Quarterly Report (10-q)

Date : 08/02/2018 @ 8:32PM
Source : Edgar (US Regulatory)
Stock : Eog Resources, Inc. (EOG)
Quote : 94.01  -2.2 (-2.29%) @ 5:05AM

Quarterly Report (10-q)

 

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

 
FORM 10-Q
 

(Mark One)

ý            QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2018
or
o            TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number: 1-9743
image00001aa10.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
 
579,200,784 (as of July 25, 2018)

 

        



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 AND COMPREHENSIVE INCOME
(In Thousands, Except Per Share Data)
(Unaudited)
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2018
 
2017
 
2018
 
2017
Operating Revenues and Other
 
 
 
 
 
 
 
Crude Oil and Condensate
$
2,377,528

 
$
1,445,454

 
$
4,478,836

 
$
2,875,515

Natural Gas Liquids
286,354

 
146,907

 
507,769

 
300,351

Natural Gas
300,845

 
224,008

 
600,611

 
454,610

Gains (Losses) on Mark-to-Market Commodity Derivative Contracts
(185,883
)
 
9,446

 
(245,654
)
 
71,466

Gathering, Processing and Marketing
1,436,436

 
778,797

 
2,538,258

 
1,505,334

Losses on Asset Dispositions, Net
(6,317
)
 
(8,916
)
 
(21,286
)
 
(25,674
)
Other, Net
29,114

 
16,776

 
60,705

 
41,435

Total
4,238,077

 
2,612,472

 
7,919,239

 
5,223,037

Operating Expenses
 

 
 

 
 

 
 

Lease and Well
314,604

 
255,186

 
614,668

 
510,963

Transportation Costs
177,797

 
186,356

 
354,754

 
365,070

Gathering and Processing Costs
109,169

 
34,746

 
210,514

 
72,890

Exploration Costs
47,478

 
34,711

 
82,314

 
91,605

Dry Hole Costs
4,902

 
27

 
4,902

 
27

Impairments
51,708

 
78,934

 
116,317

 
272,121

Marketing Costs
1,420,463

 
790,599

 
2,526,853

 
1,527,135

Depreciation, Depletion and Amortization
848,674

 
865,384

 
1,597,265

 
1,681,420

General and Administrative
104,083

 
108,507

 
198,781

 
205,745

Taxes Other Than Income
194,268

 
130,114

 
373,352

 
260,407

Total
3,273,146

 
2,484,564

 
6,079,720

 
4,987,383

Operating Income
964,931

 
127,908

 
1,839,519

 
235,654

Other Income (Expense), Net
(8,551
)
 
4,972

 
(7,824
)
 
8,123

Income Before Interest Expense and Income Taxes
956,380

 
132,880

 
1,831,695

 
243,777

Interest Expense, Net
63,444

 
70,413

 
125,400

 
141,928

Income Before Income Taxes
892,936

 
62,467

 
1,706,295

 
101,849

Income Tax Provision
196,205

 
39,414

 
370,975

 
50,279

Net Income
$
696,731

 
$
23,053

 
$
1,335,320

 
$
51,570

Net Income Per Share
 

 
 

 
 

 
 

Basic
$
1.21

 
$
0.04

 
$
2.32

 
$
0.09

Diluted
$
1.20

 
$
0.04

 
$
2.30

 
$
0.09

Dividends Declared per Common Share
$
0.1850

 
$
0.1675

 
$
0.3700

 
$
0.3350

Average Number of Common Shares
 

 
 

 
 

 
 

Basic
576,135

 
574,439

 
575,953

 
574,162

Diluted
580,375

 
578,483

 
580,007

 
578,573

Comprehensive Income
 

 
 

 
 

 
 

Net Income
$
696,731

 
$
23,053

 
$
1,335,320

 
$
51,570

Other Comprehensive Income (Loss)
 

 
 

 
 

 
 

Foreign Currency Translation Adjustments
(3,229
)
 
1,260

 
1,773

 
1,569

Other, Net of Tax
6

 
(86
)
 
12

 
(49
)
Other Comprehensive Income (Loss)
(3,223
)
 
1,174

 
1,785

 
1,520

Comprehensive Income
$
693,508

 
$
24,227

 
$
1,337,105

 
$
53,090



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,
2018
 
December 31,
2017
ASSETS
Current Assets
 
 
 
Cash and Cash Equivalents
$
1,008,215

 
$
834,228

Accounts Receivable, Net
1,907,990

 
1,597,494

Inventories
670,994

 
483,865

Assets from Price Risk Management Activities
1,840

 
7,699

Income Taxes Receivable
364,119

 
113,357

Other
278,694

 
242,465

Total
4,231,852

 
3,279,108

Property, Plant and Equipment
 

 
 

Oil and Gas Properties (Successful Efforts Method)
55,319,050

 
52,555,741

Other Property, Plant and Equipment
4,141,479

 
3,960,759

Total Property, Plant and Equipment
59,460,529

 
56,516,500

Less:  Accumulated Depreciation, Depletion and Amortization
(32,306,734
)
 
(30,851,463
)
Total Property, Plant and Equipment, Net
27,153,795

 
25,665,037

Deferred Income Taxes
17,067

 
17,506

Other Assets
689,666

 
871,427

Total Assets
$
32,092,380

 
$
29,833,078

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
 

 
 

Accounts Payable
$
2,336,952

 
$
1,847,131

Accrued Taxes Payable
213,461

 
148,874

Dividends Payable
106,569

 
96,410

Liabilities from Price Risk Management Activities
195,457

 
50,429

Current Portion of Long-Term Debt
1,262,540

 
356,235

Other
182,322

 
226,463

Total
4,297,301

 
2,725,542

 
 
 
 
Long-Term Debt
5,172,257

 
6,030,836

Other Liabilities
1,304,624

 
1,275,213

Deferred Income Taxes
3,865,804

 
3,518,214

Commitments and Contingencies (Note 8)


 


 
 
 
 
Stockholders' Equity
 

 
 

Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 579,597,990 Shares Issued at June 30, 2018 and 578,827,768 Shares Issued at December 31, 2017
205,796

 
205,788

Additional Paid in Capital
5,591,643

 
5,536,547

Accumulated Other Comprehensive Loss
(17,512
)
 
