10-Q 1 a2014093010-q.htm 10-Q 2014.09.30 10-Q


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 
FORM 10-Q
 

(Mark One)

ý            QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2014
or
o            TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number: 1-9743
 
EOG RESOURCES, INC.
(Exact name of registrant as specified in its charter)
Delaware
 
47-0684736
(State or other jurisdiction
 of incorporation or organization)
 
(I.R.S. Employer
Identification No.)

1111 Bagby, Sky Lobby 2, Houston, Texas 77002
(Address of principal executive offices)       (Zip Code)

713-651-7000
(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes ý  No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  
Yes ý  No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer ý    Accelerated filer o    Non-accelerated filer o   Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  
Yes o  No ý

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.
Title of each class
 
Number of shares
Common Stock, par value $0.01 per share
 
548,009,414 (as of October 27, 2014)




EOG RESOURCES, INC.

TABLE OF CONTENTS



PART I.
FINANCIAL INFORMATION
Page No.
 
 
 
 
ITEM 1.
Financial Statements (Unaudited)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
ITEM 2.
 
 
 
 
 
ITEM 3.
 
 
 
 
 
ITEM 4.
 
 
 
 
PART II.
OTHER INFORMATION
 
 
 
 
 
 
ITEM 1.
 
 
 
 
 
ITEM 2.
 
 
 
 
 
ITEM 4.
 
 
 
 
 
ITEM 6.
 
 
 
 
 
 
 
 
 
 

-2-



PART I.  FINANCIAL INFORMATION
ITEM 1.  FINANCIAL STATEMENTS
EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(In Thousands, Except Per Share Data)
(Unaudited)
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 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

Net Income Per Share
 

 
 

 
 

 
 

Basic
$
2.03

 
$
0.85

 
$
4.55

 
$
3.00

Diluted
$
2.01

 
$
0.85

 
$
4.51

 
$
2.96

Dividends Declared per Common Share
$
0.1675

 
$
0.0938

 
$
0.4175

 
$
0.2813

Average Number of Common Shares
 

 
 

 
 

 
 

Basic
543,984

 
540,941

 
543,086

 
539,869

Diluted
549,518

 
547,152

 
548,401

 
545,712

Comprehensive Income
 

 
 

 
 

 
 

Net Income
$
1,103,618

 
$
462,498

 
$
2,470,899

 
$
1,616,915

Other Comprehensive Income (Loss)
 

 
 

 
 

 
 

Foreign Currency Translation Adjustments
(38,886
)
 
15,106

 
(27,438
)
 
(18,472
)
Foreign Currency Swap Transaction

 
1,459

 
50

 
2,498

Income Tax Related to Foreign Currency Swap Transaction

 

 
(670
)
 

Interest Rate Swap Transaction

 
678

 
777

 
1,999

Income Tax Related to Interest Rate Swap Transaction

 
(244
)
 
(281
)
 
(719
)
Other
23

 
27

 
(547
)
 
82

Other Comprehensive Income (Loss)
(38,863
)
 
17,026

 
(28,109
)
 
(14,612
)
Comprehensive Income
$
1,064,755

 
$
479,524

 
$
2,442,790

 
$
1,602,303

The accompanying notes are an integral part of these consolidated financial statements.

-3-



EOG RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share Data)
(Unaudited)
 
September 30,
2014
 
December 31,
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 (Note 8)


 


 
 
 
 
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


The accompanying notes are an integral part of these consolidated financial statements.

-4-


EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)
 
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

The accompanying notes are an integral part of these consolidated financial statements.

-5-



EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1.    Summary of Significant Accounting Policies

General. The consolidated financial statements of EOG Resources, Inc., together with its subsidiaries (collectively, EOG), included herein have been prepared by management without audit pursuant to the rules and regulations of the United States Securities and Exchange Commission (SEC). Accordingly, they reflect all normal recurring adjustments which are, in the opinion of management, necessary for a fair presentation of the financial results for the interim periods presented. Certain information and notes normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP) have been condensed or omitted pursuant to such rules and regulations. However, management believes that the disclosures included either on the face of the financial statements or in these notes are sufficient to make the interim information presented not misleading. These consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in EOG's Annual Report on Form 10-K for the year ended December 31, 2013, filed on February 24, 2014 (EOG's 2013 Annual Report).

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The operating results for the three and nine months ended September 30, 2014, are not necessarily indicative of the results to be expected for the full year.

On February 24, 2014, EOG's Board of Directors (Board) approved a two-for-one stock split in the form of a stock dividend, payable to stockholders of record as of March 17, 2014, and paid on March 31, 2014. All share and per share amounts in the financial statements and these notes have been restated to reflect the two-for-one stock split.

Recently Issued Accounting Standards. In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-09 "Revenue From Contracts With Customers" (ASU 2014-09), which will require entities to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will supersede most current guidance related to revenue recognition when it becomes effective. The new standard also will require expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. ASU 2014-09 will be effective for interim and annual reporting periods beginning after December 15, 2016. Early application is not permitted. EOG is analyzing the requirements of ASU 2014-09 to determine what impact the new standard will have on its consolidated financial statements and related disclosures.

-6-

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

2.    Stock-Based Compensation

As more fully discussed in Note 6 to the Consolidated Financial Statements included in EOG's 2013 Annual Report, EOG maintains various stock-based compensation plans. Stock-based compensation expense is included on the Consolidated Statements of Income and Comprehensive Income based upon the job function of the employees receiving the grants as follows (in millions):
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2014
 
2013
 
2014
 
2013
Lease and Well
$
9.7

 
$
7.2

 
$
30.4

 
$
25.4

Gathering and Processing Costs
0.4

 
0.3

 
0.9

 
0.9

Exploration Costs
6.7

 
6.7

 
20.2

 
20.6

General and Administrative
21.7

 
31.3

 
52.1

 
56.3

Total
$
38.5

 
$
45.5

 
$
103.6

 
$
103.2


The Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (2008 Plan) provides for grants of stock options, stock-settled stock appreciation rights (SARs), restricted stock, restricted stock units, performance units, performance stock and other stock-based awards. At September 30, 2014, approximately 28.8 million common shares remained available for grant under the 2008 Plan. EOG's policy is to issue shares related to the 2008 Plan from either previously authorized unissued shares or treasury shares to the extent treasury shares are available.

Stock Options and Stock-Settled Stock Appreciation Rights and Employee Stock Purchase Plan. The fair value of stock option and SAR grants is estimated using the Hull-White II binomial option pricing model. The fair value of Employee Stock Purchase Plan (ESPP) grants is estimated using the Black-Scholes-Merton model. Stock-based compensation expense related to stock option, SAR and ESPP grants totaled $21.2 million and $19.2 million during the three months ended September 30, 2014 and 2013, respectively, and $44.9 million and $40.0 million during the nine months ended September 30, 2014 and 2013, respectively.

Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants during the nine-month periods ended September 30, 2014 and 2013 are as follows:
 
Stock Options/SARs
 
ESPP
 
Nine Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2014
 
2013
 
2014
 
2013
Weighted Average Fair Value of Grants
$
30.77

 
$
27.34

 
$
21.27

 
$
15.07

Expected Volatility
35.25
%
 
35.86
%
 
25.12
%
 
29.89
%
Risk-Free Interest Rate
0.95
%
 
0.78
%
 
0.08
%
 
0.11
%
Dividend Yield
0.6
%
 
0.4
%
 
0.5
%
 
0.6
%
Expected Life
5.2 years

 
5.5 years

 
0.5 years

 
0.5 years


Expected volatility is based on an equal weighting of historical volatility and implied volatility from traded options in EOG's common stock. The risk-free interest rate is based upon United States Treasury yields in effect at the time of grant. The expected life is based upon historical experience and contractual terms of stock option, SAR and ESPP grants.


