10-Q 1 a2015093010-q.htm 10-Q 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, 2015
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
 
549,707,193 (as of October 29, 2015)

 

        



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 (LOSS) AND COMPREHENSIVE INCOME (LOSS)
(In Thousands, Except Per Share Data)
(Unaudited)
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
Net Operating Revenues
 
 
 
 
 
 
 
Crude Oil and Condensate
$
1,181,092

 
$
2,671,502

 
$
3,894,092

 
$
7,687,579

Natural Gas Liquids
95,217

 
258,927

 
311,137

 
753,135

Natural Gas
281,837

 
443,108

 
843,657

 
1,508,892

Gains on Mark-to-Market Commodity Derivative
   Contracts
29,239

 
469,125

 
56,954

 
84,119

Gathering, Processing and Marketing
572,217

 
1,196,933

 
1,820,843

 
3,240,139

Gains (Losses) on Asset Dispositions, Net
(1,185
)
 
60,346

 
(5,142
)
 
75,700

Other, Net
14,011

 
18,675

 
39,126

 
40,279

Total
2,172,428

 
5,118,616

 
6,960,667

 
13,389,843

Operating Expenses
 

 
 

 
 

 
 

Lease and Well
283,221

 
368,340

 
934,366

 
1,035,632

Transportation Costs
203,594

 
246,067

 
641,739

 
729,883

Gathering and Processing Costs
35,497

 
41,621

 
106,503

 
108,015

Exploration Costs
31,344

 
48,955

 
114,548

 
139,221

Dry Hole Costs
198

 
16,359

 
14,317

 
30,265

Impairments
6,307,420

 
55,542

 
6,445,375

 
207,938

Marketing Costs
615,303

 
1,213,652

 
1,924,134

 
3,263,471

Depreciation, Depletion and Amortization
722,172

 
1,040,018

 
2,544,187

 
2,983,111

General and Administrative
90,959

 
96,931

 
257,580

 
270,725

Taxes Other Than Income
105,677

 
204,969

 
334,244

 
606,411

Total
8,395,385

 
3,332,454

 
13,316,993

 
9,374,672

Operating Income (Loss)
(6,222,957
)
 
1,786,162

 
(6,356,326
)
 
4,015,171

Other Income (Expense), Net
8,607

 
(21,338
)
 
7,996

 
(16,726
)
Income (Loss) Before Interest Expense and Income Taxes
(6,214,350
)
 
1,764,824

 
(6,348,330
)
 
3,998,445

Interest Expense, Net
60,571

 
49,704

 
174,400

 
151,723

Income (Loss) Before Income Taxes
(6,274,921
)
 
1,715,120

 
(6,522,730
)
 
3,846,722

Income Tax Provision (Benefit)
(2,199,182
)
 
611,502

 
(2,282,511
)
 
1,375,823

Net Income (Loss)
$
(4,075,739
)
 
$
1,103,618

 
$
(4,240,219
)
 
$
2,470,899

Net Income (Loss) Per Share
 

 
 

 
 

 
 

Basic
$
(7.47
)
 
$
2.03

 
$
(7.77
)
 
$
4.55

Diluted
$
(7.47
)
 
$
2.01

 
$
(7.77
)
 
$
4.51

Dividends Declared per Common Share
$
0.1675

 
$
0.1675

 
$
0.5025

 
$
0.4175

Average Number of Common Shares
 

 
 

 
 

 
 

Basic
545,920

 
543,984

 
545,466

 
543,086

Diluted
545,920

 
549,518

 
545,466

 
548,401

Comprehensive Income (Loss)
 

 
 

 
 

 
 

Net Income (Loss)
$
(4,075,739
)
 
$
1,103,618

 
$
(4,240,219
)
 
$
2,470,899

Other Comprehensive Income (Loss)
 

 
 

 
 

 
 

Foreign Currency Translation Adjustments
(7,004
)
 
(38,886
)
 
(11,767
)
 
(27,438
)
Other, Net of Tax
28

 
23

 
(156
)
 
(671
)
Other Comprehensive Loss
(6,976
)
 
(38,863
)
 
(11,923
)
 
(28,109
)
Comprehensive Income (Loss)
$
(4,082,715
)
 
$
1,064,755

 
$
(4,252,142
)
 
$
2,442,790

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,
2015
 
December 31,
2014
ASSETS
Current Assets
 
 
 
Cash and Cash Equivalents
$
742,689

 
$
2,087,213

Accounts Receivable, Net
1,123,111

 
1,779,311

Inventories
660,252

 
706,597

Assets from Price Risk Management Activities
71,503

 
465,128

Income Taxes Receivable
53,667

 
71,621

Deferred Income Taxes
40,619

 
19,618

Other
133,117

 
286,533

Total
2,824,958

 
5,416,021

Property, Plant and Equipment
 

 
 

Oil and Gas Properties (Successful Efforts Method)
50,025,191

 
46,503,532

Other Property, Plant and Equipment
3,890,934

 
3,750,958

Total Property, Plant and Equipment
53,916,125

 
50,254,490

Less:  Accumulated Depreciation, Depletion and Amortization
(29,640,793
)
 
(21,081,846
)
Total Property, Plant and Equipment, Net
24,275,332

 
29,172,644

Other Assets
176,957

 
174,022

Total Assets
$
27,277,247

 
$
34,762,687

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
 

 
 

Accounts Payable
$
1,561,574

 
$
2,860,548

Accrued Taxes Payable
174,897

 
140,098

Dividends Payable
91,377

 
91,594

Deferred Income Taxes

 
110,743

Short-Term Borrowings and Current Portion of Long-Term Debt
36,279

 
6,579

Other
182,834

 
174,746

Total
2,046,961

 
3,384,308

 
 
 
 
Long-Term Debt
6,393,931

 
5,903,354

Other Liabilities
970,288

 
939,497

Deferred Income Taxes
4,581,844

 
6,822,946

Commitments and Contingencies (Note 8)


 


 
 
 
 
Stockholders' Equity
 

 
 

Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 550,052,879 Shares Issued at September 30, 2015 and 549,028,374 Shares Issued at December 31, 2014
205,503

 
205,492

Additional Paid in Capital
2,897,439

 
2,837,150

Accumulated Other Comprehensive Loss
(34,979
)
 
(23,056
)
Retained Earnings
10,247,349

 
14,763,098

Common Stock Held in Treasury, 383,870 Shares at September 30, 2015 and 733,517 Shares at December 31, 2014
(31,089
)
 
(70,102
)
Total Stockholders' Equity
13,284,223

 
17,712,582

Total Liabilities and Stockholders' Equity
$
27,277,247

 
$
34,762,687


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,
 
2015
 
2014
Cash Flows from Operating Activities
 
 
 
Reconciliation of Net Income (Loss) to Net Cash Provided by Operating Activities:
 
 
 
Net Income (Loss)
$
(4,240,219
)
 
$
2,470,899

Items Not Requiring (Providing) Cash
 

 
 

Depreciation, Depletion and Amortization
2,544,187

 
2,983,111

Impairments
6,445,375

 
207,938

Stock-Based Compensation Expenses
101,926

 
103,636

Deferred Income Taxes
(2,377,030
)
 
974,522

(Gains) Losses on Asset Dispositions, Net
5,142

 
(75,700
)
Other, Net
3,735

 
17,188

Dry Hole Costs
14,317

 
30,265

Mark-to-Market Commodity Derivative Contracts
 

 
 

Total Gains
(56,954
)
 
(84,119
)
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts
661,021

 
(188,937
)
Excess Tax Benefits from Stock-Based Compensation
(24,219
)
 
(87,827
)
Other, Net
8,904

 
8,701

Changes in Components of Working Capital and Other Assets and Liabilities
 

 
 

Accounts Receivable
448,311

 
(341,043
)
Inventories
27,007

 
(119,166
)
Accounts Payable
(1,310,211
)
 
566,753

Accrued Taxes Payable
77,575

 
176,412

Other Assets
146,965

 
(61,966
)
Other Liabilities
(15,683
)
 
66,618

Changes in Components of Working Capital Associated with Investing and Financing Activities
519,203

 
(108,568
)
Net Cash Provided by Operating Activities
2,979,352

 
6,538,717

Investing Cash Flows
 

 
 

Additions to Oil and Gas Properties
(3,918,065
)
 
(5,653,035
)
Additions to Other Property, Plant and Equipment
(252,295
)
 