(19,297
)
Retained Earnings
11,714,656

 
10,593,533

Common Stock Held in Treasury, 410,969 Shares at June 30, 2018 and 350,961 Shares at December 31, 2017
(42,189
)
 
(33,298
)
Total Stockholders' Equity
17,452,394

 
16,283,273

Total Liabilities and Stockholders' Equity
$
32,092,380

 
$
29,833,078


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,
 
2018
 
2017
Cash Flows from Operating Activities
 
 
 
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
 
 
 
Net Income
$
1,335,320

 
$
51,570

Items Not Requiring (Providing) Cash
 

 
 

Depreciation, Depletion and Amortization
1,597,265

 
1,681,420

Impairments
116,317

 
272,121

Stock-Based Compensation Expenses
67,289

 
58,061

Deferred Income Taxes
347,586

 
35,162

Losses on Asset Dispositions, Net
21,286

 
25,674

Other, Net
13,507

 
(6,691
)
Dry Hole Costs
4,902

 
27

Mark-to-Market Commodity Derivative Contracts
 

 
 

Total (Gains) Losses
245,654

 
(71,466
)
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts
(88,334
)
 
2,591

Other, Net
(261
)
 
(185
)
Changes in Components of Working Capital and Other Assets and Liabilities
 

 
 

Accounts Receivable
(309,751
)
 
103,786

Inventories
(192,219
)
 
(6,129
)
Accounts Payable
455,977

 
76,704

Accrued Taxes Payable
22,535

 
(39,124
)
Other Assets
(62,843
)
 
(61,089
)
Other Liabilities
(53,168
)
 
(66,869
)
Changes in Components of Working Capital Associated with Investing and Financing Activities
(27,279
)
 
(79,138
)
Net Cash Provided by Operating Activities
3,493,783

 
1,976,425

Investing Cash Flows
 

 
 

Additions to Oil and Gas Properties
(2,980,286
)
 
(1,885,417
)
Additions to Other Property, Plant and Equipment
(144,858
)
 
(88,076
)
Proceeds from Sales of Assets
8,276

 
175,260

Changes in Components of Working Capital Associated with Investing Activities
27,250

 
79,138

Net Cash Used in Investing Activities
(3,089,618
)
 
(1,719,095
)
Financing Cash Flows
 

 
 

Dividends Paid
(203,610
)
 
(192,984
)
Treasury Stock Purchased
(32,023
)
 
(21,678
)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan
11,145

 
9,608

Repayment of Capital Lease Obligation
(3,354
)
 
(3,251
)
Changes in Components of Working Capital Associated with Financing Activities
29

 

Net Cash Used in Financing Activities
(227,813
)
 
(208,305
)
Effect of Exchange Rate Changes on Cash
(2,365
)
 
523

Increase in Cash and Cash Equivalents
173,987

 
49,548

Cash and Cash Equivalents at Beginning of Period
834,228

 
1,599,895

Cash and Cash Equivalents at End of Period
$
1,008,215

 
$
1,649,443


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, 2017, filed on February 27, 2018 (EOG's 2017 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, 2018, are not necessarily indicative of the results to be expected for the full year.

Effective January 1, 2018, EOG adopted the provisions of Accounting Standards Update (ASU) 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09). ASU 2014-09 and other related ASUs 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. EOG elected to adopt ASU 2014-09 using the modified retrospective approach, which required EOG to recognize in retained earnings the cumulative effect at the date of adoption for all existing contracts with customers which were not substantially complete as of January 1, 2018. There was no impact to retained earnings upon adoption of ASU 2014-09.

EOG presents disaggregated revenues by type of commodity within its Condensed Consolidated Statements of Income and Comprehensive Income and by geographic areas defined as operating segments. See Note 5.

In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees relating to certain processing and marketing agreements within its United States segment as Gathering and Processing Costs, instead of a deduction to Revenues within its Condensed Consolidated Statements of Income and Comprehensive Income. There was no impact to operating income, net income or cash flows resulting from changes to the presentation of natural gas processing fees. The impacts of the adoption of ASU 2014-09 for the three and six months ended June 30, 2018, were as follows (in thousands):

-6-

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


 
Three Months Ended 
 June 30, 2018
 
Six Months Ended 
 June 30, 2018
 
As Reported
 
Amounts Without Adoption of ASU 2014-09
 
Effect of Change
 
As Reported
 
Amounts Without Adoption of ASU 2014-09
 
Effect of Change
Operating Revenues and Other
 
 
 
 
 
 
 
 
 
 
 
Crude Oil and Condensate
$
2,377,528

 
$
2,377,528

 
$

 
$
4,478,836

 
$
4,478,836

 
$

Natural Gas Liquids
286,354

 
284,898

 
1,456

 
507,769

 
504,543

 
3,226

Natural Gas
300,845

 
257,652

 
43,193

 
600,611

 
514,273

 
86,338

Gathering, Processing and Marketing
1,436,436

 
1,431,077

 
5,359

 
2,538,258

 
2,527,313

 
10,945

Total Operating Revenues and Other
4,238,077

 
4,188,069

 
50,008

 
7,919,239

 
7,818,730

 
100,509

Operating Expenses
 
 
 
 
 
 
 
 
 
 
 
Gathering and Processing Costs
109,169

 
64,520

 
44,649

 
210,514

 
120,950

 
89,564

Marketing Costs
1,420,463

 
1,415,104

 
5,359

 
2,526,853

 
2,515,908

 
10,945

Total Operating Expenses
3,273,146

 
3,223,138

 
50,008

 
6,079,720

 
5,979,211

 
100,509

Operating Income
964,931

 
964,931

 

 
1,839,519

 
1,839,519

 


Revenues are recognized for the sale of crude oil and condensate, natural gas liquids (NGLs) and natural gas at the point control of the product is transferred to the customer, typically when production is delivered and title or risk of loss transfers to the customer. Arrangements for such sales are evidenced by signed contracts with prices typically based on stated market indices, with certain adjustments for product quality and geographic location. As EOG typically invoices customers shortly after performance obligations have been fulfilled, contract assets and contract liabilities are not recognized. The balances of accounts receivable from contracts with customers on January 1, 2018 and June 30, 2018, were $1,343 million and $1,608 million, respectively, and are included in Accounts Receivable, Net on the Condensed Consolidated Balance Sheets. Losses incurred on receivables from contracts with customers are infrequent and have been immaterial.

