10-Q 1 a2017063010-q.htm 10-Q Document
 

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 June 30, 2017
or
o            TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number: 1-9743
image00001aa07.jpg 
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, a smaller reporting company, or an emerging growth company.  See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer ý    Accelerated filer o    Non-accelerated filer o (Do not check if a smaller reporting company)
Smaller reporting company o   Emerging growth company o
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 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
 
577,448,119 (as of July 25, 2017)

 

        



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.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
(In Thousands, Except Per Share Data)
(Unaudited)
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2017
 
2016
 
2017
 
2016
Net Operating Revenues and Other
 
 
 
 
 
 
 
Crude Oil and Condensate
$
1,445,454

 
$
1,059,690

 
$
2,875,515

 
$
1,813,401

Natural Gas Liquids
146,907

 
111,643

 
300,351

 
186,962

Natural Gas
224,008

 
155,983

 
454,610

 
321,486

Gains (Losses) on Mark-to-Market Commodity Derivative Contracts
9,446

 
(44,373
)
 
71,466

 
(38,938
)
Gathering, Processing and Marketing
778,797

 
485,256

 
1,505,334

 
819,209

Losses on Asset Dispositions, Net
(8,916
)
 
(15,550
)
 
(25,674
)
 
(6,403
)
Other, Net
16,776

 
23,091

 
41,435

 
34,372

Total
2,612,472

 
1,775,740

 
5,223,037

 
3,130,089

Operating Expenses
 

 
 

 
 

 
 

Lease and Well
255,186

 
218,393

 
510,963

 
459,258

Transportation Costs
186,356

 
179,471

 
365,070

 
369,925

Gathering and Processing Costs
34,746

 
29,226

 
72,890

 
57,750

Exploration Costs
34,711

 
30,559

 
91,605

 
60,388

Dry Hole Costs
27

 
(172
)
 
27

 
74

Impairments
78,934

 
72,714

 
272,121

 
144,331

Marketing Costs
790,599

 
480,046

 
1,527,135

 
820,900

Depreciation, Depletion and Amortization
865,384

 
862,491

 
1,681,420

 
1,791,382

General and Administrative
108,507

 
97,705

 
205,745

 
198,236

Taxes Other Than Income
130,114

 
93,480

 
260,407

 
154,159

Total
2,484,564

 
2,063,913

 
4,987,383

 
4,056,403

Operating Income (Loss)
127,908

 
(288,173
)
 
235,654

 
(926,314
)
Other Income (Expense), Net
4,972

 
(20,996
)
 
8,123

 
(25,433
)
Income (Loss) Before Interest Expense and Income Taxes
132,880

 
(309,169
)
 
243,777

 
(951,747
)
Interest Expense, Net
70,413

 
71,108

 
141,928

 
139,498

Income (Loss) Before Income Taxes
62,467

 
(380,277
)
 
101,849

 
(1,091,245
)
Income Tax Provision (Benefit)
39,414

 
(87,719
)
 
50,279

 
(326,911
)
Net Income (Loss)
$
23,053

 
$
(292,558
)
 
$
51,570

 
$
(764,334
)
Net Income (Loss) Per Share
 

 
 

 
 

 
 

Basic
$
0.04

 
$
(0.53
)
 
$
0.09

 
$
(1.40
)
Diluted
$
0.04

 
$
(0.53
)
 
$
0.09

 
$
(1.40
)
Dividends Declared per Common Share
$
0.1675

 
$
0.1675

 
$
0.3350

 
$
0.3350

Average Number of Common Shares
 

 
 

 
 

 
 

Basic
574,439

 
547,335

 
574,162

 
547,029

Diluted
578,483

 
547,335

 
578,573

 
547,029

Comprehensive Income (Loss)
 

 
 

 
 

 
 

Net Income (Loss)
$
23,053

 
$
(292,558
)
 
$
51,570

 
$
(764,334
)
Other Comprehensive Income
 

 
 

 
 

 
 

Foreign Currency Translation Adjustments
1,260

 
5,844

 
1,569

 
8,029

Other, Net of Tax
(86
)
 
23

 
(49
)
 
45

Other Comprehensive Income
1,174

 
5,867

 
1,520

 
8,074

Comprehensive Income (Loss)
$
24,227

 
$
(286,691
)
 
$
53,090

 
$
(756,260
)


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

-3-

        



EOG RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share Data)
(Unaudited)
 
June 30,
2017
 
December 31,
2016
ASSETS
Current Assets
 
 
 
Cash and Cash Equivalents
$
1,649,443

 
$
1,599,895

Accounts Receivable, Net
1,114,454

 
1,216,320

Inventories
336,198

 
350,017

Assets from Price Risk Management Activities
4,746

 

Income Taxes Receivable
91,256

 
12,305

Other
187,276

 
206,679

Total
3,383,373

 
3,385,216

Property, Plant and Equipment
 

 
 

Oil and Gas Properties (Successful Efforts Method)
50,973,760

 
49,592,091

Other Property, Plant and Equipment
3,883,759

 
4,008,564

Total Property, Plant and Equipment
54,857,519

 
53,600,655

Less:  Accumulated Depreciation, Depletion and Amortization
(29,277,359
)
 
(27,893,577
)
Total Property, Plant and Equipment, Net
25,580,160

 
25,707,078

Deferred Income Taxes
16,888

 
16,140

Other Assets
283,196

 
190,767

Total Assets
$
29,263,617

 
$
29,299,201

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
 

 
 

Accounts Payable
$
1,615,170

 
$
1,511,826

Accrued Taxes Payable
155,458

 
118,411

Dividends Payable
96,145

 
96,120

Liabilities from Price Risk Management Activities

 
61,817

Current Portion of Long-Term Debt
606,454

 
6,579

Other
249,027

 
232,538

Total
2,722,254

 
2,027,291

 
 
 
 
Long-Term Debt
6,380,350

 
6,979,779

Other Liabilities
1,199,778

 
1,282,142

Deferred Income Taxes
5,059,520

 
5,028,408

Commitments and Contingencies (Note 8)


 


 
 
 
 
Stockholders' Equity
 

 
 

Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized at June 30, 2017, 640,000,000 Shares Authorized at December 31, 2016, 577,711,399 Shares Issued at June 30, 2017 and 576,950,272 Shares Issued at December 31, 2016
205,777

 
205,770

Additional Paid in Capital
5,485,832

 
5,420,385

Accumulated Other Comprehensive Loss
(17,490
)
 
(19,010
)
Retained Earnings
8,256,359

 
8,398,118

Common Stock Held in Treasury, 316,339 Shares at June 30, 2017 and 250,155 Shares at December 31, 2016
(28,763
)
 
(23,682
)
Total Stockholders' Equity
13,901,715

 
13,981,581

Total Liabilities and Stockholders' Equity
$
29,263,617

 
$
29,299,201


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

-4-


EOG RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)
 
Six Months Ended 
 June 30,
 
2017
 
2016
Cash Flows from Operating Activities
 
 
 
Reconciliation of Net Income (Loss) to Net Cash Provided by Operating Activities:
 
 
 
Net Income (Loss)
$
51,570

 
$
(764,334
)
Items Not Requiring (Providing) Cash
 

 
 

Depreciation, Depletion and Amortization
1,681,420

 
1,791,382

Impairments
272,121

 
144,331

Stock-Based Compensation Expenses
58,061

 
59,471

Deferred Income Taxes
35,162

 
(384,294
)
Losses on Asset Dispositions, Net
25,674

 
6,403

Other, Net
(6,691
)
 
29,991

Dry Hole Costs
27

 
74

Mark-to-Market Commodity Derivative Contracts
 

 
 

Total (Gains) Losses
(71,466
)
 
38,938

Net Cash Received from Settlements of Commodity Derivative Contracts
2,591

 
2,852

Excess Tax Benefits from Stock-Based Compensation

 
(11,811
)
Other, Net
(185
)
 
5,008

Changes in Components of Working Capital and Other Assets and Liabilities
 

 
 

Accounts Receivable
103,786

 
(22,572
)
Inventories
(6,129
)
 
95,813

Accounts Payable
76,704

 
(203,358
)
Accrued Taxes Payable
(39,124
)
 
93,320

Other Assets
(61,089
)
 
(33,589
)
Other Liabilities
(66,869
)
 
1,565

Changes in Components of Working Capital Associated with Investing and Financing Activities
(79,138
)
 
(54,453
)
Net Cash Provided by Operating Activities
1,976,425

 
794,737

Investing Cash Flows
 

 
 

Additions to Oil and Gas Properties
(1,885,417
)
 
(1,143,549
)
Additions to Other Property, Plant and Equipment
(88,076
)
 
(44,584
)
Proceeds from Sales of Assets
175,260

 
252,529

Changes in Components of Working Capital Associated with Investing Activities
79,138

