Crude Oil ( ) Brent Crude ( ) Natural Gas ( ) S&P 500 ( ) PHLX Oil ( )
  • Increases 2014 Full-Year Crude Oil and Condensate Production Growth Goal to 31 Percent from 29 Percent
  • Raises 2014 Total Production Growth Target to 16.5 Percent from 14 Percent
  • Reports 29 Percent Increase in U.S. Crude Oil and Condensate Production and 17 Percent Growth in Total Company Production Year-Over-Year
  • Confirms Prolific, Highly Over-Pressured Crude Oil Window on Delaware Basin Wolfcamp Acreage
  • Realizes Strong Drilling Results from Eagle Ford, Emerging Delaware Basin and Rockies Crude Oil Plays

EOG Resources, Inc. (EOG) (EOG) today reported third quarter 2014 net income of $1,103.6 million, or $2.01 per share. This compares to third quarter 2013 net income of $462.5 million, or $0.85 per share.

Adjusted non-GAAP net income for the third quarter 2014 was $720.6 million, or $1.31 per share, and adjusted non-GAAP net income for the same prior year period was $634.3 million, or $1.16 per share.

Consistent with some analysts’ practice of matching realizations to settlement months and making certain other adjustments in order to exclude one-time items, adjusted non-GAAP net income for the third quarter 2014 excluded a previously disclosed non-cash net gain of $469.1 million ($301.0 million after-tax, or $0.55 per share) on the mark-to-market of financial commodity derivative contracts. The net cash outflow related to settlements of financial commodity derivative contracts was $68.0 million ($43.6 million after-tax, or $0.08 per share). During the third quarter 2014, the net gains on asset dispositions were $60.3 million ($38.4 million net of tax, or $0.07 per share). (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)

Reflecting the ongoing shift in its asset portfolio, crude oil now accounts for 48 percent of EOG’s total production, compared to 42 percent at the end of the third quarter 2013. This highly desirable ratio drove EOG’s strong financial metrics for the first nine months of 2014. Discretionary cash flow increased 18 percent and adjusted EBITDAX advanced 19 percent, versus the first nine months of 2013. In addition, adjusted non-GAAP earnings per share increased 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), adjusted non-GAAP EBITDAX to income before interest expense and income taxes (GAAP) and adjusted non-GAAP net income to GAAP net income.)

Operational Highlights
EOG is increasing its full year 2014 crude oil and condensate production growth target to 31 percent from 29 percent and total production growth target to 16.5 percent from 14 percent, as it continues to improve well productivity in its key domestic crude oil plays.

In the third quarter, EOG’s U.S. crude oil and condensate production increased 29 percent, compared to the same prior year period. Production gains from the South Texas Eagle Ford, North Dakota Bakken and Delaware Basin led EOG’s crude oil production growth. Driven by the Delaware Basin and Eagle Ford, total natural gas liquids (NGLs) production increased 25 percent, and total company natural gas production increased 3 percent, compared to the third quarter 2013. Total company production increased 17 percent.

Delaware Basin
In the Delaware Basin, EOG has confirmed that 90,000 of its 140,000 net acre position in the Wolfcamp is in a highly over-pressured crude oil window, representing a significant enhancement in the play’s reinvestment rate-of-return. EOG drilled two Wolfcamp wells that have a 50 percent crude oil mix.  In Lea County, New Mexico, the Diamond SM 36 State #1H began production at 1,340 barrels of oil per day (Bopd) with 195 barrels per day (Bpd) of NGLs and 1.3 million cubic feet per day (MMcfd) of natural gas. On the Texas side of the play in Loving County, the Voyager 15 #3H had a high initial production rate of 1,890 Bopd with 385 Bpd of NGLs and 2.5 MMcfd of natural gas. EOG has 100 and 48 percent working interest, respectively, in these two wells. EOG plans to increase its Delaware Basin Wolfcamp drilling activity on the 50 percent crude oil acreage.

Near the Texas/New Mexico border in Loving County, Texas, EOG completed its third well in the Second Bone Spring Sand this year. The State Magellan #2H, in which EOG has 100 percent working interest, began initial production at 1,825 Bopd with 295 Bpd of NGLs and 2.2 MMcfd of natural gas. Drilled 20 miles southwest of EOG’s existing production, the well confirms the prospectivity of the Second Bone Spring Sand over a greater amount of acreage. These results, together with recent mapping and geological studies, indicate EOG has at least 90,000 net acres of Second Bone Spring Sand potential across its acreage.