Crude Oil and Condensate. EOG sells its crude oil and condensate production at the wellhead or further downstream at a contractually-specified delivery point. Revenue is recognized when control transfers to the customer. Any costs incurred prior to the transfer of control, such as gathering and transportation, are recognized as Operating Expenses.

Natural Gas Liquids. EOG delivers certain of its natural gas production to either EOG-owned processing facilities or third-party processing facilities, where extraction of NGLs occurs. For EOG-owned facilities, revenue is recognized after processing upon transfer of NGLs to a customer. For third-party facilities, extracted NGLs are sold to the owner of the processing facility at the tailgate, or EOG takes possession and sells the extracted NGLs at the tailgate or exercises its option to sell further downstream to various customers.

Under typical arrangements, sales of NGLs are recognized when control transfers after processing occurs either at the tailgate of the processing plant or further downstream. EOG recognizes revenues based on contract terms which reflect prevailing market prices, with processing fees recognized as Gathering and Processing Costs.

Natural Gas. EOG sells its natural gas production either at the wellhead or further downstream at a contractually-specified delivery point. In connection with the extraction of NGLs, EOG sells residue gas under separate agreements. Typically, EOG takes possession of the natural gas at the tailgate of the processing facility and sells it at the tailgate or further downstream. In each case, EOG recognizes revenues when control transfers to the customer, based on contract terms which reflect prevailing market prices.

Gathering, Processing and Marketing. Gathering, processing and marketing revenues represent sales of third-party crude oil and condensate, NGLs and natural gas, as well as fees associated with processing and gathering third-party natural gas and revenues from sales of EOG-owned sand. EOG evaluates whether it is the principal or agent under these transactions. As control of the underlying commodity is transferred to EOG prior to the gathering, processing and marketing activities, EOG considers itself the principal of these arrangements. Accordingly, EOG recognizes these transactions on a gross basis. Purchases of third-party

-7-

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


commodities are recorded as Marketing Costs, with sales of third-party commodities and fees received for gathering and processing recorded as Gathering, Processing and Marketing revenues.

Recently Issued Accounting Standards. In March 2018, the Financial Accounting Standards Board (FASB) issued ASU 2018-05, "Income Taxes (Topic 740) - Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118" (ASU 2018-05). In December 2017, the United States (U.S.) enacted the Tax Cuts and Jobs Act (TCJA), which made significant changes to U.S. federal income tax law. Shortly after enactment of the TCJA, the SEC staff issued Staff Accounting Bulletin No. 118 (SAB 118), which provides guidance on accounting for the impact of the TCJA. ASU 2018-05 codified various paragraphs of SAB 118 and was effective upon issuance. Under SAB 118, an entity would use a similar approach as the measurement period provided in the Business Combinations Topic of the Accounting Standards Codification (ASC). An entity will recognize those matters for which the accounting can be completed. For matters that have not been completed, the entity would either (1) recognize provisional amounts to the extent that they are reasonably able to be estimated and adjust them over time as more information becomes available or (2) for any specific income tax effects of the TCJA for which a reasonable estimate cannot be determined, continue to apply the Income Taxes Topic of the ASC on the basis of the provisions of the tax laws that were in effect immediately before the TCJA was signed into law. EOG has prepared its condensed consolidated financial statements for the three and six months ended June 30, 2018 in accordance with ASU 2018-05. EOG expects to have all provisional amounts finalized by the fourth quarter of 2018.

As discussed in EOG's 2017 Annual Report, provisional amounts were recorded for the impact of the statutory rate reduction from 35% to 21% and the deemed repatriation tax on foreign earnings. EOG has not made any measurement period adjustments related to these items during the three and six months ended June 30, 2018, because the foreign earnings and profits study has not been completed and the impact of certain tax elections on EOG's 2017 federal tax filings have not been fully analyzed.

Additionally, EOG recorded a provisional amount in 2017 for its refundable alternative minimum tax (AMT) credits due to the lack of guidance, at that time, on whether any portion of these credits would be sequestered due to a federal budgetary provision. In the first quarter of 2018, the Internal Revenue Service (IRS) affirmed that any refundable AMT credits resulting from the TCJA would be subject to sequestration. EOG does not expect further clarification from the IRS or Office of Management and Budget and therefore considers the accounting for sequestration on its refundable AMT credits complete.

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 certain 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." In January 2018, the FASB issued ASU 2018-01, "Leases (Topic 842) - Land Easement Practical Expedient for Transition to Topic 842" (ASU 2018-01), which permits an entity an optional election to not evaluate under ASU 2016-02 those existing or expired land easements that were not previously accounted for as leases prior to the adoption of ASU 2016-02. Additionally, in July 2018, the FASB issued ASU 2018-11, “Leases (Topic 842) - Targeted Improvements” (ASU 2018-11), which permits an entity (i) to apply the provisions of ASU 2016-02 at the adoption date instead of the earliest period presented in the financial statements, and, as a lessor, (ii) to account for lease and nonlease components as a single component as the nonlease components would otherwise be accounted for under the provisions of ASU 2014-09. ASU 2016-02 and other related ASUs are effective for interim and annual periods beginning after December 31, 2018, and early application is permitted. Based on the provisions of ASU 2018-11 and other related ASUs, lessees and lessors may recognize and measure leases at the beginning of the earliest period presented in the financial statements, defined as the effective date, using a modified retrospective approach, or at the adoption date by recognizing a cumulative-effect adjustment to the opening balance of retained earnings.
  
EOG is continuing its assessment of ASU 2016-02 by implementing its project plan, evaluating certain operational and corporate policies and processes, further defining its population of leases and reviewing numerous contracts. EOG plans to elect the package of practical expedients within ASU 2016-02 that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases, or (iii) initial direct costs for any existing leases. Additionally, EOG plans to elect the practical expedient under ASU 2018-01 and not evaluate existing or expired land easements not previously accounted for as leases prior to the effective date. EOG does not intend to early-adopt ASU 2016-02 and other related ASUs and has not determined which transition method it will use.