 
54,477

Net Cash Used in Investing Activities
(1,719,095
)
 
(881,127
)
Financing Cash Flows
 

 
 

Net Commercial Paper Repayments

 
(259,718
)
Long-Term Debt Borrowings

 
991,097

Long-Term Debt Repayments

 
(400,000
)
Dividends Paid
(192,984
)
 
(184,036
)
Excess Tax Benefits from Stock-Based Compensation

 
11,811

Treasury Stock Purchased
(21,678
)
 
(28,755
)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan
9,608

 
10,624

Debt Issuance Costs

 
(1,602
)
Repayment of Capital Lease Obligation
(3,251
)
 
(3,150
)
Other, Net

 
(24
)
Net Cash (Used in) Provided by Financing Activities
(208,305
)
 
136,247

Effect of Exchange Rate Changes on Cash
523

 
11,359

Increase in Cash and Cash Equivalents
49,548

 
61,216

Cash and Cash Equivalents at Beginning of Period
1,599,895

 
718,506

Cash and Cash Equivalents at End of Period
$
1,649,443

 
$
779,722


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

-5-

        



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

1.    Summary of Significant Accounting Policies

General. The condensed 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 condensed 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, 2016, filed on February 27, 2017 (EOG's 2016 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 six months ended June 30, 2017, are not necessarily indicative of the results to be expected for the full year.

Effective January 1, 2017, EOG adopted the provisions of Accounting Standards Update (ASU) 2016-09, "Improvements to Employee Share-Based Payment Accounting" (ASU 2016-09), which amends certain aspects of accounting for share-based payment arrangements. ASU 2016-09 revises or provides alternative accounting for the tax impacts of share-based payment arrangements, forfeitures and minimum statutory tax withholdings and prescribes certain disclosures to be made in the period the new standard is adopted. There was no impact to retained earnings with respect to excess tax benefits. EOG began recognizing all excess tax benefits and tax deficiencies as income tax provision or benefit as discrete events. Net excess tax benefits recognized within income tax provision was $12 million for the six months ended June 30, 2017. The treatment of forfeitures did not change as EOG elected to continue the current process of estimating the number of forfeitures. As such, this had no cumulative effect on retained earnings. EOG elected to present changes to the statements of cash flows on a prospective transition method.

Effective January 1, 2017, EOG adopted the provisions of ASU 2015-17, "Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes" (ASU 2015-17), which simplifies the presentation of deferred taxes in a classified balance sheet by eliminating the requirement to separate deferred income tax liabilities and assets into current and noncurrent amounts. Instead, ASU 2015-17 requires that all deferred tax liabilities and assets be shown as noncurrent in a classified balance sheet. In connection with the adoption of ASU 2015-17, EOG restated its December 31, 2016 balance sheet to reclassify $169 million of current deferred income tax assets as noncurrent.

Recently Issued Accounting Standards. In February 2017, the Financial Accounting Standards Board (FASB) issued ASU 2017-05, “Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20) - Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets” (ASU 2017-05). ASU 2017-05 clarifies the scope and application of Accounting Standards Codification (ASC) 610-20 to the sale or transfer of nonfinancial assets and, in substance, nonfinancial assets to noncustomers, including partial sales. ASU 2017-05 is effective for interim and annual periods beginning after December 15, 2017, and early adoption is permitted, at the same time of adoption of ASU 2014-09, “Revenue From Contracts With Customers” (ASU 2014-09). EOG does not intend to early adopt ASU 2017-05. EOG is reviewing the provisions of ASU 2017-05 in connection with the adoption of ASU 2014-09 to determine its impact on its consolidated financial statements and related disclosures.

In January 2017, the FASB issued ASU 2017-01, "Business Combinations (Topic 805): Clarifying the Definition of a Business" (ASU 2017-01), which clarifies the definition of a business to provide guidance in evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 provides a screen to determine when a set of assets is not a business, requiring that when substantially all fair value of gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets, the set of assets is not a business. A framework is provided to assist in evaluating whether both an input and a substantive process are present for the set to be a business. ASU 2017-01 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. No disclosures are required at transition and early adoption is permitted. EOG is evaluating ASU 2017-01 to determine the impact on its consolidated financial statements and related disclosures.

-6-

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



In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230) - Classification of Certain Cash Receipts and Cash Payments” (ASU 2016-15).  ASU 2016-15 reduces existing diversity in practice by providing guidance on the classification of eight specific cash receipts and cash payments transactions in the statement of cash flows.  The new standard is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years, and is required to be adopted using a retrospective approach, if practicable.  Early adoption is permitted.  EOG does not expect the adoption of the new standard to have a material impact on its consolidated financial statements and related disclosures.
  
In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" (ASU 2016-02), which significantly changes accounting for leases by requiring that lessees recognize a right-of-use asset and a related lease liability representing the obligation to make lease payments, for virtually all lease transactions. Additional disclosures about an entity's lease transactions will also be required. ASU 2016-02 defines a lease as "a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment (an identified asset) for a period of time in exchange for consideration." ASU 2016-02 is effective for interim and annual periods beginning after December 31, 2018 and early adoption is permitted. Lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented in the financial statements using a modified retrospective approach. EOG is reviewing the provisions of ASU 2016-02 to determine the impact on its consolidated financial statements and related disclosures.

In May 2014, the FASB issued ASU 2014-09, which will require entities to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will supersede most current guidance related to revenue recognition when it becomes effective. The new standard also will require expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. ASU 2014-09 is effective for interim and annual reporting periods beginning after December 15, 2017, and early adoption is permitted.  The new standard permits adoption through the use of either the full retrospective approach or a modified retrospective approach.  In May 2016, the FASB issued ASU 2016-11, which rescinds certain SEC guidance in the related ASC, including guidance related to the use of the "entitlements" method of revenue recognition used by EOG. EOG will adopt ASU 2014-09 utilizing the modified retrospective approach with a cumulative adjustment to retained earnings on January 1, 2018. Based on its current assessments to-date, EOG does not anticipate the provisions of ASU 2014-09 will have a material impact on EOG's consolidated financial statements and related disclosures. EOG continues to analyze ASU 2014-09 in order to finalize implementation and determine the impact on EOG's financial statements and related disclosures.

2.    Stock-Based Compensation

As more fully discussed in Note 7 to the Consolidated Financial Statements included in EOG's 2016 Annual Report, EOG maintains various stock-based compensation plans. Stock-based compensation expense is included on the Condensed 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 
 June 30,
 
Six Months Ended 
 June 30,
 
2017
 
2016
 
2017
 
2016
Lease and Well
$
9.6

 
$
8.9

 
$
20.5

 
$
19.3

Gathering and Processing Costs
0.2

 
0.3

 
0.4

 
0.6

Exploration Costs
5.3

 
5.0

 
11.5

 
11.5

General and Administrative
12.5

 
12.9

 
25.7

 
28.1

Total
$
27.6

 
$
27.1

 
$
58.1

 
$
59.5


The Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (2008 Plan) provides for grants of stock options, stock-settled stock appreciation rights (SARs), restricted stock and restricted stock units, performance units and performance stock and other stock-based awards. At June 30, 2017, approximately 20.9 million common shares remained available for grant under the 2008 Plan. EOG's policy is to issue shares related to the 2008 Plan from previously authorized unissued shares or treasury shares to the extent treasury shares are available.


-7-

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


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 $11.1 million and $13.0 million during the three months ended June 30, 2017 and 2016, respectively, and $22.1 million and $26.2 million during the six months ended June 30, 2017 and 2016, respectively.

Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants during the six-month periods ended June 30, 2017 and 2016 are as follows:
 
Stock Options/SARs
 
ESPP
 
Six Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2017
 
2016
 
2017
 
2016
Weighted Average Fair Value of Grants
$
26.64

 
$
21.04

 
$
24.28

 
$
17.56

Expected Volatility
30.46
%
 
35.90
%
 
30.33
%
 
36.79
%
Risk-Free Interest Rate
1.39
%
 
0.93
%
 
0.65
%
 
0.49
%
Dividend Yield
0.68
%
 
0.91
%
 
0.69
%
 
0.82
%
Expected Life
5.3 years

 
5.3 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.