-7-

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

The following table sets forth stock option and SAR transactions for the nine-month periods ended September 30, 2014 and 2013 (stock options and SARs in thousands):
 
Nine Months Ended 
 September 30, 2014
 
Nine Months Ended 
 September 30, 2013
 
Number of
Stock
Options/SARs
 
Weighted
Average
Grant
Price
 
Number of
Stock
Options/SARs
 
Weighted
Average
Grant
Price
Outstanding at January 1
10,452

 
$
54.43

 
12,438

 
$
42.91

Granted
2,122

 
101.65

 
2,234

 
83.66

Exercised (1)
(1,351
)
 
44.52

 
(3,648
)
 
34.52

Forfeited
(226
)
 
62.95

 
(168
)
 
48.38

Outstanding at September 30 (2)
10,997

 
$
64.58

 
10,856

 
$
54.03

Vested or Expected to Vest (3)
10,568

 
$
63.92

 
10,398

 
$
53.63

Exercisable at September 30 (4)
5,573

 
$
49.23

 
4,982

 
$
44.03


(1)
The total intrinsic value of stock options/SARs exercised for the nine months ended September 30, 2014 and 2013 was $78.0 million and $134.2 million, respectively. The intrinsic value is based upon the difference between the market price of EOG's common stock on the date of exercise and the grant price of the stock options/SARs.
(2)
The total intrinsic value of stock options/SARs outstanding at September 30, 2014 and 2013 was $384.9 million and $332.3 million, respectively. At September 30, 2014 and 2013, the weighted average remaining contractual life was 4.6 years and 4.8 years, respectively.
(3)
The total intrinsic value of stock options/SARs vested or expected to vest at September 30, 2014 and 2013 was $376.6 million and $322.5 million, respectively. At September 30, 2014 and 2013, the weighted average remaining contractual life was 4.5 years and 4.7 years, respectively.
(4)
The total intrinsic value of stock options/SARs exercisable at September 30, 2014 and 2013 was $277.5 million and $202.4 million, respectively. At September 30, 2014 and 2013, the weighted average remaining contractual life was 3.3 years and 3.5 years, respectively.

At September 30, 2014, unrecognized compensation expense related to non-vested stock option, SAR and ESPP grants totaled $127.5 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.9 years.

Restricted Stock and Restricted Stock Units. Employees may be granted restricted (non-vested) stock and/or restricted stock units without cost to them. Stock-based compensation expense related to restricted stock and restricted stock units totaled $13.9 million and $19.2 million for the three months ended September 30, 2014 and 2013, respectively, and $53.4 million and $55.5 million for the nine months ended September 30, 2014 and 2013, respectively.


-8-

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

The following table sets forth restricted stock and restricted stock unit transactions for the nine-month periods ended September 30, 2014 and 2013 (shares and units in thousands):
 
Nine Months Ended September 30, 2014
 
Nine Months Ended September 30, 2013
 
Number of
Shares and
Units
 
Weighted
Average
Grant Date
Fair Value
 
Number of
Shares and
Units
 
Weighted
Average
Grant Date
Fair Value
Outstanding at January 1
7,358

 
$
49.54

 
7,636

 
$
45.53

Granted
1,024

 
99.00

 
1,284

 
75.93

Released (1)
(2,540
)
 
37.92

 
(1,234
)
 
52.89

Forfeited
(220
)
 
59.36

 
(160
)
 
47.70

Outstanding at September 30 (2)
5,622

 
$
63.41

 
7,526

 
$
49.47

 
(1)
The total intrinsic value of restricted stock and restricted stock units released for the nine months ended September 30, 2014 and 2013 was $270.0 million and $89.2 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date restricted stock and restricted stock units are released.
(2)
The total intrinsic value of restricted stock and restricted stock units outstanding at September 30, 2014 and 2013 was $556.7 million and $637.0 million, respectively.

At September 30, 2014, unrecognized compensation expense related to restricted stock and restricted stock units totaled $192.5 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.6 years.

Performance Units and Performance Stock. EOG grants performance units and/or performance stock to its executive officers. The fair value of the performance units and performance stock is estimated using a Monte Carlo simulation. Stock-based compensation expense related to performance unit and performance stock grants totaled $3.4 million and $7.1 million for the three months ended September 30, 2014 and 2013, respectively, and $5.3 million and $7.7 million for the nine months ended September 30, 2014 and 2013, respectively.

Weighted average fair values and valuation assumptions used to value performance unit and performance stock grants during the nine-month periods ended September 30, 2014 and 2013 are as follows:

 
Nine Months Ended 
 September 30,
 
2014
 
2013
Weighted Average Fair Value of Grants
$
119.27

 
$
100.34

Expected Volatility
32.18
%
 
33.63
%
Risk-Free Interest Rate
1.18
%
 
0.79
%

Expected volatility is based on the term-matched historical volatility over the simulated term, which is calculated as the time between the grant date and the end of the performance period. The risk-free interest rate is based on a 3.26 year zero-coupon risk-free interest rate derived from the Treasury Constant Maturities yield curve on the grant date.


-9-

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

The following table sets forth performance unit and performance stock transactions for the nine-month periods ended September 30, 2014 and 2013 (shares and units in thousands):

 
Nine Months Ended 
 September 30, 2014
 
Nine Months Ended 
 September 30, 2013
 
Number of
Shares and
Units
 
Weighted
Average
Grant Date
Fair Value
 
Number of
Shares and
Units
 
Weighted
Average
Grant Date
Fair Value
Outstanding at January 1
261

 
$
82.18

 
142

 
$
67.05

Granted
72

 
119.27

 
119

 
100.34

Released

 

 

 

Forfeited

 

 

 

Outstanding at September 30 (1)
333

 
$
90.17

 
261

 
$
82.18

 
(1)
The total intrinsic value of performance units and performance stock outstanding at September 30, 2014 and 2013 was $33.0 million and $22.1 million, respectively.

At September 30, 2014, unrecognized compensation expense related to performance units and performance stock totaled $9.4 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 1.9 years.

3.    Net Income Per Share

The following table sets forth the computation of Net Income Per Share for the three-month and nine-month periods ended September 30, 2014 and 2013 (in thousands, except per share data):
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2014
 
2013
 
2014
 
2013
Numerator for Basic and Diluted Earnings Per Share -
 
 
 
 
 
 
 
Net Income
$
1,103,618

 
$
462,498

 
$
2,470,899

 
$
1,616,915

Denominator for Basic Earnings Per Share -
 

 
 

 
 

 
 

Weighted Average Shares
543,984

 
540,941

 
543,086

 
539,869

Potential Dilutive Common Shares -
 

 
 

 
 

 
 

Stock Options/SARs
2,760

 
2,378

 
2,644

 
2,196

Restricted Stock/Units and Performance Units/Stock
2,774

 
3,833

 
2,671

 
3,647

Denominator for Diluted Earnings Per Share -
 

 
 

 
 

 
 

Adjusted Diluted Weighted Average Shares
549,518

 
547,152

 
548,401

 
545,712

Net Income Per Share
 

 
 

 
 

 
 

Basic
$
2.03

 
$
0.85

 
$
4.55

 
$
3.00

Diluted
$
2.01

 
$
0.85

 
$
4.51

 
$
2.96


The diluted earnings per share calculation excludes stock options and SARs that were anti-dilutive. Shares underlying the excluded stock options and SARs totaled 0.2 million and 0.5 million shares for the three months ended September 30, 2014 and 2013, respectively, and 0.2 million shares for each of the nine months ended September 30, 2014 and 2013.


-10-

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

4.    Supplemental Cash Flow Information

Net cash paid for interest and income taxes was as follows for the nine-month periods ended September 30, 2014 and 2013 (in thousands):
 
Nine Months Ended 
 September 30,
 
2014
 
2013
Interest (1)
$
143,615

 
$
172,808

Income Taxes, Net of Refunds Received
$
330,476

 
$
220,450

 
(1)
Net of capitalized interest of $43 million and $34 million for the nine months ended September 30, 2014 and 2013, respectively.

EOG's accrued capital expenditures at September 30, 2014 and 2013 were $960 million and $743 million, respectively.