-8-

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


2.    Stock-Based Compensation

As more fully discussed in Note 7 to the Consolidated Financial Statements included in EOG's 2017 Annual Report, EOG maintains various stock-based compensation plans. Stock-based compensation expense is included on the Condensed Consolidated Statements of Income and Comprehensive Income based upon the job function of the employees receiving the grants as follows (in millions):
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2018
 
2017
 
2018
 
2017
Lease and Well
$
11.4

 
$
9.6

 
$
24.2

 
$
20.5

Gathering and Processing Costs
0.1

 
0.2

 
0.2

 
0.4

Exploration Costs
5.7

 
5.3

 
12.6

 
11.5

General and Administrative
14.6

 
12.5

 
30.3

 
25.7

Total
$
31.8

 
$
27.6

 
$
67.3

 
$
58.1


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, 2018, approximately 16.9 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.

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 $11.7 million and $11.1 million during the three months ended June 30, 2018 and 2017, respectively, and $23.7 million and $22.1 million during the six months ended June 30, 2018 and 2017, 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, 2018 and 2017 are as follows:
 
Stock Options/SARs
 
ESPP
 
Six Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2018
 
2017
 
2018
 
2017
Weighted Average Fair Value of Grants
$
29.18

 
$
26.64

 
$
23.27

 
$
24.28

Expected Volatility
28.88
%
 
30.46
%
 
22.04
%
 
30.33
%
Risk-Free Interest Rate
2.23
%
 
1.39
%
 
1.60
%
 
0.65
%
Dividend Yield
0.67
%
 
0.68
%
 
0.66
%
 
0.69
%
Expected Life
5.0 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.


-9-

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


The following table sets forth stock option and SAR transactions for the six-month periods ended June 30, 2018 and 2017 (stock options and SARs in thousands):
 
Six Months Ended 
 June 30, 2018
 
Six Months Ended 
 June 30, 2017
 
Number of
Stock
Options/SARs
 
Weighted
Average
Grant
Price
 
Number of
Stock
Options/SARs
 
Weighted
Average
Grant
Price
Outstanding at January 1
9,103

 
$
83.89

 
9,850

 
$
75.53

Granted
32

 
110.17

 
16

 
96.41

Exercised (1)
(1,662
)
 
71.33

 
(783
)
 
57.05

Forfeited
(124
)
 
92.07

 
(189
)
 
89.40

Outstanding at June 30 (2)
7,349

 
$
86.71

 
8,894

 
$
76.90

Vested or Expected to Vest (3)
7,006

 
$
86.44

 
8,594

 
$
76.53

Exercisable at June 30 (4)
2,938

 
$
78.74

 
4,973

 
$
68.43


(1)
The total intrinsic value of stock options/SARs exercised for the six months ended June 30, 2018 and 2017 was $74.5 million and $33.5 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, 2018 and 2017 was $277.2 million and $147.8 million, respectively. At June 30, 2018 and 2017, the weighted average remaining contractual life was 4.3 years and 3.6 years, respectively.
(3)
The total intrinsic value of stock options/SARs vested or expected to vest at June 30, 2018 and 2017 was $266.2 million and $145.7 million, respectively. At June 30, 2018 and 2017, the weighted average remaining contractual life was 4.3 years and 3.5 years, respectively.
(4)
The total intrinsic value of stock options/SARs exercisable at June 30, 2018 and 2017 was $134.2 million and $120.9 million, respectively. At June 30, 2018 and 2017, the weighted average remaining contractual life was 2.7 years and 2.2 years, respectively.

At June 30, 2018, unrecognized compensation expense related to non-vested stock option, SAR and ESPP grants totaled $76.9 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 1.9 years.

Restricted Stock and Restricted Stock Units. Employees may be granted restricted (non-vested) stock and/or restricted stock units without cost to them. Stock-based compensation expense related to restricted stock and restricted stock units totaled $19.0 million and $15.6 million for the three months ended June 30, 2018 and 2017, respectively, and $41.3 million and $34.2 million for the six months ended June 30, 2018 and 2017, respectively.

The following table sets forth restricted stock and restricted stock unit transactions for the six-month periods ended June 30, 2018 and 2017 (shares and units in thousands):
 
Six Months Ended 
 June 30, 2018
 
Six Months Ended 
 June 30, 2017
 
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
3,905

 
$
88.57

 
3,962

 
$
79.63

Granted
309

 
103.52

 
437

 
98.97

Released (1)
(331
)
 
69.55

 
(407
)
 
63.20

Forfeited
(120
)
 
91.28

 
(143
)
 
83.92

Outstanding at June 30 (2)
3,763

 
$
91.39

 
3,849

 
$
83.40

 
(1)
The total intrinsic value of restricted stock and restricted stock units released for the six months ended June 30, 2018 and 2017 was $34.9 million and $40.4 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, 2018 and 2017 was $468.2 million and $348.4 million, respectively.


-10-

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


At June 30, 2018, unrecognized compensation expense related to restricted stock and restricted stock units totaled $153.2 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.1 years.

Performance Units and Performance Stock. EOG has granted performance units and/or performance stock (collectively, 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. The fair value of the Performance Awards is estimated using a Monte Carlo simulation. Stock-based compensation expense related to the Performance Award grants totaled $1.1 million and $0.9 million for the three-month periods ended June 30, 2018 and 2017, respectively, and $2.3 million and $1.8 million for the six-month periods ended June 30, 2018 and 2017, respectively.

The following table sets forth the Performance Awards transactions for the six-month periods ended June 30, 2018 and 2017:
 
Six Months Ended 
 June 30, 2018
 
Six Months Ended 
 June 30, 2017
 
Number of
Units
 
Weighted
Average
Price per
Grant Date
 
Number of
Units
 
Weighted
Average
Price per
Grant Date
Outstanding at January 1
502,331

 
$
90.96

 
545,290

 
$
80.92

Granted

 

 

 

Granted for Performance Multiple (1)
71,805

 
101.87

 
118,834

 
84.43

Released (2)

 

 
(89,224
)
 
84.43

Forfeited

 

 

 

Outstanding at June 30 (3)
574,136

(4)
$
92.33

 
574,900

 
$
81.10

 
(1)
Upon completion of the Performance Period for the Performance Awards granted in 2014 and 2013, a performance multiple of 200% was applied to each of the grants resulting in additional grants of Performance Awards in February 2018 and February 2017, respectively.
(2)
The total intrinsic value of Performance Awards released during the six months ended June 30, 2017 was approximately $9.0 million. The intrinsic value is based upon the closing price of EOG's common stock on the date the Performance Awards are released.
(3)
The total intrinsic value of Performance Awards outstanding at June 30, 2018 and 2017 was approximately $71.4 million and $52.0 million, respectively.
(4)
Upon the application of the relevant performance multiple at the completion of each of the remaining Performance Periods, a minimum of 292,054 and a maximum of 856,218 Performance Awards could be outstanding.