The following table sets forth stock option and SAR transactions for the six-month periods ended June 30, 2017 and 2016 (stock options and SARs in thousands):
 
Six Months Ended 
 June 30, 2017
 
Six Months Ended 
 June 30, 2016
 
Number of
Stock
Options/SARs
 
Weighted
Average
Grant
Price
 
Number of
Stock
Options/SARs
 
Weighted
Average
Grant
Price
Outstanding at January 1
9,850

 
$
75.53

 
10,744

 
$
67.98

Granted
16

 
96.41

 
11

 
71.51

Exercised (1)
(783
)
 
57.05

 
(790
)
 
44.31

Forfeited
(189
)
 
89.40

 
(150
)
 
85.91

Outstanding at June 30 (2)
8,894

 
$
76.90

 
9,815

 
$
69.61

Vested or Expected to Vest (3)
8,594

 
$
76.53

 
9,490

 
$
69.24

Exercisable at June 30 (4)
4,973

 
$
68.43

 
5,638

 
$
61.50


(1)
The total intrinsic value of stock options/SARs exercised for the six months ended June 30, 2017 and 2016 was $33.5 million and $26.8 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 June 30, 2017 and 2016 was $147.8 million and $173.1 million, respectively. At June 30, 2017 and 2016, the weighted average remaining contractual life was 3.6 years and 3.6 years, respectively.
(3)
The total intrinsic value of stock options/SARs vested or expected to vest at June 30, 2017 and 2016 was $145.7 million and $170.3 million, respectively. At June 30, 2017 and 2016, the weighted average remaining contractual life was 3.5 years and 3.6 years, respectively.
(4)
The total intrinsic value of stock options/SARs exercisable at June 30, 2017 and 2016 was $120.9 million and $137.7 million, respectively. At June 30, 2017 and 2016, the weighted average remaining contractual life was 2.2 years and 2.4 years, respectively.

At June 30, 2017, unrecognized compensation expense related to non-vested stock option, SAR and ESPP grants totaled $75.6 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.3 years.


-8-

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


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 $15.6 million and $13.7 million for the three months ended June 30, 2017 and 2016, respectively, and $34.2 million and $32.4 million for the six months ended June 30, 2017 and 2016, respectively.

The following table sets forth restricted stock and restricted stock unit transactions for the six-month periods ended June 30, 2017 and 2016 (shares and units in thousands):
 
Six Months Ended 
 June 30, 2017
 
Six Months Ended 
 June 30, 2016
 
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
3,962

 
$
79.63

 
4,908

 
$
70.35

Granted
437

 
98.97

 
306

 
75.56

Released (1)
(407
)
 
63.20

 
(798
)
 
61.36

Forfeited
(143
)
 
83.92

 
(203
)
 
76.97

Outstanding at June 30 (2)
3,849

 
$
83.40

 
4,213

 
$
72.11

 
(1)
The total intrinsic value of restricted stock and restricted stock units released for the six months ended June 30, 2017 and 2016 was $40.4 million and $60.8 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 June 30, 2017 and 2016 was $348.4 million and $351.5 million, respectively.

At June 30, 2017, unrecognized compensation expense related to restricted stock and restricted stock units totaled $151.1 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.5 years.

Performance Units and Performance Stock. EOG has granted performance units and/or performance stock (Performance Awards) to its executive officers annually since 2012. As more fully discussed in the grant agreements, the performance metric applicable to the Performance Awards is EOG's total shareholder return over a three-year performance period relative to the total shareholder return of a designated group of peer companies (Performance Period). Upon the application of the performance multiple at the completion of the Performance Period, a minimum of 0% and a maximum of 200% of the Performance Awards granted could be outstanding. Subject to the termination provisions set forth in the grant agreements and the applicable performance multiple, the grants of Performance Awards will generally "cliff" vest five years from the date of grant. The fair value of the Performance Awards is estimated using a Monte Carlo simulation.

At December 31, 2016, 545,290 Performance Awards were outstanding. Upon completion of the Performance Period for the Performance Awards granted in 2013, a performance multiple of 200% was applied to the 2013 grants resulting in an additional grant of 118,834 Performance Awards in February 2017. A total of 89,224 Performance Awards were released during the six months ended June 30, 2017, with a total intrinsic value of $9.0 million, based upon the closing price of EOG's common stock on the release date. Upon the application of the performance multiple at the completion of the remaining Performance Periods, a minimum of 299,540 and a maximum of 850,260 Performance Awards could be outstanding. There were 574,900 Performance Awards outstanding as of June 30, 2017. The total intrinsic value of Performance Awards outstanding at June 30, 2017 was $52.0 million.

Stock-based compensation expense related to the Performance Award grants totaled $0.9 million and $0.4 million for the three month periods ended June 30, 2017 and 2016, respectively, and $1.8 million and $0.9 million for the six months ended June 30, 2017 and 2016, respectively. At June 30, 2017, unrecognized compensation expense related to Performance Awards totaled $8.6 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.5 years.


-9-

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


3.    Net Income (Loss) Per Share

The following table sets forth the computation of Net Income (Loss) Per Share for the three-month and six-month periods ended June 30, 2017 and 2016 (in thousands, except per share data):
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2017
 
2016
 
2017
 
2016
Numerator for Basic and Diluted Earnings Per Share -
 
 
 
 
 
 
 
Net Income (Loss)
$
23,053

 
$
(292,558
)
 
$
51,570

 
$
(764,334
)
Denominator for Basic Earnings Per Share -
 

 
 

 
 

 
 

Weighted Average Shares
574,439

 
547,335

 
574,162

 
547,029

Potential Dilutive Common Shares -
 

 
 

 
 

 
 

Stock Options/SARs
1,452

 

 
1,669

 

Restricted Stock/Units and Performance Units/Stock
2,592

 

 
2,742

 

Denominator for Diluted Earnings Per Share -
 

 
 

 
 

 
 

Adjusted Diluted Weighted Average Shares
578,483

 
547,335

 
578,573

 
547,029

Net Income (Loss) Per Share
 

 
 

 
 

 
 

Basic
$
0.04

 
$
(0.53
)
 
$
0.09

 
$
(1.40
)
Diluted
$
0.04

 
$
(0.53
)
 
$
0.09

 
$
(1.40
)

The diluted earnings per share calculation excludes stock options, SARs, restricted stock and units and performance units that were anti-dilutive. Shares underlying the excluded stock options and SARs totaled 3.4 million and 10.2 million shares for the three months ended June 30, 2017 and 2016, respectively, and 2.0 million and 10.4 million shares for the six months ended June 30, 2017 and 2016, respectively. For both the three months and six months ended June 30, 2016, 4.6 million shares of restricted stock, restricted stock units and performance units were excluded.

4.    Supplemental Cash Flow Information

Net cash paid for interest and income taxes was as follows for the six-month periods ended June 30, 2017 and 2016 (in thousands):
 
Six Months Ended 
 June 30,
 
2017
 
2016
Interest (1)
$
136,733

 
$
118,120

Income Taxes, Net of Refunds Received
$
98,157

 
$
(10,997
)
 
(1)
Net of capitalized interest of $14 million and $17 million for the six months ended June 30, 2017 and 2016, respectively.

EOG's accrued capital expenditures at June 30, 2017 and 2016 were $488 million and $371 million, respectively.

Non-cash investing activities for the six months ended June 30, 2017, included non-cash additions of $154 million to EOG's oil and gas properties as a result of property exchanges.


-10-

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


5.    Segment Information

Selected financial information by reportable segment is presented below for the three-month and six-month periods ended June 30, 2017 and 2016 (in thousands):
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2017
 
2016
 
2017
 
2016
Net Operating Revenues and Other
 
 
 
 
 
 
 
United States
$
2,530,885

 
$
1,704,320

 
$
5,050,734

 
$
2,983,989

Trinidad
72,299

 
62,731

 
146,222

 
125,524

Other International (1)
9,288

 
8,689

 
26,081

 
20,576

Total
$
2,612,472

 
$
1,775,740

 
$
5,223,037

 
$
3,130,089

Operating Income (Loss)
 

 
 

 
 

 
 

United States
$
130,314

 
$
(280,593
)
 
$
249,845

 
$
(905,577
)
Trinidad
32,360

 
17,054

 
48,773

 
25,932

Other International (1)
(34,766
)
 
(24,634
)
 
(62,964
)
 
(46,669
)
Total
127,908

 
(288,173
)
 
235,654

 
(926,314
)
Reconciling Items
 

 
 

 
 

 
 

Other Income (Expense), Net
4,972

 
(20,996
)
 
8,123

 
(25,433
)
Interest Expense, Net
(70,413
)
 
(71,108
)
 
(141,928
)
 
(139,498
)
Income (Loss) Before Income Taxes
$
62,467

 
$
(380,277
)
 
$
101,849

 
$
(1,091,245
)
 
(1)
Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016.

Total assets by reportable segment are presented below at June 30, 2017 and December 31, 2016 (in thousands):
 
At
June 30,
2017
 
At
December 31,
2016
Total Assets
 
 
 
United States
$
27,676,982

 
$
27,746,851

Trinidad
947,166

 
889,253

Other International (1)
639,469

 
663,097

Total
$
29,263,617

 
$
29,299,201

 
(1)
Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016.