Also in Loving County, Texas, EOG has been drilling Leonard Shale wells. The State Pathfinder #1H and #3H, which were completed in the Leonard ‘A’ zone as 450-foot spacing tests, had a combined rate of 2,340 Bopd with 470 Bpd of NGLs and 2.6 MMcfd of natural gas. EOG has 100 percent working interest in these wells. EOG is continuing to test various spacing patterns between and across producing zones in the Leonard Shale where it holds an expanded 80,000 net acre position.

South Texas Eagle Ford
Through drilling and completion improvements, EOG again realized outstanding capital efficiencies and strong well results in its single largest growth engine, the Eagle Ford. In Gonzales County, the Neuse Unit #1H was turned to sales at an initial peak rate of 4,170 Bopd with 160 Bpd of NGLs and 935 thousand cubic feet per day (Mcfd) of natural gas. The Boothe Unit #12H, #13H, #14H and #15H came online at rates ranging from 2,640 to 3,445 Bopd with 490 to 580 Bpd of NGLs and 2.8 to 3.4 MMcfd of natural gas. EOG has 100 percent working interest in these five Eagle Ford wells.

In Karnes County, the Colleen Unit #1H had an initial production rate of 3,660 Bopd with 360 Bpd of NGLs and 2.1 MMcfd of natural gas. The Maverick Unit #2H came online at an initial rate of 3,680 Bopd with 365 Bpd of NGLs and 2.1 MMcfd of natural gas. The Lake Unit #4H, #6H and #8H began production from two different pads at a combined rate of 6,460 Bopd with 735 Bpd of NGLs and 4.3 MMcfd of natural gas. EOG has 100 percent working interest in these five Eagle Ford wells.

West of Gonzales and Karnes, in LaSalle and McMullen counties, among the wells turned to sales, 31 had initial production rates exceeding 1,200 Bopd including the Corner S Ranch  #11H, #12H, #13H, #14H, #15H and #16H. The wells, in which EOG has 100 percent working interest, had a combined rate exceeding 8,400 Bopd, 325 Bpd of NGLs and 1.9 MMcfd of natural gas.

North Dakota Bakken
EOG’s Bakken drilling activity for the year has concentrated on its Parshall Core and Antelope Extension acreage. In the Core, EOG continues to test various spacing patterns to determine a development program that maximizes the field’s resource potential. While preliminary results from 700-foot spaced wells are encouraging, EOG will continue to analyze production data. EOG is simultaneously testing well patterns of less than 700 feet. In the Antelope Extension area, EOG has pursued development drilling in the Bakken and tested various Three Forks intervals to determine the prospectivity of the formation across its acreage. Additionally, EOG has reduced its overall Bakken drilling costs by integrating self-sourced sand and identifying drilling efficiencies, as well as refining completion techniques in both areas.

In the Core area, the Parshall 44-1004H, 45-1004H and 46-1004H, in which EOG has 69 percent working interest, were turned to production at initial rates of 2,710, 2,005 and 2,105 Bopd with 875, 665 and 860 Mcfd of rich natural gas, respectively. The Parshall 47-2226H, 48-2226H and 49-2226H began production at a cumulative rate of 5,105 Bopd with 2.3 MMcfd of rich natural gas. EOG has 70 percent working interest in these three Core wells.

In the Antelope Extension area, EOG had successful drilling results from the first, second and third Three Forks benches. The first well drilled in the third interval of the Three Forks was the Mandaree 134-05H, in which EOG has 70 percent working interest. It came online at 1,410 Bopd with 2.2 MMcfd of rich natural gas. In the second interval, the Mandaree 135-05H, in which EOG has 69 percent working interest, had an initial rate of 1,620 Bopd with 2.5 MMcfd of rich natural gas. EOG has 42 percent working interest in the Mandaree 17-05H, which began producing at 1,745 Bopd with 2.8 MMcfd of rich natural gas from the first bench. EOG is continuing to test and drill Three Forks wells in all three intervals across its Antelope acreage.

“At EOG, we are never satisfied with the status quo. We are constantly identifying efficiencies in our drilling practices and making breakthroughs in completion methodology that raise the bar on EOG’s ongoing outstanding performance,” said Chairman and Chief Executive Officer William R. “Bill” Thomas.

Wyoming DJ and Powder River Basins
In the DJ Basin, EOG is simultaneously developing the stacked Codell and Niobrara formations from multi-well pad locations in Laramie County, Wyoming. During the third quarter, a seven-well pattern of three Codell and four Niobrara wells was brought to production with a combined initial rate exceeding 7,800 Bopd with 5.4 MMcfd of rich natural gas. The wells, in which EOG has 75 percent working interest, were drilled with 710-foot spacing between laterals averaging 9,400 feet. Initial production and drilling results from the Codell and Niobrara are encouraging.