(587,178
)
Proceeds from Sales of Assets
144,285

 
91,335

Changes in Restricted Cash

 
(91,238
)
Changes in Components of Working Capital Associated with Investing Activities
(519,323
)
 
108,999

Net Cash Used in Investing Activities
(4,545,398
)
 
(6,131,117
)
Financing Cash Flows
 

 
 

Net Commercial Paper Borrowings
29,700

 

Long-Term Debt Borrowings
990,225

 
496,220

Long-Term Debt Repayments
(500,000
)
 
(500,000
)
Settlement of Foreign Currency Swap

 
(31,573
)
Dividends Paid
(274,577
)
 
(187,670
)
Excess Tax Benefits from Stock-Based Compensation
24,219

 
87,827

Treasury Stock Purchased
(43,419
)
 
(114,824
)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan
14,967

 
11,740

Debt Issuance Costs
(5,933
)
 
(895
)
Repayment of Capital Lease Obligation
(4,599
)
 
(4,457
)
Other, Net
120

 
(431
)
Net Cash Provided by (Used in) Financing Activities
230,703

 
(244,063
)
Effect of Exchange Rate Changes on Cash
(9,181
)
 
(601
)
Increase (Decrease) in Cash and Cash Equivalents
(1,344,524
)
 
162,936

Cash and Cash Equivalents at Beginning of Period
2,087,213

 
1,318,209

Cash and Cash Equivalents at End of Period
$
742,689

 
$
1,481,145

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, 2014, filed on February 18, 2015 (EOG's 2014 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, 2015, are not necessarily indicative of the results to be expected for the full year.

Recently Issued Accounting Standards. In July 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2015-11, "Accounting for Inventory" (ASU 2015-11), which requires entities to measure most inventory at lower of cost or net realizable value. ASU 2015-11 defines net realizable value as "the estimated selling prices in the ordinary course of business, less reasonably predictable cost of completion, disposal and transportation." ASU 2015-11 is effective prospectively for interim and annual periods beginning after December 15, 2016. EOG is reviewing the requirements of the new standard and does not believe that the adoption of ASU 2015-11 will have a material impact on its consolidated financial statements and related disclosures.

In April 2015, the FASB issued ASU 2015-03, "Interest - Computation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs" (ASU 2015-03), which changes the presentation of debt issuance costs in financial statements. Under ASU 2015-03, an entity will present debt issuance costs in the balance sheet as a direct reduction from the related debt liability rather than as an asset. Amortization of such costs will be presented as a component of interest expense. ASU 2015-03 is effective for interim and annual reporting periods beginning after December 15, 2015. Early adoption is permitted. Because ASU 2015-03 does not address debt issuance costs related to line-of-credit arrangements, in August 2015, the FASB issued ASU 2015-15 "Interest - Computation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements" (ASU 2015-15). ASU 2015-15 provides that, in the absence of authoritative guidance in ASU 2015-03, the SEC would not object to an entity deferring and presenting debt issuance costs related to a line-of-credit arrangement as an asset and subsequently amortizing the deferred debt issuance costs over the term of the line-of-credit arrangement. EOG does not expect the adoption of ASU 2015-03 and ASU 2015-15 to have a material impact on its consolidated financial statements and related disclosures.

In May 2014, the FASB issued 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. The FASB originally intended ASU 2014-09 to be effective for interim and annual reporting periods beginning after December 15, 2016 and permits adoption through the use of either the full retrospective approach or a modified retrospective approach. In July 2015, the FASB issued an update which delays by one year the effective date of ASU 2014-09 and allows for early adoption as of the original effective date. EOG has not determined which transition method it will use and is continuing to analyze 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 7 to the Consolidated Financial Statements included in EOG's 2014 Annual Report, EOG maintains various stock-based compensation plans. Stock-based compensation expense is included on the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) 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,
 
2015
 
2014
 
2015
 
2014
Lease and Well
$
10.3

 
$
9.7

 
$
32.9

 
$
30.4

Gathering and Processing Costs
0.4

 
0.4

 
1.0

 
0.9

Exploration Costs
6.0

 
6.7

 
19.3

 
20.2

General and Administrative
23.6

 
21.7

 
48.8

 
52.1

Total
$
40.3

 
$
38.5

 
$
102.0

 
$
103.6


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 (SAR), restricted stock and restricted stock units, performance units and performance stock and other stock-based awards. At September 30, 2015, approximately 24.6 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 grants 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 $20.0 million and $21.2 million during the three months ended September 30, 2015 and 2014, respectively, and $43.3 million and $44.9 million during the nine months ended September 30, 2015 and 2014, 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, 2015 and 2014 are as follows:
 
Stock Options/SARs
 
ESPP
 
Nine Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
Weighted Average Fair Value of Grants
$
21.87

 
$
30.77

 
$
21.40

 
$
21.27

Expected Volatility
38.04
%
 
35.25
%
 
32.54
%
 
25.12
%
Risk-Free Interest Rate
0.83
%
 
0.95
%
 
0.12
%
 
0.08
%
Dividend Yield
0.85
%
 
0.60
%
 
0.72
%
 
0.50
%
Expected Life
5.3 years

 
5.2 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, 2015 and 2014 (stock options and SARs in thousands):
 
Nine Months Ended 
 September 30, 2015
 
Nine Months Ended 
 September 30, 2014
 
Number of
Stock
Options/SARs
 
Weighted
Average
Grant
Price
 
Number of
Stock
Options/SARs
 
Weighted
Average
Grant
Price
Outstanding at January 1
10,493

 
$
64.96

 
10,452

 
$
54.43

Granted
2,029

 
69.95

 
2,122

 
101.65

Exercised (1)
(1,291
)
 
47.25

 
(1,351
)
 
44.52

Forfeited
(203
)
 
80.12

 
(226
)
 
62.95

Outstanding at September 30 (2)
11,028

 
$
67.67

 
10,997

 
$
64.58

Vested or Expected to Vest (3)
10,653

 
$
67.22

 
10,568

 
$
63.92

Exercisable at September 30 (4)
6,121

 
$
57.34

 
5,573

 
$
49.23


(1)
The total intrinsic value of stock options/SARs exercised for the nine months ended September 30, 2015 and 2014 was $52.4 million and $78.0 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, 2015 and 2014 was $136.9 million and $384.9 million, respectively. At September 30, 2015 and 2014, the weighted average remaining contractual life was 4.4 years and 4.6 years, respectively.
(3)
The total intrinsic value of stock options/SARs vested or expected to vest at September 30, 2015 and 2014 was $135.7 million and $376.6 million, respectively. At September 30, 2015 and 2014, the weighted average remaining contractual life was 4.3 years and 4.5 years, respectively.
(4)
The total intrinsic value of stock options/SARs exercisable at September 30, 2015 and 2014 was $121.6 million and $277.5 million, respectively. At September 30, 2015 and 2014, the weighted average remaining contractual life was 3.1 years and 3.3 years, respectively.

At September 30, 2015, unrecognized compensation expense related to non-vested stock option, SAR and ESPP grants totaled $112.2 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 3.0 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 $16.2 million and $13.9 million for the three months ended September 30, 2015 and 2014, respectively, and $53.9 million and $53.4 million for the nine months ended September 30, 2015 and 2014, 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, 2015 and 2014 (shares and units in thousands):
 
Nine Months Ended 
 September 30, 2015
 
Nine Months Ended 
 September 30, 2014
 
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
5,394

 
$
64.39

 
7,358

 
$
49.54

Granted
1,036

 
77.90

 
1,024

 
99.00

Released (1)
(1,250
)
 
51.02

 
(2,540
)
 
37.92

Forfeited
(152
)
 
74.83

 
(220
)
 
59.36

Outstanding at September 30 (2)
5,028

 
$
70.18

 
5,622

 
$
63.41

 
(1)
The total intrinsic value of restricted stock and restricted stock units released for the nine months ended September 30, 2015 and 2014 was $102.5 million and $270.0 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date the restricted stock and restricted stock units are released.
(2)
The total intrinsic value of restricted stock and restricted stock units outstanding at September 30, 2015 and 2014 was $366.0 million and $556.7 million, respectively.