-11-

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


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 six-month periods ended June 30, 2017 and 2016 (in thousands):
 
Six Months Ended 
 June 30,
 
2017
 
2016
Carrying Amount at Beginning of Period
$
912,926

 
$
811,554

Liabilities Incurred
19,276

 
18,258

Liabilities Settled (1)
(28,726
)
 
(18,043
)
Accretion
17,010

 
16,521

Revisions
3,646

 
(635
)
Foreign Currency Translations
3,808

 
(6,745
)
Carrying Amount at End of Period
$
927,940

 
$
820,910

 
 
 
 
Current Portion
$
33,922

 
$
8,349

Noncurrent Portion
$
894,018

 
$
812,561

 
(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 Condensed Consolidated Balance Sheets.

7.    Exploratory Well Costs

EOG's net changes in capitalized exploratory well costs for the six-month period ended June 30, 2017, are presented below (in thousands):
 
Six Months Ended 
 June 30, 2017
Balance at January 1
$

Additions Pending the Determination of Proved Reserves
2,995

Reclassifications to Proved Properties

Costs Charged to Expense

Balance at June 30
$
2,995



-12-

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


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 a defined benefit pension plan covering certain of its employees in Trinidad. For the six months ended June 30, 2017 and 2016, EOG's total costs recognized for these pension plans were $18.4 million and $17.2 million, respectively. EOG also has postretirement medical and dental plans in place for eligible employees and their dependents in the United States and Trinidad, the costs of which are not material.

10.    Long-Term Debt

EOG had no outstanding commercial paper borrowings or uncommitted credit facility borrowings at June 30, 2017, and did not utilize any such borrowings during the six months ended June 30, 2017. During the six months ended June 30, 2016, EOG utilized commercial paper, bearing market interest rates, for various corporate financing purposes. The average borrowings outstanding under the commercial paper program were $210 million during the six months ended June 30, 2016. The weighted average interest rate for commercial paper borrowings was 0.76% during the six months ended June 30, 2016.

At June 30, 2017, $600 million aggregate principal amount of EOG's 5.875% Senior Notes due 2017 was reclassified as Current Portion of Long-Term Debt on the Condensed Consolidated Balance Sheets based upon its intent and ability to repay these notes upon maturity with cash in the third quarter of 2017.

EOG currently has a $2.0 billion senior unsecured Revolving Credit Agreement (Agreement) with domestic and foreign lenders. The 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 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 Agreement) plus an applicable margin. At June 30, 2017, there were no borrowings or letters of credit outstanding under the Agreement. The Eurodollar rate and applicable base rate, had there been any amounts borrowed under the Agreement, would have been 2.22% and 4.25%, respectively.

-13-

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


11.    Fair Value Measurements

As more fully discussed in Note 13 to the Consolidated Financial Statements included in EOG's 2016 Annual Report, certain of EOG's financial and nonfinancial assets and liabilities are reported at fair value on the Condensed 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 June 30, 2017 and December 31, 2016 (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 June 30, 2017
 

 
 

 
 

 
 

Financial Assets:
 

 
 

 
 

 
 

Natural Gas Swaps
$

 
$
1

 
$

 
$
1

Natural Gas Options/Collars

 
7

 

 
7

 
 
 
 
 
 
 
 
At December 31, 2016
 
 
 
 
 
 
 
Financial Assets:
 
 
 
 
 
 
 
Natural Gas Options/Collars
$

 
$
1

 
$

 
$
1

Financial Liabilities:
 
 
 
 
 
 
 
Crude Oil Swaps
$

 
$
36

 
$

 
$
36

Natural Gas Swaps

 
4

 

 
4

Natural Gas Options/Collars

 
22

 

 
22


The estimated fair value of commodity derivative contracts 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.

Proved oil and gas properties and other assets with a carrying amount of $253 million were written down to their fair value of $92 million, resulting in pretax impairment charges of $161 million for the six months ended June 30, 2017. Included in the $161 million pretax impairment charges are $138 million of impairments of proved oil and gas properties and other property, plant and equipment for which EOG utilized an accepted offer from a third-party purchaser as the basis for determining fair value. In addition, EOG recorded pretax impairment charges of $23 million for a commodity price-related write-down of other assets.

EOG utilized average prices per acre from comparable market transactions as the basis for determining the fair value of unproved properties received in non-cash property exchanges. See Note 4.

Fair Value of Debt. At June 30, 2017 and December 31, 2016, EOG had outstanding $6,990 million aggregate principal amount of senior notes, which had estimated fair values at such dates of approximately $7,181 million and $7,190 million, respectively. The estimated fair value of debt was based upon quoted market prices and, where such prices were not available, other observable (Level 2) inputs regarding interest rates available to EOG at the end of each respective period.


-14-

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


12.    Risk Management Activities

Commodity Price Risk. As more fully discussed in Note 12 to the Consolidated Financial Statements included in EOG's 2016 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. Prices received by EOG for its crude oil production generally vary from U.S. New York Mercantile Exchange (NYMEX) West Texas Intermediate prices due to adjustments for delivery location (basis) and other factors. EOG entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma. Presented below is a comprehensive summary of EOG's crude oil basis swap contracts for the six months ended June 30, 2017. The weighted average price differential expressed in dollars per barrel ($/Bbl) represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in barrels per day (Bbld) covered by the basis swap contracts.

 
Crude Oil Basis Swap Contracts
 
 
 
Volume (Bbld)
 
Weighted Average Price Differential
($/Bbl)
 
 
 
2018
 
 
 
 
 
January 1, 2018 through December 31, 2018
 
15,000

 
$
1.063

 
 
 
 
 
 
 
2019
 
 
 
 
 
January 1, 2019 through December 31, 2019
 
20,000

 
$
1.075


On March 14, 2017, EOG executed the optional early termination provision granting EOG the right to terminate certain crude oil price swaps with notional volumes of 30,000 Bbld at a weighted average price of $50.05 per Bbl for the period March 1, 2017 through June 30, 2017. EOG received cash of $4.6 million for the early termination of these contracts, which are included in the below table. Presented below is a comprehensive summary of EOG's crude oil price swap contracts for the six months ended June 30, 2017, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

Crude Oil Price Swap Contracts
 
 
Volume (Bbld)
 
Weighted Average Price ($/Bbl)
2017
 
 
 
 
January 1, 2017 through February 28, 2017 (closed)
 
35,000

 
$
50.04

March 1, 2017 through June 30, 2017 (closed)
 
30,000

 
50.05


On March 14, 2017, EOG entered into a crude oil price swap contract for the period March 1, 2017 through June 30, 2017, with notional volumes of 5,000 Bbld at a price of $48.81 per Bbl. This contract offsets the remaining crude oil price swap contract for the same time period with notional volumes of 5,000 Bbld at a price of $50.00 per Bbl. The net cash EOG received for settling these contracts was $0.7 million. The offsetting contracts are excluded from the above table.


-15-

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


Presented below is a comprehensive summary of EOG's natural gas price swap contracts for the six months ended June 30, 2017, 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)
2017
 
 
 
 
March 1, 2017 through July 31, 2017 (closed)
 
30,000

 
$
3.10

August 1, 2017 through November 30, 2017
 
30,000

 
3.10

 
 
 
 
 
2018
 
 
 
 
March 1, 2018 through November 30, 2018
 
35,000

 
$
3.00


EOG has sold call options which establish a ceiling price for the sale of notional volumes of natural gas as specified in the call option contracts. The call options require that EOG pay the difference between the call option strike price and either the average or last business day NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the call option strike price.

In addition, EOG has purchased put options which establish a floor price for the sale of notional volumes of natural gas 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 Henry Hub Index Price in the event the Henry Hub Index Price is below the put option strike price. Presented below is a comprehensive summary of EOG's natural gas call and put option contracts for the six months ended June 30, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.
Natural Gas Option Contracts
 
Call Options Sold
 
Put Options Purchased
 
Volume (MMBtud)
 
Weighted
Average Price
($/MMBtu)
 
Volume (MMBtud)
 
Weighted
Average Price
($/MMBtu)
2017
 
 
 
 
 
 
 
March 1, 2017 through July 31, 2017 (closed)
213,750

 
$
3.44

 
171,000

 
$
2.92

August 1, 2017 through November 30, 2017
213,750

 
3.44

 
171,000

 
2.92

 
 
 
 
 
 
 
 
2018
 
 
 
 
 
 
 
March 1, 2018 through November 30, 2018
120,000

 
$
3.38

 
96,000

 
$
2.94



-16-

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


EOG has also entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts. The collars require that EOG pay the difference between the ceiling price and the Henry Hub Index Price in the event the Henry Hub Index Price is above the ceiling price. The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price. Presented below is a comprehensive summary of EOG's natural gas collar contracts for the six months ended June 30, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.