5.    Segment Information

Selected financial information by reportable segment is presented below for the three-month and nine-month periods ended September 30, 2014 and 2013 (in thousands):
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2014
 
2013
 
2014
 
2013
Net Operating Revenues
 
 
 
 
 
 
 
United States
$
4,924,226

 
$
3,337,008

 
$
12,748,128

 
$
9,981,084

Canada
66,765

 
77,515

 
229,901

 
350,398

Trinidad
123,154

 
122,280

 
398,140

 
390,552

Other International (1)
4,471

 
4,593

 
13,674

 
16,061

Total
$
5,118,616

 
$
3,541,396

 
$
13,389,843

 
$
10,738,095

Operating Income (Loss)
 

 
 

 
 

 
 

United States
$
1,767,044

 
$
747,958

 
$
3,900,263

 
$
2,522,127

Canada
(17,869
)
 
(21,647
)
 
(43,711
)
 
29,683

Trinidad
61,328

 
61,087

 
209,785

 
213,875

Other International (1)
(24,341
)
 
(17,629
)
 
(51,166
)
 
(70,798
)
Total
1,786,162

 
769,769

 
4,015,171

 
2,694,887

Reconciling Items
 

 
 

 
 

 
 

Other Income (Expense), Net
(21,338
)
 
11,168

 
(16,726
)
 
5,867

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

 
(1)    Other International primarily includes EOG's United Kingdom, China and Argentina operations.


-11-

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

Total assets by reportable segment are presented below at September 30, 2014 and December 31, 2013 (in thousands):
 
At
September 30,
2014
 
At
December 31,
2013
Total Assets
 
 
 
United States
$
31,578,693

 
$
27,668,713

Canada
809,139

 
880,765

Trinidad
791,625

 
986,796

Other International (1)
1,321,426

 
1,037,964

Total
$
34,500,883

 
$
30,574,238

 
(1)    Other International primarily includes EOG's United Kingdom, China and Argentina operations.

6.    Asset Retirement Obligations

The following table presents the reconciliation of the beginning and ending aggregate carrying amounts of short-term and long-term legal obligations associated with the retirement of property, plant and equipment for the nine-month periods ended September 30, 2014 and 2013 (in thousands):
 
Nine Months Ended 
 September 30,
 
2014
 
2013
Carrying Amount at Beginning of Period
$
761,898

 
$
665,944

Liabilities Incurred
91,822

 
48,556

Liabilities Settled (1)
(44,805
)
 
(54,859
)
Accretion
33,833

 
26,421

Revisions
68,785

 
27,252

Foreign Currency Translations
(4,178
)
 
(5,898
)
Carrying Amount at End of Period
$
907,355

 
$
707,416

 
 
 
 
Current Portion
$
12,528

 
$
14,329

Noncurrent Portion
$
894,827

 
$
693,087

 
(1)
Includes settlements related to asset sales.

The current and noncurrent portions of EOG's asset retirement obligations are included in Current Liabilities - Other and Other Liabilities, respectively, on the Consolidated Balance Sheets.


-12-

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

7.    Exploratory Well Costs

EOG's net changes in capitalized exploratory well costs for the nine-month period ended September 30, 2014, are presented below (in thousands):
 
Nine Months Ended 
 September 30, 2014
 
 
Balance at December 31, 2013
$
9,211

Additions Pending the Determination of Proved Reserves
47,927

Reclassifications to Proved Properties
(15,285
)
Costs Charged to Expense
(4,011
)
Balance at September 30, 2014
$
37,842


At September 30, 2014, all capitalized exploratory well costs had been capitalized for periods of less than one year.

8.    Commitments and Contingencies

There are currently various suits and claims pending against EOG that have arisen in the ordinary course of EOG's business, including contract disputes, personal injury and property damage claims and title disputes. While the ultimate outcome and impact on EOG cannot be predicted, management believes that the resolution of these suits and claims will not, individually or in the aggregate, have a material adverse effect on EOG's consolidated financial position, results of operations or cash flow. EOG records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

9.    Pension and Postretirement Benefits

EOG has defined contribution pension plans in place for most of its employees in the United States, Canada, Trinidad and the United Kingdom, and defined benefit pension plans covering certain of its employees in Canada and Trinidad. For the nine months ended September 30, 2014 and 2013, EOG's total costs recognized for these pension plans were $29.6 million and $28.9 million, respectively. EOG also has postretirement medical and dental plans in place for eligible employees in the United States and Trinidad, the costs of which are not material.

10.    Long-Term Debt and Common Stock

Long-Term Debt. During the nine months ended September 30, 2014 and 2013, EOG utilized commercial paper and short-term borrowings under uncommitted credit facilities, bearing market interest rates, for various corporate financing purposes. EOG had no outstanding commercial paper borrowings or uncommitted credit facility borrowings at September 30, 2014. The average borrowings outstanding under the commercial paper program were $16 million and $23 million during the nine months ended September 30, 2014 and 2013, respectively. The average borrowings outstanding under the uncommitted credit facilities were $0.1 million and zero during the nine months ended September 30, 2014 and 2013, respectively. The weighted average interest rates for commercial paper borrowings during the nine months ended September 30, 2014 and 2013 were 0.25% and 0.30%, respectively, and 0.70% for uncommitted credit facility borrowings during the nine months ended September 30, 2014.

At September 30, 2014, $500 million aggregate principal amount of 2.95% Senior Notes due 2015 were classified as long-term debt based upon EOG's intent and ability to ultimately replace such amount with other long-term debt.

On March 21, 2014, EOG closed its sale of the $500 million aggregate principal amount of its 2.45% Senior Notes due 2020 (Notes). Interest on the Notes is payable semi-annually in arrears on April 1 and October 1 of each year, beginning October 1, 2014. Net proceeds from the Notes offering of approximately $496 million were used for general corporate purposes.

On March 17, 2014, EOG repaid upon maturity the $150 million aggregate principal amount of its 4.75% Subsidiary Debt due 2014 (Subsidiary Debt) and settled the foreign currency swap entered into contemporaneously with the issuance of the Subsidiary Debt for $32 million.


-13-

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

On February 3, 2014, EOG repaid upon maturity the $350 million aggregate principal amount of its Floating Rate Senior Notes due 2014 (Floating Rate Notes). On the same date, EOG settled the interest rate swap entered into contemporaneously with the issuance of the Floating Rate Notes for $0.8 million.

EOG currently has a $2.0 billion unsecured Revolving Credit Agreement (Agreement) with domestic and foreign lenders. The Agreement matures on October 11, 2016, and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods, subject to, among certain other terms and conditions, the consent of the banks holding greater than 50% of the commitments then outstanding under the Agreement. At September 30, 2014, there were no borrowings or letters of credit outstanding under the Agreement. Advances under the Agreement accrue interest based, at EOG's option, on either the London InterBank Offered Rate (LIBOR) plus an applicable margin (Eurodollar rate), or the base rate (as defined in the Agreement) plus an applicable margin. At September 30, 2014, the Eurodollar rate and applicable base rate, had there been any amounts borrowed under the Agreement, would have been 1.03% and 3.25%, respectively.

Restricted Cash. In order to comply with the Canadian Alberta Energy Regulator's requirements to post financial security for well abandonment obligations, EOG Resources Canada Inc. (EOGRC) established a 160 million Canadian dollar letter of credit facility (subsequently increased to 190 million Canadian dollars), which matures on May 29, 2018, with Royal Bank of Canada (RBC) as the lender. The letter of credit facility requires EOGRC to deposit cash, in an amount equal to all outstanding letters of credit under such facility, in a cash collateral account at RBC. At September 30, 2014, the balance in this account was 170 million Canadian dollars (152 million United States dollars).

Common Stock. On August 5, 2014, the Board increased the quarterly cash dividend on the common stock from the previous $0.125 per share to $0.1675 per share, effective beginning with the dividend to be paid on October 31, 2014, to stockholders of record as of October 17, 2014.

11.    Fair Value Measurements

As more fully discussed in Note 12 to the Consolidated Financial Statements included in EOG's 2013 Annual Report, certain of EOG's financial and nonfinancial assets and liabilities are reported at fair value on the Consolidated Balance Sheets. The following table provides fair value measurement information within the fair value hierarchy for certain of EOG's financial assets and liabilities carried at fair value on a recurring basis at September 30, 2014 and December 31, 2013 (in millions):
 
Fair Value Measurements Using:
 
Quoted
Prices in
Active
Markets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Total
At September 30, 2014
 
 
 
 
 
 
 
Financial Assets
 
 
 
 
 
 
 
Natural Gas Options/Swaptions
$

 
$
32

 
$

 
$
32

Crude Oil Swaps

 
84

 

 
84

Crude Oil Options/Swaptions

 
23

 

 
23

 
 
 
 
 
 
 
 
At December 31, 2013
 

 
 

 
 

 
 

Financial Assets
 

 
 

 
 

 
 

Natural Gas Options/Swaptions
$

 
$
8

 
$

 
$
8

 
 
 
 
 
 
 
 
Financial Liabilities
 

 
 

 
 

 
 

Crude Oil Swaps
$

 
$
17

 
$

 
$
17

Crude Oil Options/Swaptions

 
110

 

 
110

Foreign Currency Rate Swap

 
40

 

 
40

Interest Rate Swap

 
1

 

 
1



-14-

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

The estimated fair value of crude oil and natural gas derivative contracts (including options/swaptions) and the interest rate swap contract was based upon forward commodity price and interest rate curves based on quoted market prices. The estimated fair value of the foreign currency rate swap was based upon forward currency rates. Commodity derivative contracts were valued by utilizing an independent third-party derivative valuation provider who uses various types of valuation models, as applicable.