In Campbell and Converse counties, Wyoming, EOG is actively developing its acreage in the Powder River Basin with a single drilling rig program. EOG completed one well from the Parkman formation and two from the Turner during the third quarter. The Mary’s Draw 412-1527H began sales at an initial rate of 1,190 Bopd with 270 Mcfd of rich natural gas from the Parkman formation. The Mary’s Draw 24-13H and 25-13H had a combined crude oil rate of 1,880 Bopd with 3.1 MMcfd of rich natural gas from the Turner. EOG has 100 percent working interest in these three wells.

“We have added a number of new plays to EOG’s portfolio this year, while continuing to improve well productivity in our existing assets. We expect the Eagle Ford, EOG’s cornerstone, to drive our production growth for many years,” Thomas said. “It’s important to note that despite the recent pullback in crude oil prices, because of our premier acreage positions and zealous approach to improving completion methods, EOG is positioned to realize ongoing excellent returns in our top plays and continue to be an industry leader in domestic organic production growth.”

Crude Oil and Natural Gas Hedging Activity
For the period November 1 through December 31, 2014, EOG has crude oil financial price swap contracts in place for 192,000 Bopd at a weighted average price of $96.15 per barrel. For the period January 1 through December 31, 2015, EOG has crude oil financial price swap contracts in place for an average of 28,350 Bopd at a weighted average price of $91.00 per barrel, excluding unexercised options.

For December 2014, EOG has natural gas financial price swap contracts in place for 330,000 million British thermal units per day (MMBtud) at a weighted average price of $4.55 per million British thermal units (MMBtu), excluding unexercised options.

For the period January 1 through December 31, 2015, EOG has natural gas financial price swap contracts in place for 175,000 MMBtud at a weighted average price of $4.51 per MMBtu, excluding unexercised options. (For a comprehensive summary of crude oil and natural gas derivative contracts, please refer to the attached tables.)

Cash Flow and Capital Structure
At September 30, 2014, EOG’s total debt outstanding was $5,910 million for a debt-to-total capitalization ratio of 25 percent. Taking into account cash on the balance sheet of $1.5 billion at September 30, 2014, EOG’s net debt was $4,429 million for a net debt-to-total capitalization ratio of 20 percent, down from 23 percent at December 31, 2013. (Please refer to the attached tables for the reconciliation of net debt (non-GAAP) to current and long-term debt (GAAP) and the reconciliation of net debt-to-total capitalization ratio (non-GAAP) to debt-to-total capitalization ratio (GAAP).)

“EOG is committed to enhancing long-term shareholder value. We have increased the dividend twice in 2014 because our excellent financial and operational performance drives outstanding returns quarter after quarter,” Thomas said.

Conference Call November 5, 2014
EOG’s third quarter 2014 results conference call will be available via live audio webcast at 7 a.m. Central time (8 a.m. Eastern time) on Wednesday, November 5, 2014. To listen, log on towww.eogresources.com. The webcast will be archived on EOG’s website through November 19, 2014.

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 is successful in its efforts to economically develop its acreage in, produce reserves and achieve anticipated production levels from, and optimize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects;
  • 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, appropriate gathering, processing, compression, transportation and refining 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, health and safety laws and regulations relating to air emissions, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;
  • 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, facilities, equipment, materials and services;
  • the availability and cost of employees and other personnel, facilities, equipment, materials (such as water) 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 (by EOG or third parties) of production, gathering, processing, refining, 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 17 through 26 of EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013 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, 2013, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn:Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC’s website at www.sec.gov.  In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.

For Further Information Contact:

Investors

Maire A. Baldwin

(713) 651-6364

Kimberly A. Matthews

(713) 571-4676

David J. Streit

(713) 571-4902

Media

K Leonard

(713) 571-3870

 

 

EOG RESOURCES, INC.