Natural Gas Collar Contracts
 
 
 
Weighted Average Price ($/MMBtu)
 
Volume (MMBtud)
 
Ceiling Price
 
Floor Price
2017
 
 
 
 
 
March 1, 2017 through July 31, 2017 (closed)
80,000

 
$
3.69

 
$
3.20

August 1, 2017 through November 30, 2017
80,000

 
3.69

 
3.20


The following table sets forth the amounts and classification of EOG's outstanding financial derivative instruments at June 30, 2017 and December 31, 2016.  Certain amounts may be presented on a net basis on the Condensed 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
 
June 30, 2017
 
December 31, 2016
Asset Derivatives
 
 
 
 
 
 
Crude oil and natural gas derivative contracts -
 
 
 
 
 
 
Current portion
 
Assets from Price Risk Management Activities
 
$
5

 
$

Noncurrent portion
 
Other Assets
 
3

 
1

Liability Derivatives
 
 
 
 
 
 

Crude oil and natural gas derivative contracts -
 
 
 
 
 
 

Current portion
 
Liabilities from Price Risk Management Activities
 
$

 
$
62



-17-

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


Credit Risk. Notional contract amounts are used to express the magnitude of a financial derivative. 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 derivative instruments are covered by International Swap Dealers Association Master Agreements (ISDAs) with counterparties. The ISDAs may contain provisions that require EOG, if it is the party in a net liability position, to post collateral when the amount of the net liability exceeds the threshold level specified for EOG's then-current credit ratings. In addition, the ISDAs may also provide that as a result of certain circumstances, including certain events that cause EOG's credit ratings to become materially weaker than its then-current ratings, the counterparty may require all outstanding derivatives under the ISDAs to be settled immediately. See Note 11 for the aggregate fair value of all derivative instruments that were in a net liability position at December 31, 2016. EOG had no collateral posted and held no collateral at June 30, 2017 and December 31, 2016.

13.  Acquisitions and Divestitures

Yates Entities. On October 4, 2016, EOG completed its previously announced mergers and related asset purchase transactions with Yates Petroleum Corporation (YPC), Abo Petroleum Corporation (ABO), MYCO Industries, Inc. (MYCO) and certain affiliated entities (collectively with YPC, ABO and MYCO, the Yates Entities). For a further discussion of these transactions, refer to Note 17 to the Consolidated Financial Statements in EOG's 2016 Annual Report. The assets of the Yates Entities include producing wells in addition to acreage in the Delaware Basin Core, the Powder River Basin, the Permian Basin Northwest Shelf and other Western basins.

EOG accounted for the mergers with YPC, ABO and MYCO and the related asset purchase transactions as a business combination under the acquisition method with EOG as the acquirer. Under the acquisition method, the consideration transferred is allocated to the assets acquired and liabilities assumed based on their estimated fair values, with any excess of the consideration transferred over the estimated fair value of the identifiable net assets acquired recorded as goodwill. EOG did not record goodwill in connection with these transactions.

There were no changes during the six months ended June 30, 2017, to the preliminary purchase price allocation. Certain data necessary to complete the purchase price allocation is preliminary, and includes, but is not limited to, the final valuations of oil and gas properties, the valuation of off-market transportation contracts and the calculation of deferred taxes based upon the underlying tax basis of assets acquired and liabilities assumed. EOG believes the estimates used are reasonable but are subject to change as additional information becomes available.

Other. During the six months ended June 30, 2017, EOG recognized a net loss on asset dispositions of $26 million and received proceeds of approximately $175 million primarily from the sale of producing assets, unproved leasehold and other property, plant and equipment in Oklahoma and Texas. During the six months ended June 30, 2016, EOG recognized a net loss on asset dispositions of $6 million and received proceeds of approximately $253 million primarily from sales of producing properties and acreage in the Permian Basin and Oklahoma.


-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, the United Kingdom and China. EOG operates under a consistent business and operational strategy that focuses predominantly on maximizing the rate of return on investment of capital by controlling operating and capital costs and maximizing reserve recoveries. Pursuant to this strategy, each prospective drilling location is evaluated by its estimated rate of return. 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. EOG implements its strategy by emphasizing the drilling of internally generated prospects in order to find and develop low-cost reserves. 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.

Crude oil and natural gas prices have been volatile, and this volatility is expected to continue. As a result of the many uncertainties associated with the world political environment, worldwide supplies of, and demand for, crude oil and condensate, natural gas liquids (NGLs) and natural gas and the availability of other worldwide energy supplies, EOG is unable to predict what changes may occur in crude oil and condensate, NGL, and natural gas prices in the future. The market prices of crude oil and condensate, NGLs and natural gas in 2017 will continue to impact the amount of cash generated from EOG's operating activities, which will in turn impact EOG's financial position and results of operations. For the first half of 2017, the average U.S. New York Mercantile Exchange (NYMEX) crude oil and natural gas prices were $50.07 per barrel and $3.19 per million British thermal units (MMBtu), respectively, representing increases of 26% and 60%, respectively, from the average NYMEX prices for the same period in 2016. Based on its 2017 drilling and completion plans, EOG expects 2017 total production and total crude oil production to increase as compared to 2016.

During the first half of 2017, EOG continued to focus on increasing drilling, completion and operating efficiencies gained in prior years. In addition, EOG maintained the strategy of looking 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. On a volumetric basis, as calculated using the ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas, crude oil and condensate and NGL production accounted for approximately 77% of EOG's United States production during the first half of 2017 as compared to 72% for the same comparable period of 2016. During the first half of 2017, drilling and completion activities occurred primarily in the Eagle Ford play, Delaware Basin play and Rocky Mountain area. EOG's major producing areas in the United States are in New Mexico, North Dakota, Texas and Wyoming.

Trinidad. 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 Sercan Area (formerly known as 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 (NGC) and crude oil and condensate which is sold to the Petroleum Company of Trinidad and Tobago Limited. In early 2017, EOG completed and brought on-line two net wells finishing its program in the Sercan area. During the second quarter of 2017, EOG drilled a net well, which was completed in July 2017, and participated in a seismic survey program with a joint venture partner. Also, in June 2017, EOG and NGC signed a new multi-year contract under which EOG will supply future natural gas volumes to NGC beginning in 2019. For the remainder of 2017, EOG expects to drill and complete three additional net wells.


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Other International. In the United Kingdom, EOG produces crude oil from its 100% working interest East Irish Sea Conwy project. During the second quarter of 2017, the Conwy production was off-line due to operational issues. Additional downtime is expected in the second half of 2017 due to planned facility improvements and ongoing operational issues.

In the Sichuan Basin, Sichuan Province, China, EOG drilled four natural gas wells in the first half of 2017 as part of the continuing development of the Bajiaochang Field, which natural gas is sold under a long-term contract to PetroChina. In the second half of 2017, EOG expects to complete the four aforementioned wells and drill a fifth well.

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.

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% at both June 30, 2017 and December 31, 2016. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

On February 15, 2017, the Board of Directors approved an amendment to EOG's Restated Certificate of Incorporation to increase the number of EOG's authorized shares of common stock from 640 million to 1,280 million. EOG's stockholders approved the increase at the Annual Meeting of Stockholders on April 27, 2017, and the amendment was filed with the Delaware Secretary of State on April 28, 2017.

At June 30, 2017, $600 million aggregate principal amount of EOG's 5.875% Senior Notes due 2017 was reclassified as Current Portion of Long-Term Debt on the Condensed Consolidated Balance Sheets based upon its intent and ability to repay these notes upon maturity with cash in the third quarter of 2017.

Total anticipated 2017 capital expenditures are estimated to range from approximately $3.7 billion to $4.1 billion, excluding acquisitions. The majority of 2017 expenditures will be focused on United States crude oil drilling activities. EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program and other uncommitted credit facilities, bank borrowings, borrowings under its $2.0 billion senior unsecured revolving credit facility, joint development agreements and similar arrangements 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.



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Results of Operations

The following review of operations for the three months and six months ended June 30, 2017 and 2016 should be read in conjunction with the Condensed Consolidated Financial Statements of EOG and notes thereto included in this Quarterly Report on Form 10‑Q.

Three Months Ended June 30, 2017 vs. Three Months Ended June 30, 2016

Net Operating Revenues. During the second quarter of 2017, net operating revenues increased $836 million, or 47%, to $2,612 million from $1,776 million for the same period of 2016. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGLs and natural gas, for the second quarter of 2017 increased $489 million, or 37%, to $1,816 million from $1,327 million for the same period of 2016. EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $9 million for the second quarter of 2017 compared to net losses of $44 million for the same period of 2016. Gathering, processing and marketing revenues for the second quarter of 2017 increased $294 million, or 61%, to $779 million from $485 million for the same period of 2016. Net losses on asset dispositions for the second quarter of 2017 were $9 million compared to $16 million for the same period of 2016.