At June 30, 2018, unrecognized compensation expense related to Performance Awards totaled $6.0 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 1.5 years.


-11-

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


3.    Net Income Per Share

The following table sets forth the computation of Net Income Per Share for the three-month and six-month periods ended June 30, 2018 and 2017 (in thousands, except per share data):
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2018
 
2017
 
2018
 
2017
Numerator for Basic and Diluted Earnings Per Share -
 
 
 
 
 
 
 
Net Income
$
696,731

 
$
23,053

 
$
1,335,320

 
$
51,570

Denominator for Basic Earnings Per Share -
 

 
 

 
 

 
 

Weighted Average Shares
576,135

 
574,439

 
575,953

 
574,162

Potential Dilutive Common Shares -
 

 
 

 
 

 
 

Stock Options/SARs
1,365

 
1,452

 
1,237

 
1,669

Restricted Stock/Units and Performance Units/Stock
2,875

 
2,592

 
2,817

 
2,742

Denominator for Diluted Earnings Per Share -
 

 
 

 
 

 
 

Adjusted Diluted Weighted Average Shares
580,375

 
578,483

 
580,007

 
578,573

Net Income Per Share
 

 
 

 
 

 
 

Basic
$
1.21

 
$
0.04

 
$
2.32

 
$
0.09

Diluted
$
1.20

 
$
0.04

 
$
2.30

 
$
0.09


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 were zero and 3.4 million shares for the three months ended June 30, 2018 and 2017, respectively, and were zero and 2.0 million shares, respectively, for the six months ended June 30, 2018 and 2017, respectively.

4.    Supplemental Cash Flow Information

Net cash paid for interest and income taxes was as follows for the six-month periods ended June 30, 2018 and 2017 (in thousands):
 
Six Months Ended 
 June 30,
 
2018
 
2017
Interest (1)
$
133,148

 
$
136,733

Income Taxes, Net of Refunds Received
$
62,777

 
$
98,157

 
(1)
Net of capitalized interest of $11 million and $14 million for the six months ended June 30, 2018 and 2017, respectively.

EOG's accrued capital expenditures at June 30, 2018 and 2017 were $724 million and $488 million, respectively.

Non-cash investing activities for the six months ended June 30, 2018, included additions of $83 million to EOG's oil and gas properties as a result of property exchanges and an addition of $48 million to EOG's other property, plant and equipment in connection with a capital lease transaction in the Permian Basin. Non-cash investing activities for the six months ended June 30, 2017, included additions of $154 million to EOG's oil and gas properties as a result of property exchanges.


-12-

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, 2018 and 2017 (in thousands):
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
 
2018
 
2017
 
2018
 
2017
Operating Revenues and Other
 
 
 
 
 
 
 
United States
$
4,114,610

 
$
2,530,885

 
$
7,685,744

 
$
5,050,734

Trinidad
81,611

 
72,299

 
162,624

 
146,222

Other International (1)
41,856

 
9,288

 
70,871

 
26,081

Total
$
4,238,077

 
$
2,612,472

 
$
7,919,239

 
$
5,223,037

Operating Income (Loss)
 

 
 

 
 

 
 

United States
$
946,883

 
$
130,314

 
$
1,792,736

 
$
249,845

Trinidad
27,821

 
32,360

 
68,118

 
48,773

Other International (1)
(9,773
)
 
(34,766
)
 
(21,335
)
 
(62,964
)
Total
964,931

 
127,908

 
1,839,519

 
235,654

Reconciling Items
 

 
 

 
 

 
 

Other Income (Expense), Net
(8,551
)
 
4,972

 
(7,824
)
 
8,123

Interest Expense, Net
(63,444
)
 
(70,413
)
 
(125,400
)
 
(141,928
)
Income Before Income Taxes
$
892,936

 
$
62,467

 
$
1,706,295

 
$
101,849

 
(1)
Other International primarily consists of EOG's United Kingdom, China and Canada operations.

Total assets by reportable segment are presented below at June 30, 2018 and December 31, 2017 (in thousands):
 
At
June 30,
2018
 
At
December 31,
2017
Total Assets
 
 
 
United States
$
31,114,907

 
$
28,312,599

Trinidad
624,358

 
974,477

Other International (1)
353,115

 
546,002

Total
$
32,092,380

 
$
29,833,078

 
(1)
Other International primarily consists of EOG's United Kingdom, China and Canada operations.


-13-

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, 2018 and 2017 (in thousands):
 
Six Months Ended 
 June 30,
 
2018
 
2017
Carrying Amount at January 1
$
946,848

 
$
912,926

Liabilities Incurred
25,496

 
19,276

Liabilities Settled (1)
(8,184
)
 
(28,726
)
Accretion
17,941

 
17,010

Revisions
(148
)
 
3,646

Foreign Currency Translations
(547
)
 
3,808

Carrying Amount at June 30
$
981,406

 
$
927,940

 
 
 
 
Current Portion
$
18,892

 
$
33,922

Noncurrent Portion
$
962,514

 
$
894,018

 
(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, 2018, are presented below (in thousands):
 
Six Months Ended 
 June 30, 2018
Balance at January 1
$
2,167

Additions Pending the Determination of Proved Reserves
3,512

Reclassifications to Proved Properties
(5,250
)
Costs Charged to Expense
(429
)
Balance at June 30
$


At June 30, 2018, all capitalized exploratory well costs had been capitalized for periods of less than one year.