FINANCIAL REPORT

(Unaudited; in millions, except per share data)

Three Months Ended

Nine Months Ended

September 30,

September 30,

2014

2013

2014

2013

Net Operating Revenues

$

5,118.6

$

3,541.4

$

13,389.8

$

10,738.1

Net Income 

$

1,103.6

$

462.5

$

2,470.9

$

1,616.9

Net Income Per Share 

Basic

$

2.03

$

0.85

$

4.55

$

3.00

Diluted

$

2.01

$

0.85

$

4.51

$

2.96

Average Number of Common Shares

Basic

544.0

540.9

543.1

539.9

Diluted

549.5

547.2

548.4

545.7

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

Three Months Ended

Nine Months Ended

September 30,

September 30,

2014

2013

2014

2013

Net Operating Revenues

Crude Oil and Condensate

$

2,671,502

$

2,337,742

$

7,687,579

$

6,132,574

Natural Gas Liquids

258,927

208,190

753,135

556,176

Natural Gas

443,108

396,123

1,508,892

1,269,604

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

469,125

(293,387)

84,119

(206,853)

Gathering, Processing and Marketing

1,196,933

872,699

3,240,139

2,755,069

Gains on Asset Dispositions, Net

60,346

8,183

75,700

185,569

Other, Net

18,675

11,846

40,279

45,956

Total

5,118,616

3,541,396

13,389,843

10,738,095

Operating Expenses

Lease and Well

368,340

299,169

1,035,632

817,057

Transportation Costs

246,067

219,790

729,883

628,538

Gathering and Processing Costs

41,621

31,121

108,015

81,522

Exploration Costs

48,955

39,429

139,221

130,968

Dry Hole Costs

16,359

19,548

30,265

59,260

Impairments 

55,542

85,917

207,938

177,432

Marketing Costs

1,213,652

876,761

3,263,471

2,746,900

Depreciation, Depletion and Amortization

1,040,018

928,800

2,983,111

2,685,719

General and Administrative

96,931

98,654

270,725

257,246

Taxes Other Than Income

204,969

172,438

606,411

458,566

Total

3,332,454

2,771,627

9,374,672

8,043,208

Operating Income 

1,786,162

769,769

4,015,171

2,694,887

Other Income (Expense), Net

(21,338)

11,168

(16,726)

5,867

Income Before Interest Expense and Income Taxes

1,764,824

780,937

3,998,445

2,700,754

Interest Expense, Net

49,704

59,382

151,723

182,950

Income Before Income Taxes

1,715,120

721,555

3,846,722

2,517,804

Income Tax Provision

611,502

259,057

1,375,823

900,889

Net Income 

$

1,103,618

$

462,498

$

2,470,899

$

1,616,915

Dividends Declared per Common Share

$

0.1675

$

0.0938

$

0.4175

$

0.2813

Note: All share and per-share amounts shown have been restated to reflect the 2-for-1 stock split effective March 31, 2014.

 

 

EOG RESOURCES, INC.

OPERATING HIGHLIGHTS

(Unaudited)

Three Months Ended

Nine Months Ended

September 30,

September 30,

2014

2013

2014

2013

Wellhead Volumes and Prices

Crude Oil and Condensate Volumes (MBbld) (A)

United States

293.2

227.6

275.5

204.3

Canada

5.3

6.1

6.0

6.7

Trinidad

0.9

1.2

1.0

1.3

Other International (B)

0.1

0.1

0.1

0.1

Total

299.5

235.0

282.6

212.4

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

United States

$

97.33

$

108.56

$

100.10

$

106.36

Canada

87.64

97.90

90.74

90.53

Trinidad

87.87

94.96

90.84

91.80

Other International (B)

94.31

81.30

90.68

88.90

Composite

97.13

108.20

99.87

105.76

Natural Gas Liquids Volumes (MBbld) (A)

United States

85.8

68.2

78.4

63.5

Canada

0.6

0.9

0.7

0.9

Total

86.4

69.1

79.1

64.4

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

United States

$

32.61

$

32.75

$

34.83

$

31.55

Canada

40.38

32.24

43.01

37.83

Composite

32.67

32.74

34.90

31.64

Natural Gas Volumes (MMcfd) (A)

United States

941

899

920

920

Canada

63

76

65

78

Trinidad

356

352

374

350

Other International (B)

9

7

9

8

Total

1,369

1,334

1,368

1,356

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

United States

$

3.48

$

3.19

$

4.17

$

3.33

Canada

4.05

2.61

4.49

3.01

Trinidad

3.50

3.41

3.61

3.71

Other International (B)

5.00

6.12

5.03

6.58

Composite

3.52

3.23

4.04

3.43

Crude Oil Equivalent Volumes (MBoed) (D)

United States 

536.1

445.7

507.3

421.2

Canada

16.4

19.7

17.5

20.7

Trinidad

60.1

59.8

63.4

59.5

Other International (B)

1.5

1.2

1.5

1.4

Total

614.1

526.4

589.7

502.8

Total MMBoe (D)

56.5

48.4

161.0

137.3

(A)

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

(B)

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

(C) 

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

(D)

Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas.  Crude oil equivalents are determined using the ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas.  MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.