The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs and reserve lives. A reconciliation of EOG's asset retirement obligations is presented in Note 6.

Proved oil and gas properties and other assets with a carrying amount of $152 million were written down to their fair value of $68 million, resulting in pretax impairment charges of $84 million for the nine months ended September 30, 2014. Included in the $84 million pretax impairment charges are $58 million of impairments of proved oil and gas properties and other assets for which EOG utilized an accepted offer from a third-party purchaser as the basis for determining fair value. Significant Level 3 inputs associated with the calculation of discounted cash flows used in the impairment analysis include EOG's estimate of future crude oil and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data.

Fair Value of Debt. At both September 30, 2014 and December 31, 2013, EOG had outstanding $5,890 million aggregate principal amount of debt, which had estimated fair values of approximately $6,243 million and $6,222 million, respectively. The estimated fair value of debt was based upon quoted market prices and, where such prices were not available, other observable (Level 2) inputs regarding interest rates available to EOG at the end of each respective period.

12.    Risk Management Activities

Commodity Price Risk. As more fully discussed in Note 11 to the Consolidated Financial Statements included in EOG's 2013 Annual Report, EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in commodity prices for crude oil and natural gas. EOG utilizes financial commodity derivative instruments, primarily price swap, option, swaption, collar and basis swap contracts, as a means to manage this price risk. EOG has not designated any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounts for financial commodity derivative contracts using the mark-to-market accounting method. In addition to financial transactions, from time to time, EOG is a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and have varying pricing provisions. These physical commodity contracts qualify for the normal purchases and normal sales exception and, therefore, are not subject to hedge accounting or mark-to-market accounting. The financial impact of physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices.


-15-

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

Commodity Derivative Contracts. Presented below is a comprehensive summary of EOG's crude oil derivative contracts at September 30, 2014, with notional volumes expressed in barrels per day (Bbld) and prices expressed in dollars per barrel ($/Bbl).
Crude Oil Derivative Contracts
 
Volume
(Bbld)
 
Weighted Average Price
($/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 2014 (closed)
192,000

 
96.15

October 1, 2014 through December 31, 2014
192,000

 
96.15

 
 
 
 
2015 (1)
 
 
 
January 1, 2015 through June 30, 2015
20,000

 
$
91.41

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 10,000 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 10,000 Bbld at an average price of $92.85 per barrel for each month during the period July 1, 2015 through December 31, 2015.


-16-

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

Presented below is a comprehensive summary of EOG's natural gas derivative contracts at September 30, 2014, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).
Natural Gas Derivative Contracts
 
Volume (MMBtud)
 
Weighted Average Price
($/MMBtu)
2014 (1)
 
 
 
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 October 31, 2014 (closed)
330,000

 
4.55

November 1, 2014 through December 31, 2014
330,000

 
4.55

 
 
 
 
2015 (2)
 

 
 

January 1, 2015 through December 31, 2015
175,000

 
$
4.51

 
(1)
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 480,000 MMBtud at an average price of $4.63 per MMBtu for each month during the period November 1, 2014 through December 31, 2014.
(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. 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.

Foreign Currency Exchange Rate Derivative. EOG was party to a foreign currency aggregate swap with multiple banks to eliminate any exchange rate impacts that may have resulted from the Subsidiary Debt. The foreign currency swap expired and was settled contemporaneously with the repayment upon maturity of the Subsidiary Debt on March 17, 2014 (see Note 10).

Interest Rate Derivative. EOG was party to an interest rate swap with a counterparty bank. The interest rate swap was entered into in order to mitigate EOG's exposure to volatility in interest rates related to its Floating Rate Notes. The interest rate swap expired and was settled contemporaneously with the repayment upon maturity of the Floating Rate Notes on February 3, 2014 (see Note 10).

-17-

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)


The following table sets forth the amounts and classification of EOG's outstanding derivative financial instruments at September 30, 2014 and December 31, 2013. Certain amounts may be presented on a net basis on the consolidated financial statements when such amounts are with the same counterparty and subject to a master netting arrangement (in millions):
 
 
 
 
Fair Value at
Description
 
Location on Balance Sheet   
 
September 30,
2014
 
December 31,
2013
 
 
 
 
 
 
 
Asset Derivatives
 
 
 
 
 
 
Crude oil and natural gas derivative contracts -
 
 
 
 
 
 
Current portion
 
Assets from Price Risk Management Activities (1)
 
$
133

 
$
8

Noncurrent portion
 
Other Assets (2)
 
$
6

 
$

 
 
 
 
 

 
 

Liability Derivatives
 
 
 
 

 
 

Crude oil and natural gas derivative contracts -
 
 
 
 

 
 

Current portion
 
Liabilities from Price Risk Management
   Activities (3)
 
$

 
$
127

Noncurrent portion
 
Other Liabilities (4)
 
$

 
$

Foreign currency swap -
 
 
 
 

 
 

Current portion
 
Current Liabilities - Other
 
$

 
$
40

Interest rate swap -
 
 
 
 

 
 

Current portion
 
Current Liabilities - Other
 
$

 
$
1

 
(1)
The current portion of Assets from Price Risk Management Activities consists of gross assets of $147 million, partially offset by gross liabilities of $14 million at September 30, 2014, and gross assets of $18 million, partially offset by gross liabilities of $10 million at December 31, 2013.
(2)
The noncurrent portion of Assets from Price Risk Management Activities consists of gross assets of $10 million, partially offset by gross liabilities of $4 million at September 30, 2014.
(3)
The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $14 million, offset by gross assets of $14 million at September 30, 2014, and gross liabilities of $137 million, partially offset by gross assets of $10 million at December 31, 2013.
(4)
The noncurrent portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $4 million, offset by gross assets of $4 million at September 30, 2014.

Credit Risk. Notional contract amounts are used to express the magnitude of commodity price, foreign currency and interest rate swap agreements. The amounts potentially subject to credit risk, in the event of nonperformance by the counterparties, are equal to the fair value of such contracts (see Note 11). EOG evaluates its exposure to significant counterparties on an ongoing basis, including those arising from physical and financial transactions. In some instances, EOG renegotiates payment terms and/or requires collateral, parent guarantees or letters of credit to minimize credit risk.

All of EOG's outstanding derivative instruments are covered by International Swap Dealers Association Master Agreements (ISDAs) with counterparties. The ISDAs may contain provisions that require EOG, if it is the party in a net liability position, to post collateral when the amount of the net liability exceeds the threshold level specified for EOG's then-current credit ratings. In addition, the ISDAs may also provide that as a result of certain circumstances, including certain events that cause EOG's credit ratings to become materially weaker than its then-current ratings, the counterparty may require all outstanding derivatives under the ISDAs to be settled immediately. See Note 11 for the aggregate fair value of all derivative instruments that were in a net liability position at September 30, 2014 and December 31, 2013. EOG held collateral of $10 million and zero at September 30, 2014 and December 31, 2013, respectively, and had no collateral posted at September 30, 2014 and December 31, 2013.


-18-

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Concluded)
(Unaudited)


13.  Divestitures

During the first nine months of 2014, EOG received proceeds of approximately $91 million from sales of producing properties and acreage primarily in the Mid-Continent area, the Upper Gulf Coast region, Canada and the Rocky Mountain area. During the first nine months of 2013, EOG received proceeds of approximately $587 million primarily from sales of its entire interest in the planned Kitimat project, undeveloped acreage in the Horn River Basin in Canada and producing properties and acreage in the Upper Gulf Coast region, the Mid-Continent area and the Permian Basin.