At September 30, 2015, unrecognized compensation expense related to restricted stock and restricted stock units totaled $194.5 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.7 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 $4.1 million and $3.4 million for the three months ended September 30, 2015 and 2014, respectively, and $4.8 million and $5.3 million for the nine months ended September 30, 2015 and 2014, 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, 2015 and 2014 are as follows:

 
Nine Months Ended 
 September 30,
 
2015
 
2014
Weighted Average Fair Value of Grants
$
80.64

 
$
119.27

Expected Volatility
29.35
%
 
32.18
%
Risk-Free Interest Rate
1.07
%
 
1.18
%

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, 2015 and 2014 (shares and units in thousands):

 
Nine Months Ended 
 September 30, 2015
 
Nine Months Ended 
 September 30, 2014
 
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
333

 
$
90.17

 
261

 
$
82.18

Granted
72

 
80.64

 
72

 
119.27

Released

 

 

 

Forfeited

 

 

 

Outstanding at September 30 (1)
405

 
$
88.48

 
333

 
$
90.17

 
(1)
The total intrinsic value of performance units and performance stock outstanding at September 30, 2015 and 2014 was $29.5 million and $33.0 million, respectively.

At September 30, 2015, unrecognized compensation expense related to performance units and performance stock totaled $6.4 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 3.5 years.

3.    Net Income (Loss) Per Share

The following table sets forth the computation of Net Income (Loss) Per Share for the three-month and nine-month periods ended September 30, 2015 and 2014 (in thousands, except per share data):
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
Numerator for Basic and Diluted Earnings Per Share -
 
 
 
 
 
 
 
Net Income (Loss)
$
(4,075,739
)
 
$
1,103,618

 
$
(4,240,219
)
 
$
2,470,899

Denominator for Basic Earnings Per Share -
 

 
 

 
 

 
 

Weighted Average Shares
545,920

 
543,984

 
545,466

 
543,086

Potential Dilutive Common Shares -
 

 
 

 
 

 
 

Stock Options/SARs

 
2,760

 

 
2,644

Restricted Stock/Units and Performance Units/Stock

 
2,774

 

 
2,671

Denominator for Diluted Earnings Per Share -
 

 
 

 
 

 
 

Adjusted Diluted Weighted Average Shares
545,920

 
549,518

 
545,466

 
548,401

Net Income (Loss) Per Share
 

 
 

 
 

 
 

Basic
$
(7.47
)
 
$
2.03

 
$
(7.77
)
 
$
4.55

Diluted
$
(7.47
)
 
$
2.01

 
$
(7.77
)
 
$
4.51


The diluted earnings per share calculation excludes stock options, SARs, restricted stock and units and performance units and stock that were anti-dilutive. Shares underlying the excluded stock options and SARs totaled 9.8 million and 0.2 million shares for the three months ended September 30, 2015 and 2014, respectively, and 10.0 million and 0.2 million shares for the nine months ended September 30, 2015 and 2014, respectively. For both the three months and nine months ended September 30, 2015, 5.4 million shares of restricted stock and restricted stock units and performance units and performance stock were excluded.


-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, 2015 and 2014 (in thousands):
 
Nine Months Ended 
 September 30,
 
2015
 
2014
Interest (1)
$
152,590

 
$
143,615

Income Taxes, Net of Refunds Received
$
69,281

 
$
330,476

 
(1)
Net of capitalized interest of $33 million and $43 million for the nine months ended September 30, 2015 and 2014, respectively.

EOG's accrued capital expenditures at September 30, 2015 and 2014 were $437 million and $960 million, respectively.

5.    Segment Information

As more fully discussed in Note 13, during the fourth quarter of 2014, EOG completed the sale of substantially all of its Canadian operations. As a result, information related to EOG's remaining Canadian operations have been included in the Other International segment and prior year amounts have been reclassified to conform to current year presentation. Selected financial information by reportable segment is presented below for the three-month and nine-month periods ended September 30, 2015 and 2014 (in thousands):
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
Net Operating Revenues
 
 
 
 
 
 
 
United States
$
2,040,881

 
$
4,924,226

 
$
6,622,781

 
$
12,748,128

Trinidad
98,493

 
123,154

 
290,758

 
398,140

Other International (1)
33,054

 
71,236

 
47,128

 
243,575

Total
$
2,172,428

 
$
5,118,616

 
$
6,960,667

 
$
13,389,843

Operating Income (Loss)
 

 
 

 
 

 
 

United States
$
(6,110,284
)
 
$
1,767,044

 
$
(6,271,908
)
 
$
3,900,263

Trinidad
46,230

 
61,328

 
139,116

 
209,785

Other International (1)
(158,903
)
 
(42,210
)
 
(223,534
)
 
(94,877
)
Total
(6,222,957
)
 
1,786,162

 
(6,356,326
)
 
4,015,171

Reconciling Items
 

 
 

 
 

 
 

Other Income (Expense), Net
8,607

 
(21,338
)
 
7,996

 
(16,726
)
Interest Expense, Net
60,571

 
49,704

 
174,400

 
151,723

Income (Loss) Before Income Taxes
$
(6,274,921
)
 
$
1,715,120

 
$
(6,522,730
)
 
$
3,846,722

 
(1)    Other International primarily includes EOG's Canada, 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, 2015 and December 31, 2014 (in thousands):
 
At
September 30,
2015
 
At
December 31,
2014
Total Assets
 
 
 
United States
$
25,550,746

 
$
32,871,398

Trinidad
879,643

 
865,674

Other International (1)
846,858

 
1,025,615

Total
$
27,277,247

 
$
34,762,687

 
(1)    Other International primarily includes EOG's Canada, 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, 2015 and 2014 (in thousands):
 
Nine Months Ended 
 September 30,
 
2015
 
2014
Carrying Amount at Beginning of Period
$
752,718

 
$
761,898

Liabilities Incurred
38,095

 
91,822

Liabilities Settled (1)
(12,929
)
 
(44,805
)
Accretion
23,810

 
33,833

Revisions
(13,576
)
 
68,785

Foreign Currency Translations
(4,361
)
 
(4,178
)
Carrying Amount at End of Period
$
783,757

 
$
907,355

 
 
 
 
Current Portion
$
11,592

 
$
12,528

Noncurrent Portion
$
772,165

 
$
894,827

 
(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, 2015, are presented below (in thousands):
 
Nine Months Ended 
 September 30, 2015
 
Balance at January 1
$
17,253

 
Additions Pending the Determination of Proved Reserves
23,936

 
Reclassifications to Proved Properties
(26,499
)
 
Costs Charged to Expense
(6,178
)
(1)
Balance at September 30
$
8,512

 
 
(1)
Includes capitalized exploratory well costs charged to dry hole costs.

At September 30, 2015, 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, Trinidad and the United Kingdom, and defined benefit pension plans covering certain of its employees in Trinidad. For the nine months ended September 30, 2015 and 2014, EOG's total costs recognized for these pension plans were $27.0 million and $29.6 million, respectively. In connection with the divestiture of substantially all of its Canadian assets in the fourth quarter of 2014, EOG has elected to terminate the Canadian non-contributory defined benefit pension plan. 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

During the nine months ended September 30, 2015 and 2014, EOG utilized commercial paper and short-term borrowings under uncommitted credit facilities, bearing market interest rates, for various corporate financing purposes. At September 30, 2015 and 2014, EOG had $30 million and zero, respectively, of outstanding short-term borrowings from commercial paper and no outstanding borrowings from uncommitted credit facilities. The average borrowings outstanding under the commercial paper program were $7 million and $16 million during the nine months ended September 30, 2015 and 2014, respectively. The average borrowings outstanding under the uncommitted credit facilities were zero and $0.1 million during the nine months ended September 30, 2015 and 2014, respectively. The weighted average interest rates for commercial paper borrowings during the nine months ended September 30, 2015 and 2014 were 0.45% and 0.25%, respectively, and 0.70% for uncommitted credit facility borrowings during the nine months ended September 30, 2014.

At September 30, 2015, the $400 million aggregate principal amount of 2.500% Senior Notes due 2016 were classified as long-term debt based upon EOG's intent and ability to ultimately replace such amount with other long-term debt.

On June 1, 2015, EOG repaid upon maturity the $500 million aggregate principal amount of its 2.95% Senior Notes due 2015.

On March 17, 2015, EOG closed its sale of the $500 million aggregate principal amount of its 3.15% Senior Notes due 2025 and the $500 million aggregate principal amount of its 3.90% Senior Notes due 2035 (together, the Notes). Interest on the Notes is

-13-

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


payable semi-annually in arrears on April 1 and October 1 of each year, beginning on October 1, 2015. Net proceeds from the Notes offering of approximately $990 million were used for general corporate purposes.