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Wellhead volume and price statistics for the three-month periods ended June 30, 2017 and 2016 were as follows:
 
Three Months Ended 
 June 30,
 
2017
 
 
2016
Crude Oil and Condensate Volumes (MBbld) (1)
 
 
 
 
United States
333.1

 
 
265.4

Trinidad
0.8

 
 
0.8

Other International (2)
0.8

 
 
1.5

Total
334.7

 
 
267.7

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

 
 
 
United States
$
47.51

 
 
$
43.87

Trinidad
39.64

 
 
35.91

Other International (2)
35.13

 
 

Composite
47.46

 
 
43.65

Natural Gas Liquids Volumes (MBbld) (1)
 
 
 
 
United States
86.6

 
 
84.3

Other International (2)

 
 

Total
86.6

 
 
84.3

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

 
 
 

United States
$
18.65

 
 
$
14.56

Other International (2)

 
 

Composite
18.65

 
 
14.56

Natural Gas Volumes (MMcfd) (1)
 
 
 
 
United States
755

 
 
820

Trinidad
320

 
 
349

Other International (2)
21

 
 
25

Total
1,096

 
 
1,194

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

 
 
 

United States
$
2.14

 
 
$
1.18

Trinidad
2.40

 
 
1.89

Other International (2)
3.66

 
 
3.35

Composite
2.25

 
 
1.44

Crude Oil Equivalent Volumes (MBoed) (4)
 
 
 
 
United States
545.6

 
 
486.3

Trinidad
54.1

 
 
59.0

Other International (2)
4.2

 
 
5.8

Total
603.9

 
 
551.1

 
 
 
 
 
Total MMBoe (4)
55.0

 
 
50.1

 
(1)
Thousand barrels per day or million cubic feet per day, as applicable.
(2)
Other International includes EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016.
(3)
Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 12 to the Condensed 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.


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Wellhead crude oil and condensate revenues for the second quarter of 2017 increased $386 million, or 36%, to $1,445 million from $1,059 million for the same period of 2016. The increase was primarily due to an increase of 67 MBbld, or 25%, in wellhead crude oil and condensate production ($270 million) and a higher composite wellhead crude oil and condensate price ($116 million). Increased production was primarily due to increases in the Permian Basin, Rocky Mountain area, the Eagle Ford and from the 2016 mergers and related asset purchase transactions with Yates Petroleum Corporation and other affiliated entities (collectively, the Yates Entities). EOG's composite wellhead crude oil and condensate price for the second quarter of 2017 increased 9% to $47.46 per barrel compared to $43.65 per barrel for the same period of 2016.

NGL revenues for the second quarter of 2017 increased $35 million, or 32%, to $147 million from $112 million for the same period of 2016 due primarily to a higher composite average price. EOG's composite NGL price for the second quarter of 2017 increased 28% to $18.65 per barrel compared to $14.56 per barrel for the same period of 2016.

Wellhead natural gas revenues for the second quarter of 2017 increased $68 million, or 44%, to $224 million from $156 million for the same period of 2016. The increase was due to a higher composite wellhead natural gas price ($81 million), partially offset by a decrease in natural gas deliveries ($13 million). Natural gas deliveries for the second quarter of 2017 decreased 98 MMcfd, or 8%, compared to the same period of 2016 due primarily to lower deliveries in the United States (65 MMcfd) and Trinidad (29 MMcfd). The decrease in the United States was due primarily to the 2016 sale of EOG's Johnson County, Texas, Barnett Shale, Haynesville and South Texas natural gas assets, partially offset by increased production of associated natural gas from the Permian Basin and the Rocky Mountain area and the 2016 transactions with the Yates Entities. The decrease in Trinidad was primarily due to lower contractual deliveries. EOG's composite wellhead natural gas price for the second quarter of 2017 increased 56% to $2.25 per Mcf compared to $1.44 per Mcf for the same period of 2016.

During the second quarter of 2017, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $9 million compared to net losses of $44 million for the same period of 2016. During the second quarter of 2017, net cash received for settlements of financial commodity derivative contracts was $0.7 million compared to net cash paid of $15 million for the same period of 2016.

Gathering, processing and marketing revenues are revenues generated from sales of third-party crude oil, NGLs and natural gas as well as gathering fees associated with gathering third-party natural gas and revenues from sales of EOG-owned sand. 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. EOG sells sand in order to balance the timing of firm purchase agreements with completion operations and to utilize excess capacity at EOG-owned facilities. Marketing costs represent the costs of purchasing third-party crude oil and natural gas and the associated transportation costs as well as costs associated with EOG-owned sand sold to third parties.

Gathering, processing and marketing revenues less marketing costs for the second quarter of 2017 decreased $17 million as compared to the same period of 2016. The decrease primarily reflects lower margins in 2017 on crude oil marketing activities, partially offset by higher margins on natural gas marketing activities and sand sales.


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Operating and Other Expenses.  For the second quarter of 2017, operating expenses of $2,485 million were $421 million higher than the $2,064 million incurred during the second quarter of 2016.  The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended June 30, 2017 and 2016:
 
Three Months Ended 
 June 30,
 
2017
 
2016
Lease and Well
$
4.64

 
$
4.36

Transportation Costs
3.39

 
3.59

Depreciation, Depletion and Amortization (DD&A) -
 
 
 
Oil and Gas Properties
15.22

 
16.66

Other Property, Plant and Equipment
0.52

 
0.57

General and Administrative (G&A)
1.97

 
1.95

Interest Expense, Net
1.28

 
1.42

Total (1)
$
27.02

 
$
28.55

 
(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, DD&A and G&A for the three months ended June 30, 2017, compared to the same period of 2016 are set forth below. See "Net Operating Revenues" above for a discussion of wellhead 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 $255 million for the second quarter of 2017 increased $37 million from $218 million for the same prior year period primarily due to increased operating and maintenance costs in the United States ($28 million) and the United Kingdom ($9 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, 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 $186 million for the second quarter of 2017 increased $7 million from $179 million for the same prior year period primarily due to higher transportation costs in the Permian Basin ($9 million), the Rocky Mountain area ($9 million) and the Eagle Ford ($5 million) and the addition of the Yates Entities in 2016 ($5 million), partially offset by the 2016 sale of EOG's Johnson County, Texas, Barnett Shale and Haynesville natural gas assets ($20 million).

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.


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DD&A expenses for the second quarter of 2017 increased $3 million to $865 million from $862 million for the same prior year period. DD&A expenses associated with oil and gas properties for the second quarter of 2017 were $3 million higher than the same prior year period. The increase primarily reflects increased production in the United States ($95 million), partially offset by decreased rates in the United States ($86 million) and Trinidad ($3 million) and decreased production in Trinidad ($3 million). DD&A unit rates in the United States decreased primarily due to upward reserve revisions and reserves added at lower cost as a result of increased efficiencies.

G&A expenses of $109 million for the second quarter of 2017 increased $11 million from $98 million for the same prior year period primarily due to increases in professional, legal and other services ($19 million) and by an increase in employee-related expenses ($12 million) primarily due to the 2016 transactions with the Yates Entities, partially offset by a decrease in employee-related expenses in connection with certain voluntary retirements in 2016 ($20 million).

Exploration costs of $35 million for the second quarter of 2017 increased $4 million from $31 million for the same prior year period primarily due to increased geological and geophysical costs in the United States.

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 individually significant acquisition costs are analyzed on a property-by-property basis for any impairment in value. 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 $79 million for the second quarter of 2017 were $6 million higher than impairments for the same prior year period primarily due to increased impairments of other assets in the United States ($23 million), partially offset by decreased amortization of unproved property costs in the United States ($17 million). EOG recorded impairments of proved properties, other property, plant and equipment and other assets of $24 million and $1 million for the second quarter of 2017 and 2016, respectively.

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

Gathering and processing costs increased $6 million to $35 million for the second quarter of 2017 compared to $29 million for the same prior year period primarily due to increased operating costs in the United Kingdom ($8 million), partially offset by lower operating costs in the Fort Worth Basin Barnett Shale ($3 million).

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

Taxes other than income for the second quarter of 2017 increased $37 million to $130 million (7.2% of wellhead revenues) compared to $93 million (7.0% of wellhead revenues) for the same prior year period. The increase in taxes other than income was primarily due to increases in severance/production taxes, primarily as a result of increased wellhead revenues in the United States.

Other income (expense), net for the second quarter of 2017 increased $26 million compared to the same prior year period primarily due to a decrease in foreign currency exchange losses ($22 million) and decreased deferred compensation expense ($4 million).

