of a 24-inch crude oil pipeline linking the Eagle Ford with extensive Houston area refining markets. Enterprise also has commissioned a new natural gas processing plant, as well as rich natural gas pipelines to gather and transport production to its Mont Belvieu NGL complex.

In the Bakken, EOG's 90,000 net acre Core Parshall Field has evolved into a growth engine fueled by success from drilling wells on tighter densities. Initial infill drilling results in the over-pressured Core area and simultaneous increased production rates from proximate existing wells indicate significant amounts of recoverable crude oil remain. In an effort to improve recovery of the resource in place, EOG plans to further develop the Core on 320-acre spacing and test even tighter drilling densities.

During the second quarter, EOG reported a number of favorable results from its ongoing infill drilling program in the Core area. In Mountrail County, the Liberty LR 12-11H and Liberty LR 15-26H tested at 1,037 and 1,114 Bopd with 720 and 552 Mcfd of natural gas, respectively. EOG has 66 percent and 95 percent working interest in the wells, respectively. Also in the Core area, the Fertile 42-3231H and the Fertile 49-3024H came online at 1,063 Bopd with 408 Mcfd of natural gas and 928 Bopd with 365 Mcfd of natural gas, respectively. EOG has 69 percent and 80 percent working interest, respectively, in the wells.

In McKenzie County, North Dakota, 25 miles southwest of the Bakken Core, EOG is realizing economic production from its inventory of both Bakken and Three Forks drilling locations on its Antelope Extension prospect. EOG has 94 percent working interest in the Riverview 04-3031H drilled in the Bakken and the Riverview 100-3031H drilled in the Three Forks. The wells had initial production rates of 1,863 Bopd with 730 Mcfd of natural gas and 1,834 Bopd with 1.3 MMcfd of natural gas, respectively. Completed in the Bakken, the Clarks Creek 10-0805H initially produced 1,478 Bopd with 576 Mcfd of natural gas, while the Clarks Creek 100-0805H had an initial rate of 1,437 Bopd with 635 Mcfd of natural gas from the Three Forks. EOG has 85 percent working interest in the two wells. Also in the Antelope prospect, the Mandaree 16-04H, in which EOG has 90 percent working interest, produced 1,059 Bopd with 960 Mcfd of natural gas from the Bakken formation. In Roosevelt County, Montana, EOG completed the Stateline 08-3328H, with an initial production rate of 1,260 Bopd with 687 Mcfd of natural gas. EOG has 39 percent working interest in the well.

Having identified a large, multi-year drilling inventory on its Bakken Core, Antelope Extension and Stateline acreage, EOG expects to post crude oil production growth from North Dakota and Montana in 2013 and beyond.

In the West Texas and New Mexico Permian Basin, EOG is operating a seven-rig drilling program. Five rigs are operating in the Texas Wolfcamp horizontal shale play in Irion, Crockett and Reagan counties where drilling operations are defining the pervasiveness of the Wolfcamp middle interval across EOG's acreage. During the second quarter and early July, a number of wells from the middle Wolfcamp were brought to sales. In Irion County, the Munson #1001H, #1002H and #1003H came on-line at 1,110, 856 and 1,015 Bopd with 80, 70 and 40 Bpd of NGLs and 455, 405 and 230 Mcfd of natural gas, respectively. EOG has 85 percent working interest in these three Munson wells. The University 43A-#0802H, 43A-#0803H, 43A-#0805H and 43A-#0807H began production at individual initial rates ranging from 610 to 760 Bopd with 35 to 105 Bpd of NGLs and 200 to 590 Mcfd of natural gas. EOG has 50 percent working interest in these four Irion County University 43A wells.

EOG is operating two rigs in the New Mexico Leonard horizontal shale play in Eddy and Lea counties. The Ross Draw 8 Fed #2H had 722 Bopd of initial production with 270 Bpd of NGLs and 1.9 MMcfd of natural gas. The Ross Gulch 8 Fed Com #1H began sales at 540 Bopd with 145 Bpd of NGLs and 990 Mcfd of natural gas. EOG has 88 and 91 percent working interest in these Eddy County wells, respectively. In Lea County, EOG has 100 percent working interest in the Pitchblende 29 Fed Com #1H, which had an initial production rate of 1,026 Bopd with 120 Bpd of NGLs and 650 Mcfd of natural gas. This significant step-out well sets up numerous additional drilling locations. Early in the third quarter, EOG completed the Vaca 14 Fed #4H in Lea County with first sales of 986 Bopd with 200 Bpd of NGLs and 1.1 MMcfd of natural gas. EOG has 100 percent working interest in the well. Following the Eagle Ford and Bakken, EOG's Permian Basin operation was the third largest contributor to its crude oil and condensate production growth during the second quarter.