8.    Commitments and Contingencies

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


-14-

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


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, 2018 and 2017, EOG's total costs recognized for these pension plans were $20.2 million and $18.4 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 and Common Stock

Long-Term Debt. During the six months ended June 30, 2018, EOG utilized commercial paper borrowings, bearing market interest rates, for various corporate financing purposes. EOG did not utilize any such borrowings during the six months ended June 30, 2017. At June 30, 2018 and December 31, 2017, EOG had no outstanding commercial paper borrowings or uncommitted credit facility borrowings. The average borrowings outstanding under the commercial paper program were $17 million and zero during the six months ended June 30, 2018 and 2017, respectively. The weighted average interest rate for commercial paper borrowings during the six months ended June 30, 2018, was 1.97%.

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, 2018 and December 31, 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 at June 30, 2018, would have been 3.09% and 5.00%, respectively.
Common Stock. On August 2, 2018, EOG's Board of Directors increased the quarterly cash dividend on the common stock from the previous $0.1850 per share to $0.22 per share, effective beginning with the dividend to be paid on October 31, 2018, to stockholders of record as of October 17, 2018.

-15-

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 2017 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, 2018 and December 31, 2017 (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, 2018
 

 
 

 
 

 
 

Financial Assets:
 

 
 

 
 

 
 

Natural Gas Swaps
$

 
$

 
$

 
$

Natural Gas Options

 
2

 

 
2

Crude Oil Basis Swaps

 
83

 

 
83

Financial Liabilities:
 
 
 
 
 
 
 
Crude Oil Swaps
$

 
$
261

 
$

 
$
261

 
 
 
 
 
 
 
 
At December 31, 2017
 
 
 
 
 
 
 
Financial Assets:
 
 
 
 
 
 
 
Natural Gas Swaps
$

 
$
2

 
$

 
$
2

Natural Gas Options/Collars

 
6

 

 
6

Financial Liabilities:
 
 
 
 
 
 
 
Crude Oil Swaps
$

 
$
38

 
$

 
$
38

Crude Oil Basis Swaps

 
19

 

 
19


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 $163 million were written down to their fair value of $131 million, resulting in pretax impairment charges of $32 million for the six months ended June 30, 2018. Included in the $32 million pretax impairment charges are $21 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, 2018 and December 31, 2017, EOG had outstanding $6,390 million aggregate principal amount of senior notes, which had estimated fair values at such dates of approximately $6,419 million and $6,602 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.


-16-

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 2017 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 has entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma (Midland Differential). Presented below is a comprehensive summary of EOG's Midland Differential basis swap contracts for the six months ended June 30, 2018. 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.

 
Midland Differential Basis Swap Contracts
 
 
 
Volume (Bbld)
 
Weighted Average Price Differential
($/Bbl)
 
 
 
2018
 
 
 
 
 
January 1, 2018 through July 31, 2018 (closed)
 
15,000

 
$
1.063

 
August 1, 2018 through December 31, 2018
 
15,000

 
1.063

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

 
$
1.075



-17-

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


EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in the U.S. Gulf Coast and Cushing, Oklahoma (Gulf Coast Differential). Presented below is a comprehensive summary of EOG's Gulf Coast Differential basis swap contracts for the six months ended June 30, 2018. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts.

 
Gulf Coast Differential Basis Swap Contracts
 
 
 
Volume (Bbld)
 
Weighted Average Price Differential
($/Bbl)
 
 
 
2018
 
 
 
 
 
January 1, 2018 through July 31, 2018 (closed)
 
37,000

 
$
3.818

 
August 1, 2018 through December 31, 2018
 
37,000

 
3.818

 
 
 
 
 
 
 
2019
 
 
 
 
 
January 1, 2019 through December 31, 2019
 
8,000

 
$
5.660


Presented below is a comprehensive summary of EOG's crude oil price swap contracts for the six months ended June 30, 2018, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

Crude Oil Price Swap Contracts
 
 
Volume (Bbld)
 
Weighted Average Price ($/Bbl)
2018
 
 
 
 
January 1, 2018 through June 30, 2018 (closed)
 
134,000

 
$
60.04

July 1, 2018 through December 31, 2018
 
134,000

 
60.04


Presented below is a comprehensive summary of EOG's natural gas price swap contracts for the six months ended June 30, 2018, 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)
2018
 
 
 
 
March 1, 2018 through July 31, 2018 (closed)
 
35,000

 
$
3.00

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

 
3.00



-18-

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


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, 2018, 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)
2018
 
 
 
 
 
 
 
March 1, 2018 through July 31, 2018 (closed)
120,000

 
$
3.38

 
96,000

 
$
2.94

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

 
3.38

 
96,000

 
2.94



The following table sets forth the amounts and classification of EOG's outstanding financial derivative instruments at June 30, 2018 and December 31, 2017.  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, 2018
 
December 31, 2017
Asset Derivatives
 
 
 
 
 
 
Crude oil and natural gas derivative contracts -
 
 
 
 
 
 
Current portion
 
Assets from Price Risk Management Activities
 
$
2

 
$
8

Noncurrent portion
 
Other Assets
 
17

 

Liability Derivatives
 
 
 
 
 
 

Crude oil and natural gas derivative contracts -
 
 
 
 
 
 

Current portion
 
Liabilities from Price Risk Management Activities (1)
 
$
195

 
$
50

Noncurrent portion
 
Other Liabilities
 

 
7

 
(1)
The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $261 million, partially offset by gross assets of $66 million at June 30, 2018, and gross liabilities of $55 million, partially offset by gross assets of $5 million at December 31, 2017.


-19-

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 June 30, 2018 and December 31, 2017. EOG had no collateral posted and held no collateral at June 30, 2018 and December 31, 2017.

13.  Acquisitions and Divestitures

During the six months ended June 30, 2018, EOG recognized a net loss on asset dispositions of $(21) million, primarily due to non-cash exchanges of unproved leasehold in New Mexico and Wyoming as well as the disposition of inventory and other assets, and received proceeds of approximately $8 million. 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.