EOG recognized an income tax provision of $39 million for the second quarter of 2017 compared to an income tax benefit of $88 million in the second quarter of 2016, primarily due to pretax income in 2017 as compared to a pretax loss in 2016. The net effective tax rate for the second quarter of 2017 increased to 63% from 23% for the second quarter of 2016. The higher effective tax rate was primarily due to additional deferred state income taxes resulting from changes in state apportionment factors and foreign losses in the United Kingdom and Canada for which tax benefits are not recorded due to valuation allowances.


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Six Months Ended June 30, 2017 vs. Six Months Ended June 30, 2016

Net Operating Revenues. During the first six months of 2017, net operating revenues increased $2,093 million, or 67%, to $5,223 million from $3,130 million for the same period of 2016. Total wellhead revenues for the first six months of 2017 increased $1,309 million, or 56%, to $3,631 million from $2,322 million for the same period of 2016. During the first six months of 2017, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $71 million compared to net losses of $39 million for the same period of 2016. Gathering, processing and marketing revenues for the first six months of 2017 increased $686 million, or 84%, to $1,505 million from $819 million for the same period of 2016. Net losses on asset dispositions for the first six months of 2017 were $26 million compared to $6 million for the same period of 2016.

Wellhead volume and price statistics for the six-month periods ended June 30, 2017 and 2016 were as follows:
 
Six Months Ended 
 June 30,
 
 
2017
 
 
2016
 
Crude Oil and Condensate Volumes (MBbld)
 
 
 
 
 
United States
322.8

 
 
265.6

 
Trinidad
0.8

 
 
0.8

 
Other International
1.6

 
 
1.4

 
Total
325.2

 
 
267.8

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

 
 
 

 
United States
$
48.89

 
 
$
37.36

 
Trinidad
40.63

 
 
29.83

 
Other International
44.66

 
 

 
Composite
48.85

 
 
37.23

 
Natural Gas Liquids Volumes (MBbld)
 
 
 
 

 
United States
82.7

 
 
81.8

 
Other International

 
 

 
Total
82.7

 
 
81.8

 
Average Natural Gas Liquids Prices ($/Bbl)
 

 
 
 

 
United States
$
20.06

 
 
$
12.54

 
Other International

 
 

 
Composite
20.06

 
 
12.54

 
Natural Gas Volumes (MMcfd)
 
 
 
 

 
United States
742

 
 
825

 
Trinidad
314

 
 
355

 
Other International
21

 
 
25

 
Total
1,077

 
 
1,205

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

 
 
 

 
United States
$
2.23

 
 
$
1.22

 
Trinidad
2.48

 
 
1.88

 
Other International
3.71

 
 
3.49

 
Composite
2.33

 
 
1.47

 
Crude Oil Equivalent Volumes (MBoed)
 
 
 
 

 
United States
529.2

 
 
484.9

 
Trinidad
53.1

 
 
59.9

 
Other International
5.1

 
 
5.6

 
Total
587.4

 
 
550.4

 
 
 
 
 
 
 
Total MMBoe
106.3

 
 
100.2

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

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Wellhead crude oil and condensate revenues for the first six months of 2017 increased $1,063 million, or 59%, to $2,876 million from $1,813 million for the same period of 2016 due primarily to a higher composite wellhead crude oil and condensate price ($684 million) and an increase of 57 MBbld, or 21%, in wellhead crude oil and condensate production ($379 million). Increased production was primarily due to increases in the Permian Basin and the Rocky Mountain area. EOG's composite wellhead crude oil and condensate price for the first six months of 2017 increased 31% to $48.85 per barrel compared to $37.23 per barrel for the same period of 2016.

NGL revenues for the first six months of 2017 increased $113 million, or 61%, to $300 million from $187 million for the same period of 2016 due primarily to a higher composite average price. EOG's composite NGL price for the first six months of 2017 increased 60% to $20.06 per barrel compared to $12.54 per barrel for the same period of 2016.

Wellhead natural gas revenues for the first six months of 2017 increased $133 million, or 41%, to $455 million from $322 million for the same period of 2016 primarily due to a higher composite wellhead natural gas price ($169 million), partially offset by a decrease of 128 MMcfd, or 11%, in natural gas deliveries ($36 million) primarily due to lower production in the United States (83 MMcfd) and Trinidad (41 MMcfd). The decrease in the United States was due primarily to the 2016 sale of EOG's Johnson County, Texas, Barnett Shale, Haynesville and South Texas natural gas assets, partially offset by increased production of associated natural gas from the Permian Basin and the Rocky Mountain area and the 2016 transactions with the Yates Entities. EOG's composite wellhead natural gas price for the first six months of 2017 increased 58% to $2.33 per Mcf compared to $1.47 per Mcf for the same period of 2016.

During the first six months of 2017, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $71 million compared to net losses of $39 million for the same period of 2016. During the first six months of 2017 and 2016, net cash received for settlements of financial commodity derivative contracts was $3 million. The net cash received for financial commodity derivative contracts during the first six months of 2017 included certain early-terminated crude oil price swaps.

Gathering, processing and marketing revenues less marketing costs for the first six months of 2017 decreased $20 million as compared to the same period of 2016. The decrease primarily reflects lower margins in 2017 on crude oil marketing activities, partially offset by higher margins on natural gas marketing activities.

Operating and Other Expenses. For the first six months of 2017, operating expenses of $4,987 million were $931 million higher than the $4,056 million incurred during the same period of 2016. The following table presents the costs per Boe for the six-month periods ended June 30, 2017 and 2016:
 
Six Months Ended 
 June 30,
 
2017
 
2016
Lease and Well
$
4.81

 
$
4.59

Transportation Costs
3.43

 
3.69

DD&A -
 
 
 
Oil and Gas Properties
15.28

 
17.32

Other Property, Plant and Equipment
0.54

 
0.56

G&A
1.94

 
1.98

Interest Expense, Net
1.33

 
1.39

Total (1)
$
27.33

 
$
29.53

 
(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 six months ended June 30, 2017, compared to the same period of 2016 are set forth below. See "Net Operating Revenues" above for a discussion of wellhead volumes.

Lease and well expenses of $511 million for the first six months of 2017 increased $52 million from $459 million for the same prior year period primarily due to higher operating and maintenance costs in the United States ($34 million) and the United Kingdom ($13 million) and workover expenditures in the United States ($15 million).


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Transportation costs of $365 million for the first six months of 2017 decreased $5 million from $370 million for the same prior year period primarily due to the 2016 sale of EOG's Johnson County, Texas, Barnett Shale and Haynesville natural gas assets ($42 million), partially offset by higher transportation costs in the Permian Basin ($19 million), the Rocky Mountain area ($10 million) and the addition of the Yates Entities in 2016 ($8 million).

DD&A expenses for the first six months of 2017 decreased $110 million to $1,681 million from $1,791 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first six months of 2017 were $111 million lower than the same prior year period. The decrease primarily reflects decreased rates in the United States ($229 million) and Trinidad ($12 million) and decreased production in Trinidad ($9 million), partially offset by increased production in the United States ($137 million) and the United Kingdom ($4 million). DD&A unit rates in the United States decreased primarily due to upward reserve revisions and reserves added at lower cost as a result of increased efficiencies.

Exploration costs of $92 million for the first six months of 2017 increased $32 million from $60 million for the same prior year period primarily due to increased geological and geophysical costs in Trinidad ($20 million) and the United States ($11 million).

G&A expenses of $206 million for the first six months of 2017 increased $8 million from $198 million for the same prior year period primarily due to increases in professional, legal and other services ($23 million) and by an increase in employee-related expenses ($25 million) primarily due to the 2016 transactions with the Yates Entities, partially offset by a decrease in employee-related expenses in connection with certain voluntary retirements in 2016 ($42 million).

Gathering and processing costs for the first six months of 2017 increased $15 million to $73 million compared to the same prior year period primarily due to increased operating costs in the United Kingdom ($19 million), partially offset by decreased operating costs in the Fort Worth Basin Barnett Shale area ($4 million).

Impairments of $272 million for the first six months of 2017 were $128 million higher than impairments for the same prior year period primarily due to increased impairments of proved properties and other assets in the United States ($159 million), partially offset by decreased amortization of unproved property costs in the United States ($31 million), which was caused by a decrease in EOG's estimates of undeveloped properties not expected to be developed before lease expiration. For the first six months of 2017, proved property and other asset impairments in the United States were primarily related to the sale of legacy natural gas assets. EOG recorded impairments of proved properties, other property, plant and equipment and other assets of $161 million and $2 million for the first six months of 2017 and 2016, respectively.

Taxes other than income for the first six months of 2017 increased $106 million to $260 million (7.2% of wellhead revenues) from $154 million (6.6% of wellhead revenues) for the same prior year period. The increase in taxes other than income was primarily due to increased severance/production taxes ($91 million) as a result of increased wellhead revenues and increased ad valorem/property taxes ($14 million) in the United States and a decrease in credits available to EOG in 2017 for Texas high-cost gas severance tax rate reductions ($2 million).