Crude Oil and Liquids Activity

"We increased EOG's 2012 crude oil production growth target to 37 percent based on the strength of our drilling results for the first half of the year. This new goal sets EOG up to achieve an all-organic, five-year compounded annual crude oil production growth rate of 38 percent through year-end 2012," Papa said.

"Looking ahead, we expect EOG's resource-rich portfolio will continue to generate high crude oil production growth rates for a long time," Papa added.

Natural Gas Activity

Due to the ongoing weakness in natural gas pricing, EOG plans to further decrease drilling activity on its dry gas resource plays in the second half of 2012. Through active drilling programs in prior years and 2012 to date, EOG has captured strategic natural gas acreage in the Uinta, Horn River, Barnett, Haynesville and Marcellus plays. When natural gas prices rebound, EOG will hold an attractive portfolio of natural gas resources for future development.

Hedging Activity

EOG has hedged approximately 22 percent of its North American crude oil production from August 1 to December 31, 2012. EOG has crude oil financial price swap contracts in place for an average of 35,600 Bpd at a weighted average price of $106.69 per barrel, excluding unexercised options. For the period January 1 to June 30, 2013, EOG has crude oil financial price swap contracts in place for an average of 16,000 barrels per day at a weighted average price of $98.12.

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

Capital Structure

Through June 30, 2012 EOG's cash proceeds from asset sales were approximately $1,112 million. EOG is targeting total asset sales for the year of $1.2 to $1.25 billion. At June 30, 2012, EOG's total debt outstanding was $5,012 million for a debt-to-total capitalization ratio of 27 percent. Taking into account cash on the balance sheet of $280 million at the end of the second quarter, EOG's net debt was $4,732 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 long-term debt (GAAP) and the reconciliation of net debt-to-total capitalization ratio (non-GAAP) to debt-to-total capitalization ratio (GAAP).)

"By harnessing our team's outstanding technical expertise and innovative marketing strengths to EOG's exceptional asset base, during the first half of 2012 we achieved a number of our corporate goals. EOG reported growth in earnings per share, discretionary cash flow and adjusted EBITDAX. With our tremendous momentum, we increased our crude oil production growth target twice, achieved our asset sales goal and maintained a strong balance sheet," Papa said. "Moving into the second half of the year, our focus is on realizing our 2012 goal of 37 percent crude oil production growth while we moderate our drilling activity level to stay within our capital budget."

Conference Call Scheduled for August 3, 2012

EOG's second quarter 2012 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Friday, August 3, 2012. To listen, log on to www.eogresources.com. The webcast will be archived on EOG's website through August 17, 2012.

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

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

  • the timing and extent of changes in prices for, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities;
  • the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
  • the extent to which EOG can optimize reserve recovery and economically develop its plays utilizing horizontal and vertical drilling, advanced completion technologies and hydraulic fracturing;
  • the extent to which EOG is successful in its efforts to economically develop its acreage in, and to produce reserves and achieve anticipated production levels from, its existing and future crude oil and natural gas exploration and development projects, given the risks and uncertainties and capital expenditure requirements inherent in drilling, completing and operating crude oil and natural gas wells and the potential for interruptions of development and production, whether involuntary or intentional as a result of market or other conditions;
  • the extent to which EOG is successful in its efforts to market its crude oil, natural gas and related commodity production;
  • the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities;
  • the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights-of-way;
  • the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations, environmental laws and regulations relating to air emissions, waste disposal, hydraulic fracturing and access to and use of water, laws and regulations imposing conditions and restrictions on drilling and completion operations and laws and regulations with respect to derivatives and hedging activities;
  • EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties;
  • the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully and economically;
  • competition in the oil and gas exploration and production industry for employees and other personnel, equipment, materials and services and, related thereto, the availability and cost of employees and other personnel, equipment, materials and services;
  • the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
  • weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation of production, gathering, processing, compression and transportation facilities;
  • the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
  • EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;
  • the extent and effect of any hedging activities engaged in by EOG;
  • the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
  • political developments around the world, including in the areas in which EOG operates;
  • the use of competing energy sources and the development of alternative energy sources;
  • the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;
  • acts of war and terrorism and responses to these acts; and
  • the other factors described under Item 1A, "Risk Factors," on pages 15 through 23 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2011 and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

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

Effective January 1, 2010, the United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). As noted above, statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2011, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.