-20-

        



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, natural gas liquids (NGLs) 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, NGLs and natural gas and the availability of other energy supplies, EOG is unable to predict what changes may occur in crude oil and condensate, NGLs, and natural gas prices in the future. The market prices of crude oil and condensate, NGLs and natural gas in 2018 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 six months of 2018, the average U.S. New York Mercantile Exchange (NYMEX) crude oil and natural gas prices were $65.41 per barrel and $2.86 per million British thermal units (MMBtu), respectively, representing an increase of 31% and a decrease of 11%, respectively, from the average NYMEX prices for the same period in 2017. Market prices for NGLs are influenced by crude oil prices and the composition of NGL production including ethane, propane and butane, among others. Based on its 2018 drilling and completion plans, EOG expects 2018 total production and total crude oil production to increase as compared to 2017.

During the first half of 2018, EOG continued to focus on increasing drilling, completion and operating efficiencies gained in prior years. In addition, EOG continued to look for opportunities to add drilling inventory through leasehold acquisitions, farm-ins, exchanges 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 76% of EOG's United States production during the first half of 2018 and 77% for the same period of 2017. During the first half of 2018, EOG's 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 and crude oil and condensate 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, the Banyan Field and the Sercan 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. During the second quarter of 2018, EOG completed seismic surveys in the SECC Block and will continue to process that data through the remainder of 2018.

Other International. In the United Kingdom, EOG produces crude oil from its 100% working interest East Irish Sea Conwy Development project (Conwy Project). Beginning in the second quarter of 2017, the Conwy Project was off-line due to facility improvements and operational issues. During the first quarter of 2018, production from the Conwy Project resumed.


-21-

        



In the Sichuan Basin, Sichuan Province, China, EOG constructed a new gas gathering line and completed the last previously-drilled well of a 2017 five-well development program in the Bajiaochang Field. The natural gas from the Bajiaochang Field is sold under a long-term contract to PetroChina. Additionally, EOG plans to drill five new wells in the Bajiaochang Field in the second half of 2018, of which four are expected to be completed by the end of 2018.

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 27% at June 30, 2018 and 28% at December 31, 2017. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

Total anticipated 2018 capital expenditures are estimated to range from approximately $5.4 billion to $5.8 billion, excluding acquisitions and non-cash transactions. The majority of 2018 expenditures will be focused on United States crude oil 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.



-22-

        



Results of Operations

The following review of operations for the three months and six months ended June 30, 2018 and 2017 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, 2018 vs. Three Months Ended June 30, 2017

Operating Revenues. During the second quarter of 2018, operating revenues increased $1,626 million, or 62%, to $4,238 million from $2,612 million for the same period of 2017. 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 2018 increased $1,149 million, or 63%, to $2,965 million from $1,816 million for the same period of 2017. EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $186 million for the second quarter of 2018 compared to net gains of $9 million for the same period of 2017. Gathering, processing and marketing revenues for the second quarter of 2018 increased $657 million, or 84%, to $1,436 million from $779 million for the same period of 2017. Net losses on asset dispositions were $6 million for the second quarter of 2018 compared to $9 million for the same period of 2017.


-23-

        



Wellhead volume and price statistics for the three-month periods ended June 30, 2018 and 2017 were as follows:
 
Three Months Ended 
 June 30,
 
2018
 
 
2017
Crude Oil and Condensate Volumes (MBbld) (1)
 
 
 
 
United States
379.2

 
 
333.1

Trinidad
0.8

 
 
0.8

Other International (2)
4.6

 
 
0.8

Total
384.6

 
 
334.7

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

 
 
 
United States
$
67.91

 
 
$
47.51

Trinidad
60.57

 
 
39.64

Other International (2)
70.88

 
 
35.13

Composite
67.93

 
 
47.46

Natural Gas Liquids Volumes (MBbld) (1)
 
 
 
 
United States
112.9

 
 
86.6

Other International (2)

 
 

Total
112.9

 
 
86.6

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

 
 
 

United States
$
27.86

 
 
$
18.65

Other International (2)

 
 

Composite
27.86

 
 
18.65

Natural Gas Volumes (MMcfd) (1)
 
 
 
 
United States
914

 
 
755

Trinidad
282

 
 
320

Other International (2)
32

 
 
21

Total
1,228

 
 
1,096

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

 
 
 

United States
$
2.56

 
 
$
2.14

Trinidad
2.98

 
 
2.40

Other International (2)
4.10

 
 
3.66

Composite
2.69

(4) 
 
2.25

Crude Oil Equivalent Volumes (MBoed) (5)
 
 
 
 
United States
644.4

 
 
545.6

Trinidad
47.8

 
 
54.1

Other International (2)
10.0

 
 
4.2

Total
702.2

 
 
603.9

 
 
 
 
 
Total MMBoe (5)
63.9

 
 
55.0

 
(1)
Thousand barrels per day or million cubic feet per day, as applicable.
(2)
Other International includes EOG's United Kingdom, China and Canada operations.
(3)
Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 12 to the Condensed Consolidated Financial Statements).
(4)
Includes a positive revenue adjustment of $0.39 per Mcf related to the adoption of ASU 2014-09, "Revenue From Contracts with Customers" (ASU 2014-09) (see Note 1 to the Condensed Consolidated Financial Statements). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees relating to certain processing and marketing agreements as Gathering and Processing Costs, instead of a deduction to Natural Gas revenues.
(5)
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.


-24-

        




Wellhead crude oil and condensate revenues for the second quarter of 2018 increased $933 million, or 65%, to $2,378 million from $1,445 million for the same period of 2017. The increase was primarily due to a higher composite wellhead crude oil and condensate price ($717 million) and an increase of 50 MBbld, or 15%, in wellhead crude oil and condensate production ($216 million). Increased production was primarily due to increases in the Permian Basin and the Eagle Ford. EOG's composite wellhead crude oil and condensate price for the second quarter of 2018 increased 43% to $67.93 per barrel compared to $47.46 per barrel for the same period of 2017.

NGL revenues for the second quarter of 2018 increased $139 million, or 95%, to $286 million from $147 million for the same period of 2017 due primarily to a higher composite average price ($94 million) and an increase of 26 MBbld, or 30%, in production ($45 million). Increased production was primarily in the Permian Basin and the Eagle Ford. EOG's composite NGL price for the second quarter of 2018 increased 49% to $27.86 per barrel compared to $18.65 per barrel for the same period of 2017.