On July 21, 2015, EOG entered into a new $2.0 billion senior unsecured Revolving Credit Agreement (2015 Agreement) with domestic and foreign lenders. The 2015 Agreement replaces EOG's $2.0 billion senior unsecured Revolving Credit Agreement, dated as of October 11, 2011, which had a scheduled maturity date of October 11, 2016  (2011 Agreement). There were no borrowings or letters of credit outstanding under the 2011 Agreement as of the closing of the 2015 Agreement and the termination of the 2011 Agreement. The 2015 Agreement has a scheduled maturity date of July 21, 2020, and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods subject to certain terms and conditions. Advances under the 2015 Agreement will accrue interest based, at EOG's option, on either the London InterBank Offered Rate plus an applicable margin (Eurodollar rate) or the base rate (as defined in the 2015 Agreement) plus an applicable margin. Consistent with the terms of the 2011 Agreement, the 2015 Agreement contains representations, warranties, covenants and events of default that are customary for investment-grade, senior unsecured commercial bank credit agreements, including a financial covenant for the maintenance of a debt-to-total capitalization ratio of no greater than 65%. At September 30, 2015, there were no borrowings or letters of credit outstanding under the 2015 Agreement. The Eurodollar rate and applicable base rate, had there been any amounts borrowed under the 2015 Agreement, would have been 1.09% and 3.25%, respectively.
11.    Fair Value Measurements

As more fully discussed in Note 13 to the Consolidated Financial Statements included in EOG's 2014 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, 2015 and December 31, 2014 (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, 2015
 
 
 
 
 
 
 
Financial Assets
 
 
 
 
 
 
 
Natural Gas Options/Swaptions
$

 
$
31

 
$

 
$
31

Crude Oil Swaps/Put Options

 
40

 

 
40

 
 
 
 
 
 
 
 
At December 31, 2014
 

 
 

 
 

 
 

Financial Assets
 

 
 

 
 

 
 

Natural Gas Options/Swaptions
$

 
$
100

 
$

 
$
100

Crude Oil Swaps

 
121

 

 
121

Crude Oil Options/Swaptions

 
244

 

 
244


The estimated fair value of crude oil and natural gas derivative contracts (including options/swaptions) was based upon forward commodity price curves based on quoted market prices. 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.


-14-

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


Due to the decline in commodity prices, proved oil and gas properties, other property, plant and equipment and other assets with a carrying amount of $8,857 million were written down to their fair value of $2,627 million, resulting in pretax impairment charges of $6,230 million, $4,061 million net of tax, for the nine months ended September 30, 2015. Impairments included domestic legacy natural gas assets and marginal liquids plays and the Conwy crude oil project in the East Irish Sea. 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 September 30, 2015 and December 31, 2014, EOG had outstanding $6,390 million and $5,890 million, respectively, aggregate principal amount of senior notes, which had estimated fair values of approximately $6,673 million and $6,242 million, respectively. The estimated fair value of the senior notes 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 12 to the Consolidated Financial Statements included in EOG's 2014 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.

Commodity Derivative Contracts. Presented below is a comprehensive summary of EOG's crude oil price swap contracts at September 30, 2015, with notional volumes expressed in barrels per day (Bbld) and prices expressed in dollars per barrel ($/Bbl).
 
Crude Oil Price Swap Contracts
 
 
 
Volume
(Bbld)
 
Weighted
Average Price
($/Bbl)
 
 
2015
 
 
 
 
 
January 1, 2015 through June 30, 2015 (closed)
 
47,000

 
$
91.22

 
July 1, 2015 through September 30, 2015 (closed)
 
10,000

 
89.98

 
October 1, 2015 through December 31, 2015
 
10,000

 
89.98


-15-

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



EOG has purchased put options which establish a floor price for the sale of certain notional volumes of crude oil as specified in the put option contracts. The put options grant EOG the right to receive the difference between the put option strike price and the average NYMEX West Texas Intermediate crude oil price for the contract month (Index Price), in the event the Index Price is below the put option strike price. If the Index Price is above the put option strike price, EOG is only required to pay the put option premium. Below is a summary of EOG's put option contracts at September 30, 2015, with notional volumes expressed in Bbld and prices and premiums expressed in $/Bbl.
Crude Oil Put Option Contracts
 
 
Volume
(Bbld)
 
Average
Premium
($/Bbl)
 
Strike
Price
($/Bbl)
2015
 
 
 
 
 
 
September 2015 (closed)
 
82,500

 
$
1.75

 
$
45.00

October 1, 2015 through November 30, 2015
 
82,500

 
1.75

 
45.00



Presented below is a comprehensive summary of EOG's natural gas price swap contracts at September 30, 2015, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).
Natural Gas Price Swap Contracts
 
Volume (MMBtud)
 
Weighted Average Price
($/MMBtu)
2015 (1)
 

 
 

January 1, 2015 through February 28, 2015 (closed)
235,000

 
$
4.47

March 2015 (closed)
225,000

 
4.48

April 2015 (closed)
195,000

 
4.49

May 2015 (closed)
235,000

 
4.13

June 1, 2015 through July 31, 2015 (closed)
275,000

 
3.98

August 1, 2015 through October 31, 2015 (closed)
175,000

 
4.51

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

 
4.51

 
(1)
EOG has entered into natural gas price swap contracts which give counterparties the option of entering into price swap 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 price swap contracts will increase by 175,000 MMBtud at an average price of $4.51 per MMBtu for each month during the period November 1, 2015 through December 31, 2015.


-16-

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, 2015 and December 31, 2014. 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,
2015
 
December 31,
2014
 
 
 
 
 
 
 
Asset Derivatives
 
 
 
 
 
 
Crude oil and natural gas derivative contracts -
 
 
 
 
 
 
Current portion
 
Assets from Price Risk Management Activities (1)
 
$
71

 
$
465

 
 
 
 
 

 
 

Liability Derivatives
 
 
 
 

 
 

Crude oil and natural gas derivative contracts -
 
 
 
 

 
 

Current portion
 
Liabilities from Price Risk Management
   Activities (2)
 
$

 
$

 
(1)
The current portion of Assets from Price Risk Management Activities consists of gross assets of $80 million, partially offset by gross liabilities of $9 million at September 30, 2015, and gross assets of $477 million, partially offset by gross liabilities of $12 million at December 31, 2014.
(2)
The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $9 million, offset by gross assets of $9 million at September 30, 2015, and gross liabilities of $12 million, offset by gross assets of $12 million at December 31, 2014.

Credit Risk. Notional contract amounts are used to express the magnitude of commodity price 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 asset position at September 30, 2015 and December 31, 2014. EOG held collateral of $30 million and $278 million at September 30, 2015 and December 31, 2014, respectively, and had no collateral posted at September 30, 2015 or December 31, 2014.


-17-

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


13.  Acquisitions and Divestitures

During the third quarter of 2015, EOG completed three transactions to acquire certain proved crude oil properties and related assets in the Delaware Basin. The aggregate purchase price of the transactions totaled approximately $368 million.

During the first nine months of 2015, EOG received proceeds of approximately $144 million primarily from sales of gathering and processing assets. 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 fourth quarter of 2014, EOG received proceeds of approximately $400 million from the divestiture of all its assets in Manitoba and the majority of its assets in Alberta (collectively, the Canadian Sales). The Canadian Sales that closed on or about December 1, 2014, occurred in two separate transactions, an asset sale and the sale of the stock of certain of EOG's Canadian subsidiaries. As these two transactions represented a substantially complete liquidation of EOG's Canadian operations, approximately $383 million of cumulative translation adjustments previously recorded on the Consolidated Balance Sheets was reclassified to the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss). The Canadian Sales also resulted in the release of approximately $150 million of restricted cash related to future abandonment liabilities.