For Further Information Contact:

Investors

 

Maire A. Baldwin

 

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

 

Elizabeth M. Ivers

 

(713) 651-7132

   
 

Media

 

K Leonard

 

(713) 571-3870

 

EOG RESOURCES, INC.

FINANCIAL REPORT

(Unaudited; in millions, except per share data)

                       
                       
 

Three Months Ended

 

Six Months Ended

 

June 30,

 

June 30,

 

2012

 

2011

 

2012

 

2011

                       

Net Operating Revenues

$

2,909.3

 

$

2,570.3

 

$

5,716.0

 

$

4,467.4

Net Income

$

395.8

 

$

295.6

 

$

719.8

 

$

429.5

Net Income Per Share

                     

Basic

$

1.48

 

$

1.11

 

$

2.70

 

$

1.65

Diluted

$

1.47

 

$

1.10

 

$

2.67

 

$

1.63

Average Number of Common Shares

                     

Basic

 

266.9

   

265.8

   

266.7

   

259.8

Diluted

 

270.0

   

269.3

   

270.1

   

263.4

                       
                       
 
 
 
 

SUMMARY INCOME STATEMENTS

(Unaudited; in thousands, except per share data)

                       
                       
 

Three Months Ended

 

Six Months Ended

 

June 30,

 

June 30,

 

2012

 

2011

 

2012

 

2011

Net Operating Revenues

                     

Crude Oil and Condensate

$

1,376,250

 

$

938,518

 

$

2,686,585

 

$

1,695,880

Natural Gas Liquids

 

150,023

   

183,805

   

348,333

   

332,532

Natural Gas

 

359,421

   

599,993

   

726,705

   

1,183,912

Gains on Mark-to-Market Commodity Derivative Contracts

 

188,449

   

189,621

   

322,657

   

122,875

Gathering, Processing and Marketing

 

710,748

   

487,698

   

1,428,905

   

883,281

Gains on Asset Dispositions, Net

 

113,290

   

163,771

   

180,758

   

235,513

Other, Net

 

11,138

   

6,844

   

22,027

   

13,363

Total

 

2,909,319

   

2,570,250

   

5,715,970

   

4,467,356

Operating Expenses

                     

Lease and Well

 

250,756

   

216,695

   

512,251

   

431,784

Transportation Costs

 

135,393

   

101,965

   

267,235

   

199,598

Gathering and Processing Costs

 

20,588

   

17,716

   

46,180

   

36,912

Exploration Costs

 

48,149

   

41,238

   

90,956

   

92,147

Dry Hole Costs

 

11,081

   

1,676

   

11,081

   

24,627

Impairments

 

54,217

   

358,654

   

187,364

   

447,982

Marketing Costs

 

694,118

   

469,437

   

1,399,586

   

854,846

Depreciation, Depletion and Amortization

 

808,765

   

602,944

   

1,557,508

   

1,171,170

General and Administrative

 

75,727

   

67,406

   

151,996

   

137,443

Taxes Other Than Income

 

118,186

   

104,266

   

239,702

   

210,143

Total

 

2,216,980

   

1,981,997

   

4,463,859

   

3,606,652

                       

Operating Income

 

692,339

   

588,253

   

1,252,111

   

860,704

                       

Other Income, Net

 

4,675

   

6,224

   

15,306

   

9,828

                       

Income Before Interest Expense and Income Taxes

 

697,014

   

594,477

   

1,267,417

   

870,532

                       

Interest Expense, Net

 

50,775

   

51,253

   

101,044

   

101,586

                       

Income Before Income Taxes

 

646,239

   

543,224

   

1,166,373

   

768,946

                       

Income Tax Provision

 

250,461

   

247,650

   

446,586

   

339,399

                       

Net Income

$

395,778

 

$

295,574

 

$

719,787

 

$

429,547

                       

Dividends Declared per Common Share

$

0.17

 

$

0.16

 

$

0.34

 

$

0.32

                       
 
 
 

EOG RESOURCES, INC.