 

 

EOG RESOURCES, INC.

SUMMARY BALANCE SHEETS

(Unaudited; in thousands, except share data)

September 30,

December 31,

2014

2013

ASSETS

Current Assets

Cash and Cash Equivalents

$

1,481,145

$

1,318,209

Accounts Receivable, Net

2,009,091

1,658,853

Inventories

672,899

563,268

Assets from Price Risk Management Activities

132,931

8,260

Income Taxes Receivable

17,978

4,797

Deferred Income Taxes

238,258

244,606

Other

332,414

274,022

Total

4,884,716

4,072,015

Property, Plant and Equipment

Oil and Gas Properties (Successful Efforts Method)

47,912,930

42,821,803

Other Property, Plant and Equipment

3,571,545

2,967,085

Total Property, Plant and Equipment

51,484,475

45,788,888

Less:  Accumulated Depreciation, Depletion and Amortization

(22,267,642)

(19,640,052)

Total Property, Plant and Equipment, Net

29,216,833

26,148,836

Other Assets

399,334

353,387

Total Assets

$

34,500,883

$

30,574,238

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities

Accounts Payable

$

2,775,342

$

2,254,418

Accrued Taxes Payable

257,948

159,365

Dividends Payable

91,094

50,795

Liabilities from Price Risk Management Activities

127,542

Deferred Income Taxes

2,444

Current Portion of Long-Term Debt

6,579

6,579

Other

245,339

263,017

Total

3,378,746

2,861,716

Long-Term Debt

5,903,232

5,906,642

Other Liabilities

1,084,461

865,067

Deferred Income Taxes

6,414,546

5,522,354

Commitments and Contingencies

Stockholders’ Equity

Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 548,601,616 Shares Issued at September 30, 2014 and 546,378,440 Shares Issued at December 31, 2013 

205,488

202,732

Additional Paid in Capital

2,785,716

2,646,879

Accumulated Other Comprehensive Income 

387,725

415,834

Retained Earnings

14,410,707

12,168,277

Common Stock Held in Treasury, 701,786 Shares at September 30, 2014 and 206,830 Shares at December 31, 2013 

(69,738)

(15,263)

Total Stockholders’ Equity

17,719,898

15,418,459

Total Liabilities and Stockholders’ Equity

$

34,500,883

$

30,574,238

Note: All share amounts shown have been restated to reflect the 2-for-1 stock split effective March 31, 2014.

 

 

EOG RESOURCES, INC.

SUMMARY STATEMENTS OF CASH FLOWS

(Unaudited; in thousands)

Nine Months Ended

September 30,

2014

2013

Cash Flows from Operating Activities

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

Net Income 

$

2,470,899

$

1,616,915

Items Not Requiring (Providing) Cash

Depreciation, Depletion and Amortization

2,983,111

2,685,719

Impairments 

207,938

177,432

Stock-Based Compensation Expenses

103,636

103,171

Deferred Income Taxes

974,522

657,686

Gains on Asset Dispositions, Net

(75,700)

(185,569)

Other, Net

17,188

460

Dry Hole Costs

30,265

59,260

Mark-to-Market Commodity Derivative Contracts

Total (Gains) Losses

(84,119)

206,853

Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts 

(188,937)

115,323

Excess Tax Benefits from Stock-Based Compensation

(87,827)

(50,230)

Other, Net

8,701

16,222

Changes in Components of Working Capital and Other Assets and Liabilities

Accounts Receivable

(341,043)

(213,746)

Inventories

(119,166)

61,147

Accounts Payable

566,753

145,199

Accrued Taxes Payable

176,412

73,197

Other Assets

(61,966)

(78,799)

Other Liabilities

66,618

10,889

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

(108,568)

(72,945)

Net Cash Provided by Operating Activities

6,538,717

5,328,184

Investing Cash Flows

Additions to Oil and Gas Properties

(5,653,035)

(5,084,335)

Additions to Other Property, Plant and Equipment

(587,178)

(271,136)

Proceeds from Sales of Assets

91,335

587,273

Changes in Restricted Cash

(91,238)

(68,061)

Changes in Components of Working Capital Associated with Investing Activities

108,999

72,916

Net Cash Used in Investing Activities

(6,131,117)

(4,763,343)