-19-



PART I.  FINANCIAL INFORMATION

ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EOG RESOURCES, INC.

Overview
EOG Resources, Inc., together with its subsidiaries (collectively, EOG), 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, China and Argentina. EOG operates under a consistent business and operational strategy that focuses predominantly on maximizing the rate of return on investment of capital by emphasizing the drilling of internally generated prospects in order to find and develop low-cost reserves, controlling operating and capital costs and maximizing reserve recoveries. This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-effective basis, allowing EOG to deliver long-term production growth while maintaining a strong balance sheet. Maintaining the lowest possible operating cost structure that is consistent with prudent and safe operations is also an important goal in the implementation of EOG's strategy.

United States and Canada. EOG's efforts to identify plays with large reserve potential have proven to be successful. EOG continues to drill numerous wells in large acreage plays, which in the aggregate have contributed substantially to, and are expected to continue to contribute substantially to, EOG's crude oil and liquids-rich natural gas production. EOG has placed an emphasis on applying its horizontal drilling and completion expertise to unconventional crude oil and liquids-rich reservoirs. In 2014, EOG remains focused on developing its existing North American crude oil and liquids-rich acreage. In addition, increasing drilling and completion efficiencies and testing methods to improve the recovery factor of oil-in-place remain areas of emphasis in 2014. EOG also continues to evaluate certain potential crude oil and, to a lesser extent, liquids-rich exploration and development prospects. On a volumetric basis, as calculated using the ratio of 1.0 barrel of crude oil and condensate or natural gas liquids (NGL) to 6.0 thousand cubic feet of natural gas, crude oil and condensate and NGL production accounted for approximately 69% of total North American production during the first nine months of 2014 as compared to 62% for the same comparable period in 2013. This liquids growth primarily reflects increased production from the South Texas Eagle Ford, the North Dakota Bakken and the Permian Basin. Based on current trends, EOG expects its 2014 crude oil and condensate and NGL production to continue to increase both in total and as a percentage of total company production as compared to 2013. EOG's major producing areas in the United States and Canada are in New Mexico, North Dakota, Texas, Utah, Wyoming and western Canada.

EOG continues to deliver its crude oil to various markets in the United States, including sales points on the Gulf Coast where sales are based upon the premium Light Louisiana Sweet crude oil index. EOG's crude-by-rail facilities provide EOG the ability to direct its crude oil shipments via rail car to the most favorable markets, including the Gulf Coast; Cushing, Oklahoma; and other markets.

International. In Trinidad, EOG continues to deliver natural gas under existing supply contracts. Several fields in the South East Coast Consortium (SECC) Block, Modified U(a) Block, Block 4(a) and Modified U(b) Block and the EMZ Area have been developed and are producing natural gas sold to the National Gas Company of Trinidad and Tobago and crude oil and condensate sold to the Petroleum Company of Trinidad and Tobago. EOG expects to finish drilling three net development wells and to complete one net well in the SECC and Modified U(b) Blocks during the fourth quarter of 2014.

In the United Kingdom, EOG continues to make progress in the development of its 100% working interest East Irish Sea Conwy crude oil discovery. Modifications to the nearby third-party-owned Douglas platform, which will be used to process Conwy production, continued in the first nine months of 2014. First production from the Conwy field is anticipated in the second quarter of 2015.

EOG's activity in Argentina is focused on the Vaca Muerta oil shale formation in the Neuquén Basin in Neuquén Province. In 2014, EOG completed a vertical well in the Cerro Avispa Block that was drilled in late 2013 and determined the well to be a dry hole. In the third quarter of 2014, EOG drilled an exploratory well in the Bajo del Toro Block and expects to complete a previously drilled well in the fourth quarter of 2014. EOG continues to evaluate its drilling results and exploration program in Argentina.

In the Sichuan Basin, Sichuan Province, People's Republic of China, EOG completed two wells during the first nine months of 2014. EOG expects to commence a five-well drilling program in the fourth quarter of 2014 with two wells planned in 2014 and three wells planned in 2015.


-20-



EOG continues to evaluate other select crude oil and natural gas opportunities outside the United States and Canada primarily by pursuing exploitation opportunities in countries where indigenous crude oil and natural gas reserves have been identified.

Capital Structure. One of management's key strategies is to maintain a strong balance sheet with a consistently below average debt-to-total capitalization ratio as compared to those in EOG's peer group. EOG's debt-to-total capitalization ratio was 25% and 28% at September 30, 2014 and December 31, 2013, respectively. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity. At September 30, 2014, $500 million aggregate principal amount of 2.95% Senior Notes due 2015 were reclassified as long-term debt based upon EOG's intent and ability to ultimately replace such amount with other long-term debt.

On March 21, 2014, EOG closed its sale of the $500 million aggregate principal amount of its 2.45% Senior Notes due 2020 (Notes). Interest on the Notes is payable semi-annually in arrears on April 1 and October 1 of each year, beginning October 1, 2014. Net proceeds from the Notes offering of approximately $496 million were used for general corporate purposes.

On March 17, 2014, EOG repaid upon maturity the $150 million aggregate principal amount of its 4.75% Subsidiary Debt due 2014 (Subsidiary Debt) and settled the foreign currency swap entered into contemporaneously with the issuance of the Subsidiary Debt for $32 million.

On February 3, 2014, EOG repaid upon maturity the $350 million aggregate principal amount of its Floating Rate Senior Notes due 2014 (Floating Rate Notes). On the same date, EOG settled the interest rate swap entered into contemporaneously with the issuance of the Floating Rate Notes for $0.8 million.

EOG's total anticipated 2014 capital expenditures are estimated to range from $8.1 billion to $8.3 billion, excluding acquisitions. The majority of 2014 expenditures have been, and will continue to be, focused on United States crude oil and, to a lesser extent, liquids-rich drilling activity. EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program and other uncommitted credit facilities, bank borrowings, borrowings under its $2.0 billion senior unsecured revolving credit facility and equity and debt offerings.

When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer incremental exploration and/or production opportunities. Management continues to believe EOG has one of the strongest prospect inventories in EOG's history.



-21-



Results of Operations

The following review of operations for the three and nine months ended September 30, 2014 and 2013 should be read in conjunction with the consolidated financial statements of EOG and notes thereto included in this Quarterly Report on Form 10-­Q.

Three Months Ended September 30, 2014 vs. Three Months Ended September 30, 2013

Net Operating Revenues. During the third quarter of 2014, net operating revenues increased $1,578 million, or 45%, to $5,119 million from $3,541 million for the same period of 2013. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGL and natural gas, for the third quarter of 2014 increased $432 million, or 15%, to $3,374 million from $2,942 million for the same period of 2013. During the third quarter of 2014, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $469 million compared to net losses of $293 million for the same period of 2013. Gathering, processing and marketing revenues, which are revenues generated from sales of third-party crude oil and condensate, NGL and natural gas as well as fees associated with gathering third-party natural gas, for the third quarter of 2014 increased $324 million, or 37%, to $1,197 million from $873 million for the same period of 2013. Gains on asset dispositions, net, totaled $60 million and $8 million for the third quarters of 2014 and 2013, respectively.



-22-



Wellhead volume and price statistics for the three-month periods ended September 30, 2014 and 2013 were as follows:
 
Three Months Ended 
 September 30,
 
2014
 
2013
Crude Oil and Condensate Volumes (MBbld) (1)
 
 
 
United States
293.2

 
227.6

Canada
5.3

 
6.1

Trinidad
0.9

 
1.2

Other International (2)
0.1

 
0.1

Total
299.5

 
235.0

Average Crude Oil and Condensate Prices ($/Bbl) (3)
 

 
 

United States
$
97.33

 
$
108.56

Canada
87.64

 
97.90

Trinidad
87.87

 
94.96

Other International (2)
94.31

 
81.30

Composite
97.13

 
108.20

Natural Gas Liquids Volumes (MBbld) (1)
 
 
 

United States
85.8

 
68.2

Canada
0.6

 
0.9

Total
86.4

 
69.1

Average Natural Gas Liquids Prices ($/Bbl) (3)
 

 
 

United States
$
32.61

 
$
32.75

Canada
40.38

 
32.24

Composite
32.67

 
32.74

Natural Gas Volumes (MMcfd) (1)
 
 
 

United States
941

 
899

Canada
63

 
76

Trinidad
356

 
352

Other International (2)
9

 
7

Total
1,369

 
1,334

Average Natural Gas Prices ($/Mcf) (3)
 

 
 

United States
$
3.48

 
$
3.19

Canada
4.05

 
2.61

Trinidad
3.50

 
3.41

Other International (2)
5.00

 
6.12

Composite
3.52

 
3.23

Crude Oil Equivalent Volumes (MBoed) (4)
 
 
 

United States
536.1

 
445.7

Canada
16.4

 
19.7

Trinidad
60.1

 
59.8

Other International (2)
1.5

 
1.2

Total
614.1

 
526.4

 
 
 
 
Total MMBoe (4)
56.5

 
48.4

 
(1)
Thousand barrels per day or million cubic feet per day, as applicable.
(2)
Other International includes EOG's United Kingdom, China and Argentina operations.
(3)
Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 12 to the Consolidated Financial Statements).
(4)
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.