OPERATING HIGHLIGHTS

(Unaudited)

                       
 

Three Months Ended

 

Six Months Ended

 

June 30,

 

June 30,

 

2012

 

2011

 

2012

 

2011

Wellhead Volumes and Prices

                     

Crude Oil and Condensate Volumes (MBbld) (A)

                     

United States

 

150.5

   

92.3

   

140.7

   

86.8

Canada

 

6.4

   

8.8

   

7.0

   

8.6

Trinidad

 

1.7

   

3.3

   

1.9

   

3.9

Other International (B)

 

0.1

   

0.1

   

0.1

   

0.1

Total

 

158.7

   

104.5

   

149.7

   

99.4

                       

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

                     

United States

$

95.80

 

$

99.50

 

$

98.61

 

$

94.05

Canada

 

82.78

   

102.65

   

86.33

   

93.65

Trinidad

 

88.68

   

99.49

   

94.76

   

92.33

Other International (B)

 

91.20

   

101.52

   

96.49

   

93.67

Composite

 

95.20

   

99.77

   

98.00

   

93.95

                       

Natural Gas Liquids Volumes (MBbld) (A)

                     

United States

 

54.6

   

38.4

   

52.4

   

36.5

Canada

 

0.9

   

0.7

   

0.9

   

0.8

Total

 

55.5

   

39.1

   

53.3

   

37.3

                       

Average Natural Gas Liquids Prices ($/Bbl) ©

                     

United States

$

33.54

 

$

51.50

 

$

38.12

 

$

49.21

Canada

 

42.89

   

60.39

   

46.54

   

52.77

Composite

 

33.72

   

51.65

   

38.27

   

49.29

                       

Natural Gas Volumes (MMcfd) (A)

                     

United States

 

1,070

   

1,114

   

1,067

   

1,124

Canada

 

96

   

139

   

100

   

141

Trinidad

 

422

   

349

   

396

   

367

Other International (B)

 

10

   

13

   

10

   

13

Total

 

1,598

   

1,615

   

1,573

   

1,645

                       

Average Natural Gas Prices ($/Mcf) ©

                     

United States

$

2.09

 

$

4.24

 

$

2.28

 

$

4.17

Canada

 

2.21

   

4.16

   

2.33

   

3.91

Trinidad

 

3.42

   

3.51

   

3.21

   

3.35

Other International (B)

 

5.64

   

5.61

   

5.72

   

5.62

Composite

 

2.47

   

4.08

   

2.54

   

3.98

                       

Crude Oil Equivalent Volumes (MBoed) (D)

                     

United States

 

383.3

   

316.4

   

370.9

   

310.7

Canada

 

23.4

   

32.6

   

24.6

   

32.9

Trinidad

 

72.0

   

61.4

   

67.9

   

65.0

Other International (B)

 

1.8

   

2.2

   

1.8

   

2.3

Total

 

480.5

   

412.6

   

465.2

   

410.9

                       

Total MMBoe (D)

 

43.7

   

37.5

   

84.7

   

74.4

                       

(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,

 

2012

 

2011

           

ASSETS

Current Assets

         

Cash and Cash Equivalents

$

280,374

 

$

615,726

Accounts Receivable, Net

 

1,375,092

   

1,451,227

Inventories

 

620,260

   

590,594

Assets from Price Risk Management Activities

 

421,135

   

450,730

Income Taxes Receivable

 

28,448

   

26,609

Other

 

222,749

   

119,052

Total

 

2,948,058

   

3,253,938

           

Property, Plant and Equipment

         

Oil and Gas Properties (Successful Efforts Method)

 

35,562,446

   

33,664,435

Other Property, Plant and Equipment

 

2,375,862

   

2,149,989

Total Property, Plant and Equipment

 

37,938,308

   

35,814,424

Less: Accumulated Depreciation, Depletion and Amortization

 

(15,248,594)

   

(14,525,600)

Total Property, Plant and Equipment, Net

 

22,689,714

   

21,288,824

Other Assets

 

360,805

   

296,035

Total Assets

$

25,998,577

 

$

24,838,797

           

LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities

         

Accounts Payable

$

2,235,637

 

$

2,033,615

Accrued Taxes Payable

 

142,223

   

147,105

Dividends Payable

 

45,441

   

42,578

Deferred Income Taxes

 

121,059

   

135,989

Other

 

135,580

   

163,032

Total

 

2,679,940

   

2,522,319

           
           

Long-Term Debt

 

5,011,893

   