-18-

        



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, Trinidad, Canada, the United Kingdom and China. EOG operates under a consistent business 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. 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. 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 71% of total United States production during the first nine months of 2015 as compared to 70% for the same comparable period in 2014. In 2015, EOG is focused on increasing drilling and completion efficiencies, testing methods to improve the recovery factor of oil-in-place and reducing operating costs through efficiency improvements and service cost reductions. Through the first nine months of 2015, drilling continued to occur primarily in the Eagle Ford, Delaware Basin and North Dakota Bakken plays, where EOG has built an inventory of uncompleted wells. In addition, EOG continues to look for opportunities to add drilling inventory through leasehold acquisitions, farm-ins or tactical acquisitions and to evaluate certain potential crude oil and liquids-rich natural gas exploration and development prospects. During the third quarter of 2015, EOG completed three transactions to acquire certain proved crude oil properties and related assets in the Delaware Basin. The aggregate purchase price of the transactions totaled approximately $368 million. Based on its 2015 drilling plan, which has been influenced by the current low commodity price environment, EOG expects its 2015 crude oil and condensate and NGL production to be relatively flat compared to 2014. EOG's major producing areas in the United States are in New Mexico, North Dakota, Texas, Utah and Wyoming.

During the third quarter of 2015, due to the decline in commodity prices, proved oil and gas properties and related assets were written down to their fair value resulting in pretax impairment charges of $6,081 million, $3,913 million net of tax. Impairments were related to legacy natural gas assets and marginal liquids plays.

Canada. As previously reported, during the fourth quarter of 2014, EOG completed the divestiture of substantially all its assets in Canada (see Note 13 to the Consolidated Financial Statements). At the time of the sales, production from the divested assets totaled approximately 7,050 barrels of crude oil per day, 580 barrels of NGLs per day and 43.5 million cubic feet of natural gas per day. Net proved reserves divested were estimated to be 7.7 million barrels of oil, 0.8 million barrels of NGLs and 78.7 billion cubic feet of natural gas. Information related to EOG's remaining Canadian operations is presented in the "Other International" segment.

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), Modified U(b) Block and the EMZ Area have been developed and are producing natural gas, which is sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary. Crude oil and condensate from these fields are sold to the Petroleum Company of Trinidad and Tobago Limited. In the third quarter of 2015, EOG completed its three net well drilling program in Trinidad.

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 throughout the first nine months of 2015. In the third quarter of 2015, EOG recorded pretax impairment charges of $138 million for the Conwy project, primarily related to the continued decline in crude oil prices. First production from the Conwy field is anticipated by the end of 2015.


-19-

        



During the first nine months of 2015, in the Sichuan Basin, Sichuan Province, China, EOG drilled and completed a well. The successful completion extended the Shaxzimiao development in the Chuanzhong Block and provides additional opportunity for 2016.

EOG's activity in Argentina is focused on the Vaca Muerta oil shale formation in the Neuquén Province. Management is currently evaluating options for this investment.

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

The declines in commodity prices are expected to negatively impact the amount of EOG's year-end 2015 reserves to be calculated under the United States Securities and Exchange Commission rules which require companies to use a trailing 12-month average price to determine the year-end reported reserve quantities. Such prices have decreased in 2015 by approximately 45% for crude oil and condensate and 40% for natural gas compared to the prices used in estimating the reserves disclosed in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2014. EOG is unable to predict the amount of future reserve revisions at this time.

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 33% and 25% at September 30, 2015 and December 31, 2014, 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, 2015, the $400 million aggregate principal amount of EOG's 2.500% Senior Notes due 2016 was classified as long-term debt based upon its intent and ability to ultimately replace such amount with other long-term debt.

On July 21, 2015, EOG entered into a new $2.0 billion senior unsecured Revolving Credit Agreement (2015 Agreement) with domestic and foreign lenders (Banks). The 2015 Agreement replaces EOG's $2.0 billion senior unsecured revolving credit agreement which was cancelled by EOG upon the closing of the 2015 Agreement. The 2015 Agreement has a scheduled maturity date of July 21, 2020, and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods, subject to certain terms and conditions. The 2015 Agreement commits the Banks to provide advances up to an aggregate principal amount of $2.0 billion at any one time outstanding, with an option for EOG to request increases in the aggregate commitments to an amount not to exceed $3.0 billion, subject to certain terms and conditions.

On June 1, 2015, EOG repaid upon maturity the $500 million aggregate principal amount of its 2.95% Senior Notes due 2015.

On March 17, 2015, EOG closed its sale of the $500 million aggregate principal amount of its 3.15% Senior Notes due 2025 and the $500 million aggregate principal amount of its 3.90% Senior Notes due 2035 (together, the Notes). Interest on the Notes is payable semi-annually in arrears on April 1 and October 1 of each year, beginning on October 1, 2015. Net proceeds from the Notes offering of approximately $990 million were used for general corporate purposes.

Total anticipated 2015 capital expenditures are estimated to range from approximately $4.7 billion to $4.9 billion, excluding acquisitions. The majority of 2015 expenditures have been, and will continue to be, focused on United States crude oil drilling activities. The 2015 capital expenditure program has been structured to maintain EOG's strategy of capital discipline by funding its exploration, development and exploitation activities primarily from available internally generated cash flows and cash on hand. 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 the 2015 Agreement 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.



-20-

        



Results of Operations

The following review of operations for the three months ended September 30, 2015 and 2014 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, 2015 vs. Three Months Ended September 30, 2014

Net Operating Revenues. During the third quarter of 2015, net operating revenues decreased $2,947 million, or 58%, to $2,172 million from $5,119 million for the same period of 2014. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGLs and natural gas, for the third quarter of 2015 decreased $1,816 million, or 54%, to $1,558 million from $3,374 million for the same period of 2014. During the third quarter of 2015, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $29 million compared to net gains of $469 million for the same period of 2014. Gathering, processing and marketing revenues, which are revenues generated from sales of third-party crude oil and condensate, NGLs and natural gas as well as fees associated with gathering third-party natural gas and revenues from sales of EOG-owned sand, for the third quarter of 2015 decreased $625 million, or 52%, to $572 million from $1,197 million for the same period of 2014.


-21-

        



Wellhead volume and price statistics for the three-month periods ended September 30, 2015 and 2014 were as follows:
 
Three Months Ended 
 September 30,
 
2015
 
 
2014
Crude Oil and Condensate Volumes (MBbld) (1)
 
 
 
 
United States
278.3

 
 
293.2

Trinidad
1.0

 
 
0.9

Other International (2)
0.2

 
 
5.4

Total
279.5

 
 
299.5

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

 
 
 

United States
$
45.93

 
 
$
97.33

Trinidad
38.56

 
 
87.87

Other International (2)
61.80

 
 
87.72

Composite
45.91

 
 
97.13

Natural Gas Liquids Volumes (MBbld) (1)
 
 
 
 
United States
77.7

 
 
85.8

Other International (2)
0.1

 
 
0.6

Total
77.8

 
 
86.4

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

 
 
 

United States
$
13.25

 
 
$
32.61

Other International (2)
8.05

 
 
40.38

Composite
13.24

 
 
32.67

Natural Gas Volumes (MMcfd) (1)
 
 
 
 
United States
889

 
 
941

Trinidad
355

 
 
356

Other International (2)
30

 
 
72

Total
1,274

 
 
1,369

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

 
 
 

United States
$
2.04

 
 
$
3.48

Trinidad
2.90

 
 
3.50

Other International (2)
7.18

(5)
 
4.16

Composite
2.40

 
 
3.52

Crude Oil Equivalent Volumes (MBoed) (4)
 
 
 
 
United States
504.2

 
 
536.1

Trinidad
60.2

 
 
60.1

Other International (2)
5.2

 
 
17.9

Total
569.6

 
 
614.1

 
 
 
 
 
Total MMBoe (4)
52.4

 
 
56.5

 
(1)
Thousand barrels per day or million cubic feet per day, as applicable.
(2)
Other International includes EOG's Canada, 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, NGLs and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs 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.
(5)
Includes revenue adjustment of $3.62 per Mcf related to a price adjustment for natural gas sales made in China during the period June 2012 through March 2015.

-22-

        




Wellhead crude oil and condensate revenues for the third quarter of 2015 decreased $1,491 million, or 56%, to $1,181 million from $2,672 million for the same period of 2014. The decline was primarily due to a lower composite wellhead crude oil and condensate price ($1,318 million) and a decrease of 20 MBbld, or 7%, in wellhead crude oil and condensate production ($173 million). Decreased production in the Rocky Mountain area, the Eagle Ford, Other International and the Fort Worth Basin Barnett Shale area was partially offset by increased production in the Permian Basin. The decrease in Other International was primarily due to the divestiture of substantially all of EOG's Canadian operations in the fourth quarter of 2014. EOG's composite wellhead crude oil and condensate price for the third quarter of 2015 decreased 53% to $45.91 per barrel compared to $97.13 per barrel for the same period of 2014.