-23-




Wellhead crude oil and condensate revenues for the third quarter of 2014 increased $334 million, or 14%, to $2,672 million from $2,338 million for the same period of 2013 due to an increase of 65 MBbld, or 27%, in wellhead crude oil and condensate production ($638 million) primarily in the Eagle Ford, the North Dakota Bakken and the Permian Basin, partially offset by a lower composite wellhead crude oil and condensate price ($304 million). EOG's composite wellhead crude oil and condensate price for the third quarter of 2014 decreased 10% to $97.13 per barrel compared to $108.20 per barrel for the same period of 2013.

NGL revenues for the third quarter of 2014 increased $51 million, or 24%, to $259 million from $208 million for the same period of 2013 due to an increase of 17 MBbld, or 25%, in NGL deliveries. The increase in deliveries primarily reflects increased volumes in the Permian Basin and the Eagle Ford.

Wellhead natural gas revenues for the third quarter of 2014 increased $47 million, or 12%, to $443 million from $396 million for the same period of 2013. The increase was due to a higher composite wellhead natural gas price ($37 million) and an increase in natural gas deliveries ($10 million). Natural gas deliveries for the third quarter of 2014 increased 35 MMcfd, or 3%, compared to the same period of 2013 due primarily to increased production in the United States (42 MMcfd), partially offset by lower production in Canada (13 MMcfd). The increase in the United States is due primarily to increased production of associated natural gas. The decrease in Canada was primarily due to decreased production in Alberta and the Horn River Basin area. EOG's composite wellhead natural gas price for the third quarter of 2014 increased 9% to $3.52 per Mcf compared to $3.23 per Mcf for the same period of 2013.

During the third quarter of 2014, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $469 million compared to net losses of $293 million for the same period of 2013. Net cash payments for settlements of crude oil and natural gas financial derivative contracts were $68 million and $21 million during the third quarter of 2014 and 2013, respectively.

Gathering, processing and marketing revenues relate to the sale of third-party crude oil and natural gas. Purchases and sales of third-party crude oil and natural gas are utilized in order to balance firm transportation capacity with production in certain areas and to utilize excess capacity at EOG-owned facilities. Marketing costs represent the costs of purchasing third-party crude oil and natural gas and the associated transportation costs.

Gathering, processing and marketing revenues less marketing costs for the third quarter of 2014 declined $13 million as compared to the same period of 2013. The decline primarily reflects lower margins on crude oil marketing activities.

Operating and Other Expenses.  For the third quarter of 2014, operating expenses of $3,332 million were $560 million higher than the $2,772 million incurred during the third quarter of 2013.  The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended September 30, 2014 and 2013:
 
Three Months Ended 
 September 30,
 
2014
 
2013
Lease and Well
$
6.53

 
$
6.18

Transportation Costs
4.36

 
4.54

Depreciation, Depletion and Amortization (DD&A) -
 
 
 

Oil and Gas Properties
17.91

 
18.65

Other Property, Plant and Equipment
0.53

 
0.53

General and Administrative (G&A)
1.72

 
2.04

Interest Expense, Net
0.88

 
1.23

Total (1)
$
31.93

 
$
33.17

 
(1)
Total excludes gathering and processing costs, exploration costs, dry hole costs, impairments, marketing costs and taxes other than income.

The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A and interest expense, net, for the three months ended September 30, 2014, compared to the same period of 2013 are set forth below. See "Net Operating Revenues" above for a discussion of production volumes.


-24-



Lease and well expenses include expenses for EOG-operated properties, as well as expenses billed to EOG from other operators where EOG is not the operator of a property. Lease and well expenses can be divided into the following categories: costs to operate and maintain crude oil and natural gas wells, the cost of workovers and lease and well administrative expenses. Operating and maintenance costs include, among other things, pumping services, salt water disposal, equipment repair and maintenance, compression expense, lease upkeep and fuel and power. Workovers are operations to restore or maintain production from existing wells.
Each of these categories of costs individually fluctuates from time to time as EOG attempts to maintain and increase production while maintaining efficient, safe and environmentally responsible operations. EOG continues to increase its operating activities by drilling new wells in existing and new areas. Operating and maintenance costs within these existing and new areas, as well as the costs of services charged to EOG by vendors, fluctuate over time.
Lease and well expenses of $368 million for the third quarter of 2014 increased $69 million from $299 million for the same prior year period primarily due to increased operating and maintenance costs ($43 million), increased workover expenditures ($14 million) and increased lease and well administrative expenses ($12 million), all in the United States.
Transportation costs represent costs associated with the delivery of hydrocarbon products from the lease to a downstream point of sale. Transportation costs include transportation fees, costs associated with crude-by-rail operations, the cost of compression (the cost of compressing natural gas to meet pipeline pressure requirements), dehydration (the cost associated with removing water from natural gas to meet pipeline requirements), gathering fees and fuel costs.
Transportation costs of $246 million for the third quarter of 2014 increased $26 million from $220 million for the same prior year period primarily due to increased transportation costs related to production from the Eagle Ford.

DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method. EOG's DD&A rate and expense are the composite of numerous individual DD&A group calculations. There are several factors that can impact EOG's composite DD&A rate and expense, such as field production profiles, drilling or acquisition of new wells, disposition of existing wells and reserve revisions (upward or downward) primarily related to well performance, economic factors and impairments. Changes to these factors may cause EOG's composite DD&A rate and expense to fluctuate from period to period. DD&A of the cost of other property, plant and equipment is generally calculated using the straight-line depreciation method over the useful lives of the assets.

DD&A expenses for the third quarter of 2014 increased $111 million to $1,040 million from $929 million for the same prior year period. DD&A expenses associated with oil and gas properties for the third quarter of 2014 were $107 million higher than the same prior year period. The increase primarily reflects increased production in the United States ($162 million), partially offset by a decrease in unit rates in the United States ($45 million). Unit rates decreased primarily due to upward reserve revisions and reserves added at lower costs as a result of increased efficiencies.

Interest expense, net, of $50 million for the third quarter of 2014 decreased $10 million compared to the same prior year period primarily due to reduced debt outstanding and a lower composite interest rate ($7 million) and increased capitalized interest ($2 million).

Gathering and processing costs represent operating and maintenance expenses and administrative expenses associated with operating EOG's gathering and processing assets.

Gathering and processing costs increased $11 million to $42 million for the third quarter of 2014 compared to $31 million for the same prior year period. The increase primarily reflects increased activities in the Eagle Ford.

Exploration costs of $49 million for the third quarter of 2014 increased $10 million from $39 million for the same prior year period primarily due to increased geological and geophysical expenditures ($7 million) and increased exploration administrative expenses ($2 million) in the United States.

-25-



Impairments include amortization of unproved oil and gas property costs, as well as impairments of proved oil and gas properties; other property, plant and equipment; and other assets. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. When circumstances indicate that a proved property may be impaired, EOG compares expected undiscounted future cash flows at a DD&A group level to the unamortized capitalized cost of the asset. If the expected undiscounted future cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated by using the Income Approach described in the Fair Value Measurement Topic of the Financial Accounting Standards Board's Accounting Standards Codification. In certain instances, EOG utilizes accepted bids as the basis for determining fair value.