5,009,166

Other Liabilities

 

791,297

   

799,189

Deferred Income Taxes

 

4,160,306

   

3,867,219

Commitments and Contingencies

         
           

Stockholders' Equity

         

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

         

270,226,599 Shares Issued at June 30, 2012 and

         

269,323,084 Shares Issued at December 31, 2011

 

202,702

   

202,693

Additional Paid in Capital

 

2,374,122

   

2,272,052

Accumulated Other Comprehensive Income

 

400,086

   

401,746

Retained Earnings

 

10,417,405

   

9,789,345

Common Stock Held in Treasury, 419,651 Shares at June 30, 2012

         

and 303,633 Shares at December 31, 2011

 

(39,174)

   

(24,932)

Total Stockholders' Equity

 

13,355,141

   

12,640,904

Total Liabilities and Stockholders' Equity

$

25,998,577

 

$

24,838,797

           
 
 
 

EOG RESOURCES, INC.

SUMMARY STATEMENTS OF CASH FLOWS

(Unaudited; in thousands)

           
 

Six Months Ended

 

June 30,

 

2012

 

2011

Cash Flows from Operating Activities

         

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

         

Net Income

$

719,787

 

$

429,547

Items Not Requiring (Providing) Cash

         

Depreciation, Depletion and Amortization

 

1,557,508

   

1,171,170

Impairments

 

187,364

   

447,982

Stock-Based Compensation Expenses

 

55,466

   

53,427

Deferred Income Taxes

 

278,826

   

206,130

Gains on Asset Dispositions, Net

 

(180,758)

   

(235,513)

Other, Net

 

(3,404)

   

(834)

Dry Hole Costs

 

11,081

   

24,627

Mark-to-Market Commodity Derivative Contracts

         

Total Gains

 

(322,657)

   

(122,875)

Realized Gains

 

306,780

   

31,285

Excess Tax Benefits from Stock-Based Compensation

 

(22,115)

   

-

Other, Net

 

9,890

   

13,268

Changes in Components of Working Capital and Other Assets and Liabilities

         

Accounts Receivable

 

115,419

   

(165,300)

Inventories

 

(103,576)

   

(127,062)

Accounts Payable

 

176,355

   

189,250

Accrued Taxes Payable

 

14,363

   

94,311

Other Assets

 

(102,303)

   

(4,796)

Other Liabilities

 

(27,355)

   

(12,017)

Changes in Components of Working Capital Associated with Investing and

         

Financing Activities

 

(97,453)

   

76,640

Net Cash Provided by Operating Activities

 

2,573,218

   

2,069,240

           

Investing Cash Flows

         

Additions to Oil and Gas Properties

 

(3,748,278)

   

(3,122,567)

Additions to Other Property, Plant and Equipment

 

(315,542)

   

(340,140)

Proceeds from Sales of Assets

 

1,111,517

   

944,481

Changes in Components of Working Capital Associated with Investing

         

Activities

 

97,746

   

(76,852)

Net Cash Used in Investing Activities

 

(2,854,557)

   

(2,595,078)

           

Financing Cash Flows

         

Common Stock Sold

 

-

   

1,388,270

Dividends Paid

 

(88,892)

   

(81,562)

Excess Tax Benefits from Stock-Based Compensation

 

22,115

   

-

Treasury Stock Purchased

 

(22,663)

   

(16,736)

Proceeds from Stock Options Exercised and Employee Stock Purchase Plan

 

32,986

   

24,619

Other, Net

 

(293)

   

212

Net Cash (Used in) Provided by Financing Activities

 

(56,747)

   

1,314,803

           

Effect of Exchange Rate Changes on Cash

 

2,734

   

(380)

           

(Decrease) Increase in Cash and Cash Equivalents

 

(335,352)

   

788,585

Cash and Cash Equivalents at Beginning of Period

 

615,726

   

788,853

Cash and Cash Equivalents at End of Period

$

280,374

 

$

1,577,438

           
   
   
   

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, 2012 and 2011 reported Net Income (GAAP) to reflect actual net cash realized from financial commodity price transactions by eliminating the unrealized mark-to-market gains from these transactions, to add back impairment charges related to certain of EOG's North American assets in 2012 and 2011 and to eliminate the net gains on asset dispositions primarily in North America in 2012 and 2011. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for comparative purposes within the industry.