Financing Cash Flows

Long-Term Debt Borrowings

496,220

Long-Term Debt Repayments

(500,000)

Settlement of Foreign Currency Swap

(31,573)

Dividends Paid

(187,670)

(147,731)

Excess Tax Benefits from Stock-Based Compensation

87,827

50,230

Treasury Stock Purchased

(114,824)

(55,562)

Proceeds from Stock Options Exercised and Employee Stock Purchase Plan

11,740

30,080

Debt Issuance Costs

(895)

Repayment of Capital Lease Obligation

(4,457)

(4,318)

Other, Net

(431)

29

Net Cash Used in Financing Activities

(244,063)

(127,272)

Effect of Exchange Rate Changes on Cash

(601)

4,813

Increase in Cash and Cash Equivalents

162,936

442,382

Cash and Cash Equivalents at Beginning of Period

1,318,209

876,435

Cash and Cash Equivalents at End of Period

$

1,481,145

$

1,318,817

 

 

EOG RESOURCES, INC.

QUANTITATIVE RECONCILIATION OF ADJUSTED NET INCOME (NON-GAAP) 

TO NET INCOME (GAAP)

(Unaudited; in thousands, except per share data)

The following chart adjusts the three-month and nine-month periods ended September 30, 2014 and 2013 reported Net Income (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net gains on asset dispositions in North America in 2014 and 2013 and to add back impairment charges related to certain of EOG’s non-core North American assets in 2014 and 2013.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match realizations to production settlement months and make certain other adjustments to exclude non-recurring items.  EOG management uses this information for comparative purposes within the industry.

Three Months Ended 

Nine Months Ended

September 30,

September 30,

2014

2013

2014

2013

Reported Net Income (GAAP)

$

1,103,618

$

462,498

$

2,470,899

$

1,616,915

Commodity Derivative Contracts Impact

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

(469,125)

293,387

(84,119)

206,853

Net Cash Received from (Payments for) Settlements of Commodity

    Derivative Contracts

(68,037)

(20,636)

(188,937)

115,323

Subtotal

(537,162)

272,751

(273,056)

322,176

After-Tax Impact

(344,616)

174,628

(175,179)

206,273

Less: Net Gains on Asset Dispositions, Net of Tax

(38,386)

(5,241)

(47,426)

(129,616)

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

2,422

36,058

4,425

Adjusted Net Income (Non-GAAP)

$

720,616

$

634,307

$

2,284,352

$

1,697,997

Net Income Per Share (GAAP)

Basic

$

2.03

$

0.85

$

4.55

$

3.00

Diluted

$

2.01

$

0.85

$

4.51

$

2.96

Adjusted Net Income Per Share (Non-GAAP)

Basic

$

1.32

$

1.17

$

4.21

$

3.15

Diluted

$

1.31

$

1.16

$

4.17

$

3.11

Adjusted Net Income Per Diluted Share (Non-GAAP) –

   Percentage Increase

13%

34%

Average Number of Common Shares (GAAP)

Basic

543,984

540,941

543,086

539,869

Diluted

549,518

547,152

548,401

545,712

Note: All share and per-share amounts shown have been restated to reflect the 2-for-1 stock split effective March 31, 2014.

 

 

EOG RESOURCES, INC.

QUANTITATIVE RECONCILIATION OF DISCRETIONARY CASH FLOW (NON-GAAP)

TO NET CASH PROVIDED BY OPERATING ACTIVITIES (GAAP)

(Unaudited; in thousands)

The following chart reconciles the three-month and nine-month periods ended September 30, 2014 and 2013 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP).  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities.  EOG management uses this information for comparative purposes within the industry.

Three Months Ended

Nine Months Ended

September 30,

September 30,

2014

2013

2014

2013

Net Cash Provided by Operating Activities (GAAP)

$

2,336,469

$

2,012,472

$

6,538,717

$

5,328,184

Adjustments:

Exploration Costs (excluding Stock-Based Compensation Expenses) 

42,220

32,755

119,003

110,330

Excess Tax Benefits from Stock-Based Compensation

24,068

28,361

87,827

50,230

Changes in Components of Working Capital and Other Assets and Liabilities

Accounts Receivable

91,707

48,937

341,043

213,746

Inventories

9,410

(39,062)

119,166

(61,147)

Accounts Payable

(219,214)

(3,830)

(566,753)

(145,199)

Accrued Taxes Payable

(60,744)

(48,381)

(176,412)

(73,197)

Other Assets

(79,487)

(13,506)

61,966

78,799

Other Liabilities

(9,517)

(62,289)

(66,618)

(10,889)

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

76,924

53,306

108,568

72,945

Discretionary Cash Flow (Non-GAAP)

$

2,211,836

$

2,008,763

$

6,566,507

$

5,563,802

Discretionary Cash Flow (Non-GAAP) – Percentage Increase

10%

18%

 

 

EOG RESOURCES, INC.