NGL revenues for the third quarter of 2015 decreased $164 million, or 63%, to $95 million from $259 million for the same period of 2014 due to a lower composite average price ($140 million), and a decrease of 9 MBbld, or 10%, in NGL deliveries ($24 million) primarily in the Fort Worth Basin Barnett Shale area. EOG's composite NGL price for the third quarter of 2015 decreased 59% to $13.24 per barrel compared to $32.67 per barrel for the same period of 2014.

Wellhead natural gas revenues for the third quarter of 2015 decreased $161 million, or 36%, to $282 million from $443 million for the same period of 2014. The decrease was due to a lower composite wellhead natural gas price ($130 million) and a decrease in natural gas deliveries ($31 million). Natural gas deliveries for the third quarter of 2015 decreased 95 MMcfd, or 7%, compared to the same period of 2014 due primarily to lower production in the United States (52 MMcfd) and in Other International (42 MMcfd). The decrease in the United States was due primarily to decreased production in the Upper Gulf Coast, Fort Worth Basin Barnett Shale and South Texas areas, partially offset by increased production of associated natural gas from the Permian Basin and Eagle Ford. EOG's composite wellhead natural gas price for the third quarter of 2015 decreased 32% to $2.40 per Mcf compared to $3.52 per Mcf for the same period of 2014.

During the third quarter of 2015, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $29 million compared to net gains of $469 million for the same period of 2014. During the third quarter of 2015, net cash received from settlements of crude oil and natural gas financial derivative contracts was $100 million and net cash payments for settlements of crude oil and natural gas financial derivative contracts were $68 million for the same period of 2014.

Gathering, processing and marketing revenues primarily 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. Gathering, processing and marketing revenues also include fees associated with gathering third-party natural gas and revenues from sales of EOG-owned sand. Marketing costs represent the costs of purchasing third-party crude oil and natural gas and the associated transportation costs as well as costs associated with EOG-owned sand sold to third parties.

Gathering, processing and marketing revenues less marketing costs for the third quarter of 2015 decreased $26 million as compared to the same period of 2014. The decrease primarily reflects lower margins on crude oil marketing activities.


-23-

        



Operating and Other Expenses.  For the third quarter of 2015, operating expenses of $8,395 million were $5,063 million higher than the $3,332 million incurred during the third quarter of 2014.  Third quarter 2015 operating expenses included impairments of proved properties, other property, plant and equipment and other assets of $6,225 million related to commodity price declines. The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended September 30, 2015 and 2014:
 
Three Months Ended 
 September 30,
 
2015
 
2014
Lease and Well
$
5.40

 
$
6.53

Transportation Costs
3.88

 
4.36

Depreciation, Depletion and Amortization (DD&A) -
 
 
 
Oil and Gas Properties
13.16

 
17.91

Other Property, Plant and Equipment
0.61

 
0.53

General and Administrative (G&A)
1.73

 
1.72

Interest Expense, Net
1.15

 
0.88

Total (1)
$
25.93

 
$
31.93

 
(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, 2015, compared to the same period of 2014 are set forth below. See "Net Operating Revenues" above for a discussion of production volumes.

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 $283 million for the third quarter of 2015 decreased $85 million from $368 million for the same prior year period primarily due to lower lease and well expenses in Canada ($27 million) due to the divestiture of substantially all of EOG's operations in Canada during the fourth quarter of 2014, decreased operating and maintenance costs in the United States ($53 million) and decreased workover expenditures in the United States ($8 million).

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 $204 million for the third quarter of 2015 decreased $42 million from $246 million for the same prior year period primarily due to decreased transportation costs in the Rocky Mountain area ($26 million) and the Eagle Ford ($10 million) as a result of an increase in the use of pipelines to transport crude oil production and decreased transportation costs related to lower production from the Fort Worth Basin Barnett Shale area ($7 million).


-24-

        



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 2015 decreased $318 million to $722 million from $1,040 million for the same prior year period. DD&A expenses associated with oil and gas properties for the third quarter of 2015 were $320 million lower than the same prior year period. The decrease primarily reflects decreased rates in the United States ($231 million) and Trinidad ($9 million), decreased production in the United States ($52 million) and lower DD&A expenses in Canada ($29 million) due to the divestiture of substantially all of EOG's operations in Canada during the fourth quarter of 2014. Unit rates in the United States decreased primarily due to impairments of proved properties. See Note 11 to the Consolidated Financial Statements.

Exploration costs of $31 million for the third quarter of 2015 decreased $18 million from $49 million for the same prior year period primarily due to decreased geological and geophysical costs in the United States ($11 million) and lower exploration costs in Canada ($2 million) due to the divestiture of substantially all of EOG's operations in Canada during the fourth quarter of 2014.

Interest expense, net, of $61 million for the third quarter of 2015 increased $11 million compared to the same prior year period primarily due to increased debt outstanding ($5 million) and decreased capitalized interest ($5 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 decreased $7 million to $35 million for the third quarter of 2015 compared to $42 million for the same prior year period. The decrease primarily reflects decreased operating expenses in the Eagle Ford ($11 million), partially offset by increased activities in the Permian Basin ($6 million).

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 $6,307 million for the third quarter of 2015 were $6,252 million higher than impairments for the same prior year period primarily due to increased impairments of proved properties and related assets in the United States ($6,072 million) and in the United Kingdom ($142 million), primarily with respect to the Conwy project, and increased amortization of unproved property costs in the United States ($25 million), which was caused by higher amortization rates being applied to undeveloped leasehold costs in response to the significant decrease in commodity prices and an increase in EOG's estimates of undeveloped properties not expected to be developed before lease expiration. Proved property and related asset impairments in the United States were related to legacy natural gas assets and marginal liquids plays. EOG recorded impairments of proved properties, other property, plant and equipment and other assets of $6,225 million and $10 million for the third quarter of 2015 and 2014, respectively.

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 2015 decreased $99 million to $106 million (6.8% of wellhead revenues) compared to $205 million (6.1% of wellhead revenues) for the same prior year period. The decrease in taxes other than income was primarily due to decreases in severance/production taxes ($93 million), primarily as a result of decreased wellhead revenues, and in ad valorem/property taxes ($9 million), both in the United States, partially offset by a decrease in credits available to EOG in the third quarter of 2015 for Texas high-cost gas severance tax rate reductions ($6 million).

Other income (expense), net for the third quarter of 2015 increased $30 million compared to the same prior year period primarily due to a decrease in foreign currency exchange losses.

-25-

        




EOG recognized an income tax benefit of $2,199 million for the third quarter of 2015 compared to an income tax expense of $612 million in the third quarter of 2014 primarily due to 2015 impairments in the United States. The effective tax rate for the third quarter of 2015 was 35% compared to the prior year rate of 36%.

Nine Months Ended September 30, 2015 vs. Nine Months Ended September 30, 2014

Net Operating Revenues. During the first nine months of 2015, net operating revenues decreased $6,429 million, or 48%, to $6,961 million from $13,390 million for the same period of 2014. Total wellhead revenues for the first nine months of 2015 decreased $4,901 million, or 49%, to $5,049 million from $9,950 million for the same period of 2014. During the first nine months of 2015, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $57 million compared to net gains of $84 million for the same period of 2014. Gathering, processing and marketing revenues for the first nine months of 2015 decreased $1,419 million, or 44%, to $1,821 million from $3,240 million for the same period of 2014.

    

-26-

        



Wellhead volume and price statistics for the nine-month periods ended September 30, 2015 and 2014 were as follows:
 
Nine Months Ended 
 September 30,
 
2015
 
 
2014
Crude Oil and Condensate Volumes (MBbld)
 
 
 
 
United States
284.4

 
 
275.5

Trinidad
0.9

 
 
1.0

Other International
0.2

 
 
6.1

Total
285.5

 
 
282.6

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

 
 
 

United States
$
49.94

 
 
$
100.10

Trinidad
41.98

 
 
90.84

Other International
58.44

 
 
90.74

Composite
49.92

 
 
99.87

Natural Gas Liquids Volumes (MBbld)
 
 
 
 

United States
76.2

 
 
78.4

Other International
0.1

 
 
0.7

Total
76.3

 
 
79.1

Average Natural Gas Liquids Prices ($/Bbl)
 

 
 
 

United States
$
14.94

 
 
$
34.83

Other International
6.05

 
 
43.01

Composite
14.93

 
 
34.90

Natural Gas Volumes (MMcfd)
 
 
 
 

United States
895

 
 
920

Trinidad
342

 
 
374

Other International
31

 
 
74

Total
1,268

 
 
1,368

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

 
 
 

United States
$
2.14

 
 
$
4.17

Trinidad
3.01

 
 
3.61

Other International
4.63

(2)
 
4.56

Composite
2.44

 
 
4.04

Crude Oil Equivalent Volumes (MBoed)
 
 
 
 

United States
509.8

 
 
507.3

Trinidad
57.9

 
 
63.4

Other International
5.4

 
 
19.0

Total
573.1

 
 
589.7

Total MMBoe
156.5

 
 
161.0

 
(1)    Excludes the impact of financial commodity derivative instruments.
(2)
Includes revenue adjustment of $1.19 per Mcf related to a price adjustment for natural gas sales made in China during the period June 2012 through March 2015.