 
                         
                     
 

Three Months Ended

 

Six Months Ended

 
 

June 30,

 

June 30,

 
 

2012

 

2011

 

2012

 

2011

 
                         

Reported Net Income (GAAP)

$

395,778

 

$

295,574

 

$

719,787

 

$

429,547

 
                         

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

                       

Total Gains

 

(188,449)

   

(189,621)

   

(322,657)

   

(122,875)

 

Realized Gains

 

173,179

   

6,348

   

306,780

   

31,285

 

Subtotal

 

(15,270)

   

(183,273)

   

(15,877)

   

(91,590)

 
                         

After-Tax MTM Impact

 

(9,776)

   

(117,281)

   

(10,165)

   

(58,641)

 
                         

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

 

1,526

   

226,177

   

38,575

   

256,460

 

Less: Net Gains on Asset Dispositions, Net of Tax

 

(75,087)

   

(105,224)

   

(118,298)

   

(151,110)

 
                         

Adjusted Net Income (Non-GAAP)

$

312,441

 

$

299,246

 

$

629,899

 

$

476,256

 
                         

Net Income Per Share (GAAP)

                       

Basic

$

1.48

 

$

1.11

 

$

2.70

 

$

1.65

 

Diluted

$

1.47

 

$

1.10

 

$

2.67

(a)

$

1.63

(b)

                         

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

             

64%

       
                         

Adjusted Net Income Per Share (Non-GAAP)

                       

Basic

$

1.17

 

$

1.13

 

$

2.36

 

$

1.83

 

Diluted

$

1.16

 

$

1.11

 

$

2.33

 

$

1.81

 
                         

Average Number of Common Shares

                       

Basic

 

266,874

   

265,830

   

266,718

   

259,766

 

Diluted

 

269,985

   

269,332

   

270,083

   

263,363

 
                         
   
   
   

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, 2012 and 2011 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG management uses this information for comparative purposes within the industry.

 
                         
 

Three Months Ended

 

Six Months Ended

 
 

June 30,

 

June 30,

 
 

2012

 

2011

 

2012

 

2011

 
                         

Net Cash Provided by Operating Activities (GAAP)

$

1,495,613

 

$

1,111,752

 

$

2,573,218

 

$

2,069,240

 
                         

Adjustments

                       

Exploration Costs (excluding Stock-Based Compensation Expenses)

 

41,890

   

35,775

   

78,078

   

80,542

 

Excess Tax Benefits from Stock-Based Compensation

 

5,464

   

-

   

22,115

   

-

 

Changes in Components of Working Capital and Other Assets and Liabilities

                     

Accounts Receivable

 

(205,367)

   

51,445

   

(115,419)

   

165,300

 

Inventories

 

113,784

   

59,329

   

103,576

   

127,062

 

Accounts Payable

 

60,270

   

(23,753)

   

(176,355)

   

(189,250)

 

Accrued Taxes Payable

 

(19,526)

   

(14,563)

   

(14,363)

   

(94,311)

 

Other Assets

 

(6,537)

   

(13,860)

   

102,303

   

4,796

 

Other Liabilities

 

22,296

   

20,638

   

27,355

   

12,017

 

Changes in Components of Working Capital Associated

                       

with Investing and Financing Activities

 

(126,222)

   

(74,655)

   

97,453

   

(76,640)

 
                         

Discretionary Cash Flow (Non-GAAP)

$

1,381,665

 

$

1,152,108

 

$

2,697,961

(a)

$

2,098,756

(b)

                         

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

             

29%

       
                         
   
   
   

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, 2012 and 2011 reported Income Before Interest Expense and Income Taxes (GAAP) to Earnings Before Interest Expense, Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash realized from financial commodity derivative transactions by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the net gains on asset dispositions primarily in North America in 2012 and 2011. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Income Before Interest Expense and Income Taxes (GAAP) to add back Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for comparative purposes within the industry.