Other income (expense), net for the first six months of 2017 increased $33 million compared to the same prior year period primarily due to a decrease in foreign currency exchange losses.

EOG recognized an income tax provision of $50 million for the first six months of 2017 compared to an income tax benefit of $327 million for the same period in 2016, primarily due to pretax income in 2017 as compared to a pretax loss. The net effective tax rate for the first six months of 2017 increased to 49% from 30% for the first six months of 2016. The higher effective tax rate was primarily due to foreign losses in the United Kingdom and Canada for which tax benefits are not recorded due to valuation allowances and additional deferred state income taxes resulting from changes in state apportionment factors.

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Capital Resources and Liquidity

Cash Flow. The primary sources of cash for EOG during the six months ended June 30, 2017, were funds generated from operations and proceeds from sales of assets. The primary uses of cash were funds used in operations; exploration and development expenditures; dividend payments to stockholders; other property, plant and equipment expenditures; and purchases of treasury stock in connection with stock compensation plans. During the first six months of 2017, EOG's cash balance increased $49 million to $1,649 million from $1,600 million at December 31, 2016.

Net cash provided by operating activities of $1,976 million for the first six months of 2017 increased $1,181 million compared to the same period of 2016 primarily due to an increase in wellhead revenues ($1,309 million) and favorable changes in working capital and other assets and liabilities ($200 million), partially offset by an increase in cash operating expenses ($211 million) and an unfavorable change in net cash paid for income taxes ($109 million).

Net cash used in investing activities of $1,719 million for the first six months of 2017 increased by $838 million compared to the same period of 2016 due to an increase in additions to oil and gas properties ($742 million), a decrease in proceeds from the sales of assets ($77 million) and an increase in additions to other property, plant and equipment ($43 million), partially offset by favorable changes in working capital associated with investing activities ($25 million).

Net cash used in financing activities of $208 million for the first six months of 2017 included cash dividend payments ($193 million) and purchases of treasury stock in connection with stock compensation plans ($22 million). Net cash provided by financing activities of $136 million for the first six months of 2016 included net proceeds from the issuance of long-term debt ($991 million). Cash used in financing activities for the first six months of 2016 included repayments of long-term debt ($400 million), net commercial paper repayments ($260 million), cash dividend payments ($184 million) and purchases of treasury stock in connection with stock compensation plans ($29 million).

Total Expenditures. For the year 2017, EOG's budget for exploration and development and other property, plant and equipment expenditures is approximately $3.7 billion to $4.1 billion, excluding acquisitions. The table below sets out components of total expenditures for the six-month periods ended June 30, 2017 and 2016 (in millions):
 
Six Months Ended 
 June 30,
 
2017
 
2016
Expenditure Category
 
 
 
Capital
 
 
 
Exploration and Development Drilling
$
1,447

 
$
903

Facilities
309

 
182

Leasehold Acquisitions (1)
265

 
31

Property Acquisitions
4

 
10

Capitalized Interest
14

 
17

Subtotal
2,039

 
1,143

Exploration Costs
92

 
60

Dry Hole Costs

 

Exploration and Development Expenditures
2,131

 
1,203

Asset Retirement Costs
24

 
19

Total Exploration and Development Expenditures
2,155

 
1,222

Other Property, Plant and Equipment
90

 
45

Total Expenditures
$
2,245

 
$
1,267

 
(1)
Leasehold acquisitions included $154 million in 2017 related to non-cash property exchanges.
    

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Total exploration and development expenditures of $2,131 million for the first six months of 2017 were $928 million higher than the same period of 2016 primarily due to increased exploration and drilling expenditures in the United States ($481 million) and Trinidad ($52 million); increased facilities expenditures ($127 million); increased leasehold acquisitions ($234 million, including $154 million of non-cash property exchanges); and increased geological and geophysical expenditures ($31 million). Exploration and development expenditures for the first six months of 2017 of $2,131 million consisted of $1,749 million in development drilling and facilities, $364 million in exploration (including $154 million of non-cash property exchanges), $14 million in capitalized interest and $4 million in property acquisitions. Exploration and development expenditures for the first six months of 2016 of $1,203 million consisted of $1,078 million in development drilling and facilities, $98 million in exploration, $10 million in property acquisitions, and $17 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, 2016, filed on February 27, 2017, 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 Condensed Consolidated Statements of Income (Loss) and Comprehensive Income (Loss). The related cash flow impact is reflected in Cash Flows from Operating Activities on the Condensed Consolidated Statements of Cash Flows.

The total fair value of EOG's commodity derivative contracts was reflected on the Condensed Consolidated Balance Sheets at June 30, 2017, as a net asset of $8 million.

Prices received by EOG for its crude oil production generally vary from NYMEX West Texas Intermediate prices due to adjustments for delivery location (basis) and other factors. EOG entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma. Presented below is a comprehensive summary of EOG's crude oil basis swap contracts through August 1, 2017. The weighted average price differential expressed in dollars per barrel ($/Bbl) represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in barrels per day (Bbld) covered by the basis swap contracts.

 
Crude Oil Basis Swap Contracts
 
 
 
Volume (Bbld)
 
Weighted Average Price Differential
($/Bbl)
 
 
 
2018
 
 
 
 
 
January 1, 2018 through December 31, 2018
 
15,000

 
$
1.063

 
 
 
 
 
 
 
2019
 
 
 
 
 
January 1, 2019 through December 31, 2019
 
20,000

 
$
1.075



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On March 14, 2017, EOG executed the optional early termination provision granting EOG the right to terminate certain crude oil price swaps with notional volumes of 30,000 Bbld at a weighted average price of $50.05 per Bbl for the period March 1, 2017 through June 30, 2017. EOG received cash of $4.6 million for the early termination of these contracts, which are included in the below table. Presented below is a comprehensive summary of EOG's crude oil price swap contracts through August 1, 2017, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

Crude Oil Price Swap Contracts
 
 
Volume (Bbld)
 
Weighted Average Price ($/Bbl)
2017
 
 
 
 
January 1, 2017 through February 28, 2017 (closed)
 
35,000

 
$
50.04

March 1, 2017 through June 30, 2017 (closed)
 
30,000

 
50.05


On March 14, 2017, EOG entered into a crude oil price swap contract for the period March 1, 2017 through June 30, 2017, with notional volumes of 5,000 Bbld at a price of $48.81 per Bbl. This contract offsets the remaining crude oil price swap contract for the same time period with notional volumes of 5,000 Bbld at a price of $50.00 per Bbl. The net cash EOG received for settling these contracts was $0.7 million. The offsetting contracts are excluded from the above table.

Presented below is a comprehensive summary of EOG's natural gas price swap contracts through August 1, 2017, with notional volumes expressed in MMBtu per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).
Natural Gas Price Swap Contracts
 
 
Volume (MMBtud)
 
Weighted
Average Price
($/MMBtu)
2017
 
 
 
 
March 1, 2017 through August 31, 2017 (closed)
 
30,000

 
$
3.10

September 1, 2017 through November 30, 2017
 
30,000

 
3.10

 
 
 
 
 
2018
 
 
 
 
March 1, 2018 through November 30, 2018
 
35,000

 
$
3.00


EOG has sold call options which establish a ceiling price for the sale of notional volumes of natural gas as specified in the call option contracts. The call options require that EOG pay the difference between the call option strike price and either the average or last business day NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the call option strike price.


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In addition, EOG has purchased put options which establish a floor price for the sale of notional volumes of natural gas 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 Henry Hub Index Price in the event the Henry Hub Index Price is below the put option strike price. Presented below is a comprehensive summary of EOG's natural gas call and put option contracts through August 1, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.
Natural Gas Option Contracts
 
Call Options Sold
 
Put Options Purchased
 
Volume (MMBtud)
 
Weighted
Average Price
($/MMBtu)
 
Volume (MMBtud)
 
Weighted
Average Price
($/MMBtu)
2017
 
 
 
 
 
 
 
March 1, 2017 through August 31, 2017 (closed)
213,750

 
$
3.44

 
171,000

 
$
2.92

September 1, 2017 through November 30, 2017
213,750

 
3.44

 
171,000

 
2.92

 
 
 
 
 
 
 
 
2018
 
 
 
 
 
 
 
March 1, 2018 through November 30, 2018
120,000

 
$
3.38

 
96,000

 
$
2.94


EOG has also entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts. The collars require that EOG pay the difference between the ceiling price and the Henry Hub Index Price in the event the Henry Hub Index Price is above the ceiling price. The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price. Presented below is a comprehensive summary of EOG's natural gas collar contracts through August 1, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.
Natural Gas Collar Contracts