Impairments of $56 million for the third quarter of 2014 were $30 million lower than impairments for the same prior year period primarily due to lower impairments of other assets in the United States ($46 million), partially offset by increased amortization of unproved property costs in the United States ($15 million) and higher impairments of proved properties in Canada ($2 million). EOG recorded impairments of proved properties, other property, plant and equipment and other assets of $10 million and $55 million for the third quarter of 2014 and 2013, respectively.

Other income (expense), net, for the third quarter of 2014 decreased $33 million compared to the same prior year period. The decrease was primarily due to foreign currency exchange losses of $26 million in the third quarter of 2014 compared to foreign currency exchange gains of $20 million in the third quarter of 2013, partially offset by decreased deferred compensation expense ($8 million) and decreased losses on the disposition of warehouse stock ($6 million).

Taxes other than income include severance/production taxes, ad valorem/property taxes, payroll taxes, franchise taxes and other miscellaneous taxes. Severance/production taxes are generally determined based on wellhead revenues, and ad valorem/property taxes are generally determined based on the valuation of the underlying assets.

Taxes other than income for the third quarter of 2014 increased $33 million to $205 million (6.1% of wellhead revenues) compared to $172 million (5.9% of wellhead revenues) for the same prior year period. The increase in taxes other than income was primarily due to increases in the United States in severance/production taxes ($30 million) primarily as a result of increased wellhead revenues and higher ad valorem/property taxes ($10 million), partially offset by an increase in credits available to EOG in 2014 for Texas high-cost gas severance tax rate reductions ($5 million).

Income tax provision of $612 million for the third quarter of 2014 increased $353 million from $259 million for the third quarter of 2013 due primarily to higher pretax income. The net effective tax rate for the third quarter of 2014 of 36% was unchanged from the same prior year period.

Nine Months Ended September 30, 2014 vs. Nine Months Ended September 30, 2013

Net Operating Revenues. During the first nine months of 2014, net operating revenues increased $2,652 million, or 25%, to $13,390 million from $10,738 million for the same period of 2013. Total wellhead revenues for the first nine months of 2014 increased $1,992 million, or 25%, to $9,950 million from $7,958 million for the same period of 2013. During the first nine months of 2014, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $84 million compared to net losses of $207 million for the same period of 2013. Gathering, processing and marketing revenues for the first nine months of 2014 increased $485 million, or 18%, to $3,240 million from $2,755 million for the same period of 2013. Gains on asset dispositions, net, totaled $76 million and $186 million for the first nine months of 2014 and 2013, respectively.



-26-



Wellhead volume and price statistics for the nine-month periods ended September 30, 2014 and 2013 were as follows:
 
Nine Months Ended 
 September 30,
 
2014
 
2013
Crude Oil and Condensate Volumes (MBbld)
 
 
 
United States
275.5

 
204.3

Canada
6.0

 
6.7

Trinidad
1.0

 
1.3

Other International
0.1

 
0.1

Total
282.6

 
212.4

Average Crude Oil and Condensate Prices ($/Bbl) (1)
 

 
 

United States
$
100.10

 
$
106.36

Canada
90.74

 
90.53

Trinidad
90.84

 
91.80

Other International
90.68

 
88.90

Composite
99.87

 
105.76

Natural Gas Liquids Volumes (MBbld)
 
 
 

United States
78.4

 
63.5

Canada
0.7

 
0.9

Total
79.1

 
64.4

Average Natural Gas Liquids Prices ($/Bbl)
 

 
 

United States
$
34.83

 
$
31.55

Canada
43.01

 
37.83

Composite
34.90

 
31.64

Natural Gas Volumes (MMcfd)
 
 
 

United States
920

 
920

Canada
65

 
78

Trinidad
374

 
350

Other International
9

 
8

Total
1,368

 
1,356

Average Natural Gas Prices ($/Mcf) (1)
 

 
 

United States
$
4.17

 
$
3.33

Canada
4.49

 
3.01

Trinidad
3.61

 
3.71

Other International
5.03

 
6.58

Composite
4.04

 
3.43

Crude Oil Equivalent Volumes (MBoed)
 
 
 

United States
507.3

 
421.2

Canada
17.5

 
20.7

Trinidad
63.4

 
59.5

Other International
1.5

 
1.4

Total
589.7

 
502.8

 
 
 
 
Total MMBoe
161.0

 
137.3

 
(1)    Excludes the impact of financial commodity derivative instruments.


-27-



Wellhead crude oil and condensate revenues for the first nine months of 2014 increased $1,555 million, or 25%, to $7,688 million from $6,133 million for the same period of 2013 due to an increase of 70 MBbld, or 33%, in wellhead crude oil and condensate production ($2,009 million) primarily in the Eagle Ford, the North Dakota Bakken and the Permian Basin, partially offset by a lower composite wellhead crude oil and condensate price ($454 million). EOG's composite wellhead crude oil and condensate price for the first nine months of 2014 decreased 6% to $99.87 per barrel compared to $105.76 per barrel for the same period of 2013.

NGL revenues for the first nine months of 2014 increased $197 million, or 35%, to $753 million from $556 million for the same period of 2013 due to an increase of 15 MBbld, or 23%, in NGL deliveries ($127 million) and a higher composite price ($70 million). The increase in deliveries primarily reflects increased volumes in the Eagle Ford and the Permian Basin. EOG's composite NGL price for the first nine months of 2014 increased 10% to $34.90 per barrel compared to $31.64 per barrel for the same period of 2013.

Wellhead natural gas revenues for the first nine months of 2014 increased $239 million, or 19%, to $1,509 million from $1,270 million for the same period of 2013 primarily due to a higher composite wellhead natural gas price. Natural gas deliveries for the first nine months of 2014 increased 12 MMcfd, or 1%, compared to the same period of 2013 primarily due to increased contractual deliveries in Trinidad (24 MMcfd), partially offset by lower production in Canada (13 MMcfd) as a result of decreased production in Alberta and the Horn River Basin area. EOG's composite wellhead natural gas price for the first nine months of 2014 increased 18% to $4.04 per Mcf compared to $3.43 per Mcf for the same period of 2013.

During the first nine months of 2014, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $84 million compared to net losses of $207 million for the same period of 2013. During the first nine months of 2014, the net cash payments for settlements of crude oil and natural gas financial derivative contracts were $189 million compared to net cash received from settlements of crude oil and natural gas financial derivative contracts of $115 million for the same period of 2013.

Gathering, processing and marketing revenues less marketing costs for the first nine months of 2014 declined $32 million as compared to the same period of 2013 primarily due to lower margins on crude oil marketing activities.

Operating and Other Expenses. For the first nine months of 2014, operating expenses of $9,375 million were $1,332 million higher than the $8,043 million incurred during the same period of 2013. The following table presents the costs per Boe for the nine-month periods ended September 30, 2014 and 2013:
 
Nine Months Ended 
 September 30,
 
2014
 
2013
Lease and Well
$
6.44

 
$
5.95

Transportation Costs
4.54

 
4.58

DD&A -
 
 
 
Oil and Gas Properties
18.02

 
19.00

Other Property, Plant and Equipment
0.53

 
0.57

G&A
1.68

 
1.87

Interest Expense, Net
0.94

 
1.33

Total (1)
$
32.15

 
$
33.30

 
(1)
Total excludes gathering and processing costs, exploration costs, dry hole costs, impairments, marketing costs and taxes other than income.

The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, G&A and interest expense, net, for the nine months ended September 30, 2014, compared to the same period of 2013 are set forth below. See "Net Operating Revenues" above for a discussion of production volumes.

-28-



Lease and well expenses of $1,036 million for the first nine months of 2014 increased $219 million from $817 million for the same prior year period primarily due to increased operating and maintenance costs in the United States ($135 million) and Canada ($14 million) and increased workover expenditures ($55 million) and increased lease and well administrative expenses ($21 million) in the United States.

Transportation costs of $730 million for the first nine months of 2014 increased $101 million from $629 million for the same prior year period primarily due to increased transportation costs related to production from the Eagle Ford ($86 million) and the Rocky Mountain area ($23 million), partially offset by decreased transportation costs related to production from the Fort Worth Basin Barnett Shale area ($11 million).

DD&A expenses for the first nine months of 2014 increased $297 million to $2,983 million from $2,686 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first nine months of 2014 were $290 million higher than the same prior year period. The increase primarily reflects increased production in the United States ($471 million), partially offset by a decrease in unit rates in the United States ($167 million). Unit rates decreased primarily due to upward reserve revisions and reserves added at lower costs as a result of increased efficiencies.