 
                           
 

Three Months Ended

   

Six Months Ended

 
 

June 30,

   

June 30,

 
 

2012

 

2011

   

2012

 

2011

 
                           

Income Before Interest Expense and Income Taxes (GAAP)

$

697,014

 

$

594,477

   

$

1,267,417

 

$

870,532

 
                           

Adjustments:

                         

Depreciation, Depletion and Amortization

 

808,765

   

602,944

     

1,557,508

   

1,171,170

 

Exploration Costs

 

48,149

   

41,238

     

90,956

   

92,147

 

Dry Hole Costs

 

11,081

   

1,676

     

11,081

   

24,627

 

Impairments

 

54,217

   

358,654

     

187,364

   

447,982

 

EBITDAX (Non-GAAP)

 

1,619,226

   

1,598,989

     

3,114,326

   

2,606,458

 

Total (Gains) Losses on MTM Commodity Derivative Contracts

(188,449)

   

(189,621)

     

(322,657)

   

(122,875)

 

Realized Gains on MTM Commodity Derivative Contracts

 

173,179

   

6,348

     

306,780

   

31,285

 

Net Gains on Asset Dispositions

 

(113,290)

   

(163,771)

     

(180,758)

   

(235,513)

 

Adjusted EBITDAX (Non-GAAP)

$

1,490,666

 

$

1,251,945

   

$

2,917,691

(a)

$

2,279,355

(b)

                           

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

               

28%

       
                           
       
       
       
   

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 2, 2012, with notional volumes expressed in Bbld and MMBtud and prices expressed in $/Bbl and $/MMBtu. EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method.

                     
   

CRUDE OIL DERIVATIVE CONTRACTS

 
                     
                 

Weighted

 
       

Volume

 

Average Price

 
             

(Bbld)

 

($/Bbl)

 
   

2012(1)

             
   

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

34,000

 

$104.95

 
   

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

 

52,000

 

105.80

 
   

July 2012 (closed)

   

50,000

 

106.90

 
   

August 2012

     

50,000

 

106.90

 
   

September 1, 2012 through December 31, 2012

32,000

 

106.61

 
                     
   

2013(2)

             
   

January 1, 2013 through June 30, 2013

 

16,000

 

$98.12

 
                     
                     

(1)

EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for an additional six-month period. Options covering a notional volume of 18,000 Bbld are exercisable on August 31, 2012. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 18,000 Bbld at an average price of $107.42 per barrel for the period September 1, 2012 through February 28, 2013. Options covering a notional volume of 15,000 Bbld are exercisable on December 31, 2012. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 15,000 Bbld at an average price of $110.03 per barrel for the period January 1, 2013 through June 30, 2013.

(2)

EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for an additional six-month period. Options covering a notional volume of 16,000 Bbld are exercisable on June 28, 2013. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 16,000 Bbld at an average price of $98.12 per barrel for the period July 1, 2013 through December 31, 2013.

                     
   

NATURAL GAS DERIVATIVE CONTRACTS

 
                     
                 

Weighted

 
       

Volume

 

Average Price

 
             

(MMBtud)

 

($/MMBtu)

 
   

2012(3)

             
   

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

525,000

 

$5.44

 
   

September 1, 2012 through December 31, 2012

525,000

 

$5.44

 
                     
   

2013(4)

             
   

January 1, 2013 through December 31, 2013

 

150,000

 

$4.79

 
                     
   

2014(5)

             
                     
                     

(3)

EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates. Such options are exercisable monthly up until the settlement date of each monthly contract. If the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 425,000 MMBtud at an average price of $5.44 per MMBtu for the period from September 1, 2012 through December 31, 2012.

(4)

EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates. Such options are exercisable monthly up until the settlement date of each monthly contract. If the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 150,000 MMBtud at an average price of $4.79 per MMBtu for each month of 2013.

(5)

EOG settled natural gas financial price swap contracts for the period January 1, 2014 through December 31, 2014. In connection with these contracts, the counterparties retain an option of entering into derivative contracts at future dates. Such options are exercisable monthly up until the settlement date of each monthly contract. If the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 150,000 MMbtud at an average price of $4.79 per MMBtu for each month of 2014.

   
   

Definitions

             
     

Bbld

Barrels per day.

     

$/Bbl

Dollars per barrel.

     

MMBtud

Million British thermal units per day.

     

$/MMBtu

Dollars per million British thermal units.

                     
 
 
 

EOG RESOURCES, INC.

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

(Unaudited; in millions, except ratio data)

         

The following chart reconciles 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.

         
     

June 30,

 
     

2012

 
         
 

Total Stockholders' Equity - (a)

$

13,355

 
         
 

Long-Term Debt - (b)

 

5,012

 
 

Less: Cash

 

(280)

 
 

Net Debt (Non-GAAP) - (c)

 

4,732

 
         
 

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

$

18,367

 
         
 

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

$

18,087

 
         
 

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

 

27%

 
         
 

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

 

26%

 
         
 
 

EOG RESOURCES, INC.