QUANTITATIVE RECONCILIATION OF ADJUSTED EARNINGS BEFORE INTEREST EXPENSE, 

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

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

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

(Unaudited; in thousands)

The following chart adjusts the three-month and nine-month periods ended September 30, 2014 and 2013 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 received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the net gains on asset dispositions in North America in 2014 and 2013.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Income Before Interest Expense and Income Taxes (GAAP) to add back Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring items.  EOG management uses this information for comparative purposes within the industry.

Three Months Ended

Nine Months Ended

September 30,

September 30,

2014

2013

2014

2013

Income Before Interest Expense and Income Taxes (GAAP)

$

1,764,824

$

780,937

$

3,998,445

$

2,700,754

Adjustments:

Depreciation, Depletion and Amortization

1,040,018

928,800

2,983,111

2,685,719

Exploration Costs

48,955

39,429

139,221

130,968

Dry Hole Costs

16,359

19,548

30,265

59,260

Impairments 

55,542

85,917

207,938

177,432

EBITDAX (Non-GAAP)

2,925,698

1,854,631

7,358,980

5,754,133

Total (Gains) Losses on MTM Commodity Derivative Contracts 

(469,125)

293,387

(84,119)

206,853

Net Cash Received from (Payments for) Settlements of

Commodity Derivative Contracts

(68,037)

(20,636)

(188,937)

115,323

Gains on Asset Dispositions, Net

(60,346)

(8,183)

(75,700)

(185,569)

Adjusted EBITDAX (Non-GAAP)

$

2,328,190

$

2,119,199

$

7,010,224

$

5,890,740

Adjusted EBITDAX (Non-GAAP) – Percentage Increase

10%

19%

 

 

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

At

September 30,

December 31,

2014

2013

Total Stockholders’ Equity – (a)

$

17,720

$

15,418

Current and Long-Term Debt (GAAP) – (b)

5,910

5,913

Less: Cash 

(1,481)

(1,318)

Net Debt (Non-GAAP) – (c)

4,429

4,595

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

$

23,630

$

21,331

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

$

22,149

$

20,013

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

25%

28%

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

20%

23%

 

 

 

EOG RESOURCES, INC.

CRUDE OIL AND NATURAL GAS FINANCIAL

COMMODITY DERIVATIVE CONTRACTS

Presented below is a comprehensive summary of EOG’s crude oil and natural gas derivative contracts at November 4, 2014, 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) 

2014

January 2014 (closed)

156,000

$            96.30

February 2014 (closed)

171,000

96.35

March 1, 2014 through June 30, 2014 (closed)

181,000

96.55

July 1, 2014 through August 31, 2014 (closed)

202,000

96.34

September 1, 2014 through October 31, 2014 (closed)

192,000

96.15

November 1, 2014 through December 31, 2014

192,000

96.15

2015 (1)

January 1, 2015 through June 30, 2015

47,000

$            91.22

July 1, 2015 through December 31, 2015

10,000

89.98

(1)

EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional six-month periods. Options covering a notional volume of 69,000 Bbld are exercisable on or about December 31, 2014. If the counterparties exercise all such options, the notional volume of EOG’s existing crude oil derivative contracts will increase by 69,000 Bbld at an average price of $95.20 per barrel for each month during the period January 1, 2015 through June 30, 2015. Options covering a notional volume of 37,000 Bbld are exercisable on June 30, 2015. If the counterparties exercise all such options, the notional volume of EOG’s existing crude oil derivative contracts will increase by 37,000 Bbld at an average price of $91.56 per barrel for each month during the period July 1, 2015 through December 31, 2015.

NATURAL GAS DERIVATIVE CONTRACTS

Weighted

Volume

Average Price

(MMBtud) 

($/MMBtu) 

2014 (2)

January 2014 (closed)

230,000

$             4.51

February 2014 (closed)

710,000

4.57

March 2014 (closed)

810,000

4.60

April 2014 (closed)

465,000

4.52

May 2014 (closed)

685,000

4.55

June 2014 (closed)

515,000

4.52

July 2014 (closed)

340,000

4.55

August 1, 2014 through November 30, 2014 (closed)

330,000

4.55

December 2014

330,000

4.55

2015 (3)

January 1, 2015 through December 31, 2015

175,000

$             4.51

(2)

EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates. All such options are exercisable monthly up until the settlement date of each monthly contract. For December 2014, if the counterparties exercise all such options, the notional volume of EOG’s existing natural gas derivative contracts will increase by 480,000 MMBtud at an average price of $4.63 per MMBtu.