-27-

        



Wellhead crude oil and condensate revenues for the first nine months of 2015 decreased $3,794 million, or 49%, to $3,894 million from $7,688 million for the same period of 2014 due primarily to a lower composite wellhead crude oil and condensate price. EOG's composite wellhead crude oil and condensate price for the first nine months of 2015 decreased 50% to $49.92 per barrel compared to $99.87 per barrel for the same period of 2014.

NGL revenues for the first nine months of 2015 decreased $442 million, or 59%, to $311 million from $753 million for the same period of 2014 due primarily to a lower composite average price. EOG's composite NGL price for the first nine months of 2015 decreased 57% to $14.93 per barrel compared to $34.90 per barrel for the same period of 2014.

Wellhead natural gas revenues for the first nine months of 2015 decreased $665 million, or 44%, to $844 million from $1,509 million for the same period of 2014 primarily due to a lower composite wellhead natural gas price ($555 million) and a decrease of 100 MMcfd, or 7%, in natural gas deliveries ($110 million) primarily due to lower production in Other International (43 MMcfd) as a result of the divestiture of substantially all of EOG's Canadian operations in the fourth quarter of 2014, in Trinidad (32 MMcfd) and in the United States (25 MMcfd). EOG's composite wellhead natural gas price for the first nine months of 2015 decreased 40% to $2.44 per Mcf compared to $4.04 per Mcf for the same period of 2014.

During the first nine months of 2015, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $57 million compared to net gains of $84 million for the same period of 2014. During the first nine months of 2015, net cash received from settlements of crude oil and natural gas financial derivative contracts was $661 million and net cash payments for settlements of crude oil and natural gas financial derivative contracts were $189 million for the same period of 2014.

Gathering, processing and marketing revenues less marketing costs for the first nine months of 2015 declined $80 million as compared to the same period of 2014 primarily due to lower margins on crude oil and natural gas marketing activities and losses on sand sales.

Operating and Other Expenses. For the first nine months of 2015, operating expenses of $13,317 million were $3,942 million higher than the $9,375 million incurred during the same period of 2014. Operating expenses for the first nine months of 2015 included impairments of proved properties, other property, plant and equipment and other assets of $6,230 million related to commodity price declines. The following table presents the costs per Boe for the nine-month periods ended September 30, 2015 and 2014:
 
Nine Months Ended 
 September 30,
 
2015
 
2014
Lease and Well
$
5.97

 
$
6.44

Transportation Costs
4.10

 
4.54

DD&A -
 
 
 
Oil and Gas Properties
15.64

 
18.02

Other Property, Plant and Equipment
0.61

 
0.53

G&A
1.65

 
1.68

Interest Expense, Net
1.11

 
0.94

Total (1)
$
29.08

 
$
32.15

 
(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, 2015, compared to the same period of 2014 are set forth below. See "Net Operating Revenues" above for a discussion of production volumes.

Lease and well expenses of $934 million for the first nine months of 2015 decreased $102 million from $1,036 million for the same prior year period primarily due to lower lease and well expenses in Canada ($77 million) due to the divestiture of substantially all of EOG's operations in Canada during the fourth quarter of 2014, decreased operating and maintenance costs in the United States ($35 million) and decreased workover expenditures in the United States ($8 million), partially offset by increased lease and well administrative expenses in the United States ($21 million) primarily due to increased employee-related costs.


-28-

        



Transportation costs of $642 million for the first nine months of 2015 decreased $88 million from $730 million for the same prior year period primarily due to decreased transportation costs in the Rocky Mountain area ($65 million) and the Eagle Ford ($35 million) primarily due to an increase in the use of pipelines to transport crude oil production, partially offset by increased transportation costs related to higher production from the Permian Basin ($17 million).

DD&A expenses for the first nine months of 2015 decreased $439 million to $2,544 million from $2,983 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first nine months of 2015 were $449 million lower than the same prior year period. The decrease primarily reflects decreased rates in the United States ($335 million) and Trinidad ($23 million), lower DD&A expenses in Canada ($100 million) due to the divestiture of substantially all of EOG's operations in Canada during the fourth quarter of 2014 and lower volumes in Trinidad ($12 million), partially offset by higher volumes in the United States ($18 million). Unit rates in the United States decreased primarily due to impairments of proved properties (see Note 11 to the Consolidated Financial Statements), upward reserve revisions and reserves added at lower costs as a result of increased efficiencies.

Exploration costs of $115 million for the first nine months of 2015 decreased $24 million from $139 million for the same prior year period primarily due to decreased geological and geophysical costs in the United States ($16 million) and lower exploration costs in Canada ($9 million) due to the divestiture of substantially all of EOG's operations in Canada during the fourth quarter of 2014, partially offset by increased exploration administrative expenses ($4 million) in the United States.

G&A expenses of $258 million for the first nine months of 2015 decreased $13 million from $271 million for the same prior year period primarily due to decreased employee-related costs ($5 million) and decreased professional service fees ($4 million).

Interest expense, net, of $174 million for the first nine months of 2015 increased $23 million compared to the same prior year period primarily due to increased debt outstanding ($15 million) and decreased capitalized interest ($10 million).

Impairments of $6,445 million for the first nine months of 2015 were $6,237 million higher than impairments for the same prior year period primarily due to increased impairments of proved properties and related assets in the United States ($6,007 million) and in the United Kingdom ($142 million), primarily with respect to the Conwy project, and increased amortization of unproved property costs in the United States ($84 million), which was caused by higher amortization rates being applied to undeveloped leasehold costs in response to the significant decrease in commodity prices and an increase in EOG's estimates of undeveloped properties not expected to be developed before lease expiration. Proved property and related asset impairments in the United States were related to legacy natural gas assets and marginal liquids plays. EOG recorded impairments of proved properties, other property, plant and equipment and other assets of $6,230 million and $84 million for the first nine months of 2015 and 2014, respectively.

Taxes other than income for the first nine months of 2015 decreased $272 million to $334 million (6.6% of wellhead revenues) from $606 million (6.1% of wellhead revenues) for the same prior year period. The decrease in taxes other than income was primarily due to decreased severance/production taxes in the United States ($247 million) primarily as a result of decreased wellhead revenues, decreased ad valorem/property taxes in the United States ($8 million), an increase in credits available to EOG in 2015 for Texas high-cost gas severance tax rate reductions ($7 million) and decreased severance/production taxes in Trinidad ($5 million).

Other income (expense), net for the first nine months of 2015 increased $25 million compared to the same prior year period. The increase was primarily due to decreased deferred compensation expense ($10 million) and a decrease in foreign currency exchange losses ($5 million).

EOG recognized an income tax benefit of $2,283 million for the first nine months of 2015 compared to an income tax expense of $1,376 million for the same period in 2014 primarily due to certain 2015 impairments in the United States. The net effective tax rate for the first nine months of 2015 was 35% compared to the prior year rate of 36%.





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Capital Resources and Liquidity

Cash Flow. The primary sources of cash for EOG during the nine months ended September 30, 2015, were funds generated from operations, net proceeds from the issuance of the Notes and proceeds from asset sales. The primary uses of cash were funds used in operations; exploration and development expenditures; repayments of debt; other property, plant and equipment expenditures; dividend payments to stockholders; and purchases of treasury stock in connection with stock compensation plans. During the first nine months of 2015, EOG's cash balance decreased $1,344 million to $743 million from $2,087 million at December 31, 2014.