THIRD QUARTER AND FULL YEAR 2012 FORECAST AND BENCHMARK COMMODITY PRICING

 

(a) Third Quarter and Full Year 2012 Forecast

 

The forecast items for the third quarter and full year 2012 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast.

 

(b) Benchmark Commodity Pricing

 

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

 

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

 
 

ESTIMATED RANGES

 

(Unaudited)

   

3Q 2012

   

Full Year 2012

Daily Production

                     

Crude Oil and Condensate Volumes (MBbld)

                     

United States

 

148.0

-

 

160.0

   

142.0

-

 

152.0

Canada

 

5.0

-

 

6.0

   

6.3

-

 

7.3

Trinidad

 

0.8

-

 

2.0

   

1.2

-

 

1.6

Other International

 

0.0

-

 

0.2

   

0.1

-

 

0.2

Total

 

153.8

-

 

168.2

   

149.6

-

 

161.1

                       

Natural Gas Liquids Volumes (MBbld)

                     

United States

 

52.0

-

 

58.0

   

51.0

-

 

58.3

Canada

 

0.6

-

 

1.0

   

0.7

-

 

0.9

Total

 

52.6

-

 

59.0

   

51.7

-

 

59.2

                       

Natural Gas Volumes (MMcfd)

                     

United States

 

1,000

-

 

1,025

   

1,021

-

 

1,041

Canada

 

80

-

 

100

   

89

-

 

99

Trinidad

 

333

-

 

362

   

358

-

 

373

Other International

 

8

-

 

10

   

10

-

 

11

Total

 

1,421

-

 

1,497

   

1,478

-

 

1,524

                       

Crude Oil Equivalent Volumes (MBoed)

                     

United States

 

366.7

-

 

388.8

   

363.2

-

 

383.8

Canada

 

18.9

-

 

23.7

   

21.8

-

 

24.7

Trinidad

 

56.3

-

 

62.3

   

60.9

-

 

63.8

Other International

 

1.3

-

 

1.8

   

1.8

-

 

2.0

Total

 

443.2

-

 

476.6

   

447.7

-

 

474.3

                       

Operating Costs

                     

Unit Costs ($/Boe)

                     

Lease and Well

$

6.65

-

$

6.85

 

$

6.36

-

$

6.54

Transportation Costs

$

3.60

-

$

3.75

 

$

3.30

-

$

3.48

Depreciation, Depletion and Amortization

$

19.35

-

$

20.00

 

$

18.84

-

$

19.44

                       

Expenses ($MM)

                     

Exploration, Dry Hole and Impairment

$

122.0

-

$

142.0

 

$

476.2

-

$

516.2

General and Administrative

$

102.0

-

$

107.0

 

$

339.0

-

$

348.8

Gathering and Processing

$

23.2

-

$

27.2

 

$

93.6

-

$

101.6

Capitalized Interest

$

10.8

-

$

14.8

 

$

46.4

-

$

54.4

Net Interest

$

47.0

-

$

53.0

 

$

195.3

-

$

205.9

                       

Taxes Other Than Income (% of Wellhead Revenue)

 

5.8%

-

 

6.4%

   

5.9%

-

 

6.3%

                       

Income Taxes

                     

Effective Rate

 

35%

-

 

45%

   

35%

-

 

45%

Current Taxes ($MM)

$

75

-

$

90

 

$

320

-

$

340

                       

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

                     

Exploration and Development, Excluding Facilities

           

$

6,200

-

$

6,300

Exploration and Development Facilities

           

$

630

-

$

675

Gathering, Processing and Other

           

$

570

-

$

600

                       

Pricing - (Refer toBenchmark Commodity Pricingin text)

                     

Crude Oil and Condensate ($/Bbl)

                     

Differentials

                     

United States - (above) below WTI

$

(2.00)

-

$

(4.00)

 

$

(1.29)

-

$

(2.37)

Canada - (above) below WTI

$

6.50

-

$

8.00

 

$

9.41

-

$

10.17

Trinidad - (above) below WTI

$

8.75

-

$

10.25

 

$

3.00

-

$

4.00

                       

Natural Gas Liquids

                     

Realizations as % of WTI

                     

United States

 

34%

-

 

40%

   

36%

-

 

39%

Canada

 

50%

-

 

54%

   

49%

-

 

51%

                       

Natural Gas ($/Mcf)

                     

Differentials