(3)

EOG has entered into natural gas derivative contracts which give counterparties the 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 175,000 MMBtud at an average price of $4.51 per MMBtu for each month during the period January 1, 2015 through December 31, 2015.

$/Bbl

Dollars per barrel

$/MMBtu

Dollars per million British thermal units

Bbld

Barrels per day

MMBtu

Million British thermal units

MMBtud

Million British thermal units per day

 

EOG RESOURCES, INC.

FOURTH QUARTER AND FULL YEAR 2014 FORECAST AND BENCHMARK COMMODITY PRICING

(a)  Fourth Quarter and Full Year 2014 Forecast

The forecast items for the fourth quarter and full year 2014 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release.  EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.  This forecast, which should be read in conjunction with the accompanying press release and EOG’s related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast.

(b)  Benchmark Commodity Pricing

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

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

ESTIMATED RANGES

(Unaudited)

4Q 2014

Full Year 2014

Daily Production

Crude Oil and Condensate Volumes (MBbld)

United States

293.0

300.0

279.9

281.6

Canada

6.5

7.5

6.2

6.4

Trinidad

0.5

0.7

0.8

1.0

Other International

0.0

0.0

0.0

0.1

Total

300.0

308.2

286.9

289.1

Natural Gas Liquids Volumes (MBbld)

United States

81.0

87.0

79.1

80.6

Canada

0.4

0.6

0.6

0.7

Total

81.4

87.6

79.7

81.3

Natural Gas Volumes (MMcfd)

United States

905

925

916

921

Canada

60

66

63

65

Trinidad

324

372

362

374

Other International

8

10

8

9

Total

1,297

1,373

1,349

1,369

Crude Oil Equivalent Volumes (MBoed)  

United States

524.8

541.2

511.7

515.8

Canada

16.9

19.1

17.4

17.9

Trinidad

54.5

62.7

61.1

63.3

Other International

1.3

1.7

1.4

1.6

Total

597.5

624.7

591.6

598.6

Operating Costs

Unit Costs ($/Boe)

Lease and Well

$

6.50

$

6.80

$

6.45

$

6.53

Transportation Costs

$

4.55

$

4.75

$

4.54

$

4.59

Depreciation, Depletion and Amortization

$

18.10

$

18.70

$

18.43

$

18.58

Expenses ($MM)

Exploration, Dry Hole and Impairment

$

155

$

175

$

476

$

496

General and Administrative

$

102

$

112

$

373

$

383

Gathering and Processing 

$

34

$

40

$

142

$

148

Capitalized Interest

$

14

$

16

$

57

$

59

Net Interest

$

48

$

52

$

200

$

204

Taxes Other Than Income (% of Wellhead Revenue)

6.1%

6.5%

6.0%

6.4%

Income Taxes

Effective Rate 

32%

37%

34%

37%

Current Taxes ($MM)

$

115

$

130

$

515

$

535

Capital Expenditures ($MM) – FY 2014 (Excluding Acquisitions)

Exploration and Development, Excluding Facilities

$

6,450

$

6,550

Exploration and Development Facilities

$

880

$

920

Gathering, Processing and Other

$

770

$

810

Pricing – (Refer to Benchmark Commodity Pricing in text)

Crude Oil and Condensate ($/Bbl)

Differentials

United States – (above) below WTI

$

0.50

$

1.50

$

(0.09)

$

0.25

Canada – (above) below WTI

$

9.50

$

10.50

$

9.21

$

9.90

Trinidad – (above) below WTI

$

9.75

$

10.75

$

7.97

$

8.75

Natural Gas Liquids

Realizations as % of WTI

United States

30%

35%

33%

35%

Canada

32%

38%

40%

43%

Natural Gas ($/Mcf)

Differentials

United States – (above) below NYMEX Henry Hub

$

0.30

$

0.70

$

0.32

$

0.43

Canada – (above) below NYMEX Henry Hub

$

0.00

$

0.30

$

0.00

$

0.09

Realizations

Trinidad

$

3.10

$

3.50

$

3.50

$

3.58

Other International

$

4.45

$

5.45

$

4.87

$

5.12

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