Net cash provided by operating activities of $2,979 million for the first nine months of 2015 decreased $3,559 million compared to the same period of 2014 primarily due to a decrease in wellhead revenues ($4,901 million), unfavorable changes in working capital and other assets and liabilities ($202 million) and an increase in net cash paid for interest expense ($9 million), partially offset by a favorable change in net cash flow from the settlement of financial commodity derivative contracts ($850 million), a decrease in cash operating expenses ($492 million) and a decrease in net cash paid for income taxes ($261 million).

Net cash used in investing activities of $4,545 million for the first nine months of 2015 decreased by $1,586 million compared to the same period of 2014 due primarily to a decrease in additions to oil and gas properties ($1,735 million); a decrease in additions to other property, plant and equipment ($335 million); a decrease in restricted cash ($91 million); and an increase in proceeds from sales of assets ($53 million); partially offset by unfavorable changes in working capital associated with investing activities ($628 million).

Net cash provided by financing activities of $231 million for the first nine months of 2015 included net proceeds from the issuance of the Notes ($990 million), net commercial paper borrowings ($30 million), excess tax benefits from stock-based compensation ($24 million) and proceeds from stock options exercised and employee stock purchase plan activity ($15 million). Cash used in financing activities for the first nine months of 2015 included repayments of long-term debt ($500 million), cash dividend payments ($275 million) and purchases of treasury stock in connection with stock compensation plans ($43 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 issuances of long-term debt ($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).

Total Expenditures. For the year 2015, EOG's budget for exploration and development and other property, plant and equipment expenditures is approximately $4.7 billion to $4.9 billion, excluding acquisitions. The table below sets out components of total expenditures for the nine-month periods ended September 30, 2015 and 2014 (in millions):
 
Nine Months Ended 
 September 30,
 
2015
 
2014
Expenditure Category
 
 
 
Capital
 
 
 
Drilling and Facilities
$
3,384

 
$
5,191

Leasehold Acquisitions
111

 
321

Property Acquisitions
376

 
73

Capitalized Interest
33

 
43

Subtotal
3,904

 
5,628

Exploration Costs
115

 
139

Dry Hole Costs
14

 
30

Exploration and Development Expenditures
4,033

 
5,797

Asset Retirement Costs
26

 
170

Total Exploration and Development Expenditures
4,059

 
5,967

Other Property, Plant and Equipment
253

 
587

Total Expenditures
$
4,312

 
$
6,554



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Exploration and development expenditures of $4,033 million for the first nine months of 2015 were $1,764 million lower than the same period of 2014 primarily due to decreased drilling and facilities expenditures in the United States ($1,768 million), Canada ($64 million) and the United Kingdom ($28 million); decreased leasehold acquisitions ($210 million) and decreased geological and geophysical expenditures ($16 million); partially offset by increased property acquisitions in the United States ($303 million) and increased drilling and facilities expenditures in Trinidad ($55 million). Exploration and development expenditures for the first nine months of 2015 of $4,033 million consist of $3,339 million in development, $376 million in property acquisitions, $285 million in exploration and $33 million in capitalized interest. 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 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 12 to the Consolidated Financial Statements included in EOG's Annual Report on Form 10-K for the year ended December 31, 2014, filed on February 18, 2015, 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 (Loss) and Comprehensive Income (Loss). The related cash flow impact is reflected in Cash Flows from Operating Activities.

Commodity Derivative Contracts. The total fair value of EOG's crude oil and natural gas price swap contracts was reflected on the Consolidated Balance Sheets at September 30, 2015, as a net asset of $71 million. Presented below is a comprehensive summary of EOG's crude oil price swap contracts at November 5, 2015, with notional volumes expressed in barrels per day (Bbld) and prices expressed in dollars per barrel ($/Bbl).

Crude Oil Price Swap Contracts
 
 
Volume
(Bbld)
 
Weighted
Average Price
($/Bbl)
2015
 
 
 
 
January 1, 2015 through June 30, 2015 (closed)
 
47,000

 
$
91.22

July 1, 2015 through October 31, 2015 (closed)
 
10,000

 
89.98

November 1, 2015 through December 31, 2015
 
10,000

 
89.98



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EOG has purchased put options which establish a floor price for the sale of certain notional volumes of crude oil specified in the put option contracts. The put options grant EOG the right to receive the difference between the put option strike price and the average NYMEX West Texas Intermediate crude oil price for the contract month (Index Price), in the event the Index Price is below the put option strike price. If the Index Price is above the put option strike price, EOG is only required to pay the put option premium. Below is a summary of EOG's put option contracts at November 5, 2015, with notional volumes expressed in Bbld and prices and premiums expressed in $/Bbl.
Crude Oil Put Option Contracts
 
 
Volume
(Bbld)
 
Average
Premium
($/Bbl)
 
Strike
Price
($/Bbl)
2015
 
 
 
 
 
 
September 1, 2015 through October 31, 2015 (closed)
 
82,500

 
$
1.75

 
$
45.00

November 2015
 
82,500

 
1.75

 
45.00


Presented below is a comprehensive summary of EOG's natural gas price swap contracts at November 5, 2015, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).

Natural Gas Price Swap Contracts
 
 
Volume (MMBtud)
 
Weighted
Average Price
($/MMBtu)
2015 (1)
 
 
 
 
January 1, 2015 through February 28, 2015 (closed)
 
235,000

 
$
4.47

March 2015 (closed)
 
225,000

 
4.48

April 2015 (closed)
 
195,000

 
4.49

May 2015 (closed)
 
235,000

 
4.13

June 1, 2015 through July 31, 2015 (closed)
 
275,000

 
3.98

August 1, 2015 through November 30, 2015 (closed)
 
175,000

 
4.51

December 2015
 
175,000

 
4.51

 
(1)
EOG has entered into natural gas price swap contracts which give counterparties the option of entering into price swap 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 price swap contracts will increase by 175,000 MMBtud at an average price of $4.51 per MMBtu for the month of December 2015.



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Information Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production and costs, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, generate income or cash flows or pay dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:

the timing, extent and duration of changes in prices for, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities;
the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
the extent to which EOG is successful in its efforts to economically develop its acreage in, produce reserves and achieve anticipated production levels from, and optimize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects;
the extent to which EOG is successful in its efforts to market its crude oil, natural gas and related commodity production;
the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, transportation and refining facilities;
the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights-of-way, and EOG's ability to retain mineral licenses and leases;
the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations; environmental, health and safety laws and regulations relating to air emissions, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;
EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties;
the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully and economically;
competition in the oil and gas exploration and production industry for employees and other personnel, facilities, equipment, materials and services;
the availability and cost of employees and other personnel, facilities, equipment, materials (such as water) and services;
the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression and transportation facilities;
the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;
the extent and effect of any hedging activities engaged in by EOG;
the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
political conditions and developments around the world (such as political instability and armed conflict), including in the areas in which EOG operates;
the use of competing energy sources and the development of alternative energy sources;
the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;
acts of war and terrorism and responses to these acts;
physical, electronic and cyber security breaches; and

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the other factors described under ITEM 1A, Risk Factors, on pages 13 through 20 of EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014, and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

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


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PART I.  FINANCIAL INFORMATION


ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
EOG RESOURCES, INC.

EOG's exposure to commodity price risk, interest rate risk and foreign currency exchange rate risk is discussed in (i) the "Derivative Transactions," "Financing," "Foreign Currency Exchange Rate Risk" and "Outlook" sections of "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity" on pages 39 through 41 of EOG's Annual Report on Form 10-K for the year ended December 31, 2014, filed on February 18, 2015 (EOG's 2014 Annual Report); and (ii) Note 12, "Risk Management Activities," to EOG's Consolidated Financial Statements on pages F-26 through F-28 of EOG's 2014 Annual Report. There have been no material changes in this information. For additional information regarding EOG's financial commodity derivative contracts and physical commodity contracts, see (i) Note 12, "Risk Management Activities," to EOG's Consolidated Financial Statements in this Quarterly Report on Form 10-Q; (ii) "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Net Operating Revenues" in this Quarterly Report on Form 10-Q; and (iii) "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Commodity Derivative Transactions" in this Quarterly Report on Form 10-Q.


ITEM 4. CONTROLS AND PROCEDURES
EOG RESOURCES, INC.


Disclosure Controls and Procedures. EOG's management, with the participation of EOG's principal executive officer and principal financial officer, evaluated the effectiveness of EOG's disclosure