G&A expenses of $271 million for the first nine months of 2014 increased $13 million compared to the same prior year period primarily due to increased costs associated with supporting expanding operations.

Exploration costs of $139 million for the first nine months of 2014 increased $8 million from $131 million for the same prior year period primarily due to increased geological and geophysical expenditures in the United States.

Interest expense, net, of $152 million for the first nine months of 2014 decreased $31 million compared to the same prior year period primarily due to reduced debt outstanding and a lower composite interest rate ($20 million) and increased capitalized interest ($8 million).

Gathering and processing costs for the first nine months of 2014 increased $26 million to $108 million compared to the same prior year period primarily due to increased activities in the Eagle Ford.

Impairments of $208 million for the first nine months of 2014 were $31 million higher than impairments for the same prior year period primarily due to higher impairments of proved properties in the United States ($51 million) and increased amortization of unproved property costs in the United States ($40 million), partially offset by lower impairments of other assets in the United States ($47 million) and lower impairments of proved properties in Argentina ($6 million), Canada ($3 million) and the United Kingdom ($3 million). EOG recorded impairments of proved properties, other property, plant and equipment and other assets of $84 million and $93 million for the first nine months of 2014 and 2013, respectively.

Taxes other than income for the first nine months of 2014 increased $147 million to $606 million (6.1% of wellhead revenues) from $459 million (5.8% of wellhead revenues) for the same prior year period. The increase in taxes other than income was primarily due to increases in the United States in severance/production taxes ($126 million) primarily as a result of increased wellhead revenues and higher ad valorem/property taxes ($29 million), partially offset by an increase in credits available to EOG in 2014 for Texas high-cost gas severance tax rate reductions ($3 million) and decreased severance/production taxes in Trinidad ($3 million).

Other income (expense), net for the first nine months of 2014 decreased $23 million compared to the same prior year period. The decrease was primarily due to foreign currency exchange losses of $14 million for the first nine months of 2014 compared to foreign currency exchange gains of $7 million for the first nine months of 2013.

Income tax provision of $1,376 million for the first nine months of 2014 increased $475 million from $901 million compared to the same prior year period due primarily to higher pretax income. The net effective tax rate for the first nine months of 2014 of 36% was unchanged from the same prior year period.

-29-



Capital Resources and Liquidity

Cash Flow. The primary sources of cash for EOG during the nine months ended September 30, 2014, were funds generated from operations, net proceeds from the issuance of the Notes, proceeds from asset sales, excess tax benefits from stock-based compensation and proceeds from stock options exercised and employee stock purchase plan activity. The primary uses of cash were funds used in operations; exploration and development expenditures; repayments of long-term debt; other property, plant and equipment expenditures; dividend payments to stockholders; an increase in restricted cash; and purchases of treasury stock in connection with stock compensation plans. During the first nine months of 2014, EOG's cash balance increased $163 million to $1,481 million from $1,318 million at December 31, 2013.

Net cash provided by operating activities of $6,539 million for the first nine months of 2014 increased $1,211 million compared to the same period of 2013 primarily reflecting an increase in wellhead revenues ($1,992 million), favorable changes in working capital and other assets and liabilities ($151 million) and a decrease in net cash paid for interest expense ($29 million), partially offset by an increase in cash operating expenses ($513 million), an unfavorable change in net cash flow from the settlement of financial commodity derivative contracts ($304 million) and an increase in net cash paid for income taxes ($110 million).

Net cash used in investing activities of $6,131 million for the first nine months of 2014 increased by $1,368 million compared to the same period of 2013 due primarily to an increase in additions to oil and gas properties ($569 million); a decrease in proceeds from sales of assets ($496 million); an increase in additions to other property, plant and equipment ($316 million); and an increase in restricted cash ($23 million); partially offset by favorable changes in working capital associated with investing activities ($36 million).

Net cash used in financing activities of $244 million for the first nine months of 2014 included repayments of long-term debt ($500 million), cash dividend payments ($188 million), purchases of treasury stock in connection with stock compensation plans ($115 million) and the settlement of a foreign currency swap ($32 million). Cash provided by financing activities for the first nine months of 2014 included net proceeds from the issuance of the Notes ($496 million), excess tax benefits from stock-based compensation ($88 million) and proceeds from stock options exercised and employee stock purchase plan activity ($12 million). Net cash used in financing activities of $127 million for the first nine months of 2013 included cash dividend payments ($148 million) and purchases of treasury stock in connection with stock compensation plans ($56 million). Cash provided by financing activities for the first nine months of 2013 included excess tax benefits from stock-based compensation ($50 million) and proceeds from stock options exercised and employee stock purchase plan activity ($30 million).

Total Expenditures. For the year 2014, EOG's budget for exploration and development and other property, plant and equipment expenditures is approximately $8.1 billion to $8.3 billion, excluding acquisitions. The table below sets out components of total expenditures for the nine-month periods ended September 30, 2014 and 2013 (in millions):
 
Nine Months Ended 
 September 30,
 
2014
 
2013
Expenditure Category
 
 
 
Capital
 
 
 
Drilling and Facilities
$
5,191

 
$
4,596

Leasehold Acquisitions
321

 
309

Property Acquisitions
73

 
92

Capitalized Interest
43

 
34

Subtotal
5,628

 
5,031

Exploration Costs
139

 
131

Dry Hole Costs
30

 
59

Exploration and Development Expenditures
5,797

 
5,221

Asset Retirement Costs
170

 
69

Total Exploration and Development Expenditures
5,967

 
5,290

Other Property, Plant and Equipment
587

 
271

Total Expenditures
$
6,554

 
$
5,561



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Exploration and development expenditures of $5,797 million for the first nine months of 2014 were $576 million higher than the same period of 2013 due primarily to increased drilling and facilities expenditures in the United States ($759 million) and China ($7 million), increased leasehold acquisition expenditures in the United States ($14 million), increased capitalized interest in the United States ($7 million) and increased exploration geological and geophysical expenditures in the United States ($6 million), partially offset by decreased drilling and facilities expenditures in Trinidad ($77 million), in the United Kingdom ($49 million), Canada ($39 million) and Argentina ($9 million) and decreased property acquisitions in the United States ($19 million). The exploration and development expenditures for the first nine months of 2014 of $5,797 million consist of $5,121 million in development, $560 million in exploration, $73 million in property acquisitions and $43 million in capitalized interest. The exploration and development expenditures for the first nine months of 2013 of $5,221 million consist of $4,524 million in development, $571 million in exploration, $92 million in property acquisitions and $34 million in capitalized interest.

The level of exploration and development expenditures, including acquisitions, will vary in future periods depending on energy market conditions and other related economic factors. EOG has significant flexibility with respect to financing alternatives and the ability to adjust its exploration and development expenditure budget as circumstances warrant. While EOG has certain continuing commitments associated with expenditure plans related to its operations, such commitments are not expected to be material when considered in relation to the total financial capacity of EOG.

Commodity Derivative Transactions. As more fully discussed in Note 11 to the Consolidated Financial Statements included in EOG's Annual Report on Form 10-K for the year ended December 31, 2013, filed on February 24, 2014, EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in commodity prices for crude oil and natural gas. EOG utilizes financial commodity derivative instruments, primarily price swap, option, swaption, collar and basis swap contracts, as a means to manage this price risk. EOG has not designated any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounts for financial commodity derivative contracts using the mark-to-market accounting method. Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as Gains (Losses) on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income and Comprehensive Income. The related cash flow impact is reflected in Cash Flows from Operating Activities. In addition to financial transactions, from time to time, EOG is a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and have varying pricing provisions. The financial impact of physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices.


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Commodity Derivative Contracts. The total fair value of EOG's crude oil and natural gas derivative contracts was reflected on the Consolidated Balance Sheets at September 30, 2014, as a net asset of $139 million. Presented below is a comprehensive summary of EOG's crude oil derivative contracts at November 4, 2014, with notional volumes expressed in barrels per day (Bbld) and prices expressed in dollars per barrel ($/Bbl).

Crude Oil Derivative Contracts
 
 
 
 
 
Weighted
Average Price ($/Bbl)
 
 
Volume (Bbld)
 
 
 
 
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.



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