Wellhead natural gas revenues for the second quarter of 2018 increased $77 million, or 34%, to $301 million from $224 million for the same period of 2017. The increase was due to a higher composite wellhead natural gas price ($50 million) and an increase in natural gas deliveries ($27 million). Natural gas deliveries for the second quarter of 2018 increased 132 MMcfd, or 12%, compared to the same period of 2017 due primarily to higher deliveries in the United States resulting from increased production of associated natural gas from the Permian Basin and the Eagle Ford, partially offset by lower natural gas deliveries in Trinidad. EOG's composite wellhead natural gas price for the second quarter of 2018 increased 20% to $2.69 per Mcf compared to $2.25 per Mcf for the same period of 2017. This increase in composite wellhead natural gas prices includes a positive revenue adjustment of $0.39 per Mcf related to the adoption of ASU 2014-09.

During the second quarter of 2018, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $186 million compared to net gains of $9 million for the same period of 2017. During the second quarter of 2018, net cash paid for settlements of financial commodity derivative contracts was $66 million compared to net cash received of $0.7 million for the same period of 2017.

Gathering, processing and marketing revenues are revenues generated from sales of third-party crude oil, NGLs and natural gas, as well as fees associated with processing and gathering third-party natural gas and revenues from sales of EOG-owned sand. Purchases and sales of third-party crude oil and natural gas may be 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 to purchase third-party crude oil, natural gas and sand 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 2018 increased $28 million as compared to the same period of 2017 primarily due to higher margins on crude oil marketing activities.

Operating and Other Expenses.  For the second quarter of 2018, operating expenses of $3,273 million were $788 million higher than the $2,485 million incurred during the second quarter of 2017.  The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended June 30, 2018 and 2017:
 
Three Months Ended 
 June 30,
 
2018
 
2017
Lease and Well
$
4.92

 
$
4.64

Transportation Costs
2.78

 
3.39

Depreciation, Depletion and Amortization (DD&A) -
 
 
 
Oil and Gas Properties
12.83

 
15.22

Other Property, Plant and Equipment
0.45

 
0.52

General and Administrative (G&A)
1.63

 
1.97

Interest Expense, Net
0.99

 
1.28

Total (1)
$
23.60

 
$
27.02

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


-25-

        



The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, G&A and net interest expense for the three months ended June 30, 2018, compared to the same period of 2017, are set forth below. See "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 $315 million for the second quarter of 2018 increased $60 million from $255 million for the same prior year period primarily due to increased operating and maintenance costs ($42 million), lease and well administrative expenses ($13 million) and workover expenditures ($11 million), all in the United States, partially offset by decreased operating and maintenance costs in the United Kingdom ($7 million). Lease and well expenses increased in the United States primarily due to increased operating activities resulting in increased production.

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), the cost of dehydration (the cost associated with removing water from natural gas to meet pipeline requirements), gathering fees and fuel costs.

Transportation costs of $178 million for the second quarter of 2018 decreased $9 million from $186 million for the same prior year period primarily due to decreased transportation costs in the Barnett Shale ($16 million), Rocky Mountain area ($11 million) and the Eagle Ford ($6 million), partially offset by increased transportation costs in the Permian Basin ($27 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.

DD&A expenses for the second quarter of 2018 decreased $16 million to $849 million from $865 million for the same prior year period. DD&A expenses associated with oil and gas properties for the second quarter of 2018 were $17 million lower than the same prior year period. The decrease primarily reflects decreased unit rates in the United States ($167 million), partially offset by increased production in the United States ($144 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 from drilling and completions operations.

G&A expense of $104 million for the second quarter of 2018 decreased $5 million from $109 million for the same prior year period primarily due to decreased professional, legal and other services ($13 million), partially offset by increased employee-related expenses ($6 million).

Interest expense, net of $63 million for the second quarter of 2018 decreased $7 million compared to the same prior year period primarily due to repayment in September 2017 of the $600 million aggregate principal amount of 5.875% Senior Notes due 2017.

Gathering and processing costs represent operating and maintenance expenses and administrative expenses associated with operating EOG's gathering and processing assets and, beginning January 1, 2018, natural gas processing fees from third parties. EOG pays third parties to process a portion of its natural gas production to extract NGLs. See Note 1 to the Condensed Consolidated Financial Statements for discussion related to EOG's adoption of ASU 2014-09.


-26-

        



Gathering and processing costs increased $74 million to $109 million for the second quarter of 2018 compared to $35 million for the same prior year period primarily due to the adoption of ASU 2014-09 ($45 million) and increased operating costs in the Permian Basin ($12 million), the Eagle Ford ($10 million) and the United Kingdom ($5 million).

Exploration costs of $47 million for the second quarter of 2018 increased $12 million from $35 million for the same prior year period primarily due to increased geological and geophysical costs in Trinidad.

Impairments include amortization of unproved oil and gas property costs as well as impairments of proved oil and gas properties; other property, plant and equipment; and other assets. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment. 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 offers from third-party purchasers as the basis for determining fair value.

Impairments of $52 million for the second quarter of 2018 were $27 million lower than impairments for the same prior year period primarily due to decreased impairments of proved properties and other assets in the United States ($14 million) and decreased amortization of unproved property costs in the United States ($13 million), which was caused by a decrease in EOG's estimates of undeveloped properties not expected to be developed before lease expiration. EOG recorded impairments of proved properties, other property, plant and equipment and other assets of $10 million and $24 million for the second quarter of 2018 and 2017, respectively.

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

Taxes other than income for the second quarter of 2018 increased $64 million to $194 million (6.6% of wellhead revenues) compared to $130 million (7.2% 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 as a result of increased wellhead revenues in the United States.

Other income (expense), net for the second quarter of 2018 decreased $14 million compared to the same prior year period primarily due to an increase in foreign currency exchange losses ($8 million) and increased deferred compensation expense ($6 million).

EOG recognized an income tax provision of $196 million for the second quarter of 2018 compared to an income tax provision of $39 million in the second quarter of 2017, primarily due to an increase in pretax income. The net effective tax rate for 2018 decreased to 22% from 63% in 2017. The lower effective tax rate is mostly due to the reduction in the U.S. federal statutory tax rate to 21% in 2018 from 35% in 2017, foreign income in the United Kingdom for which no taxes are recorded due to valuation allowances and the absence of certain 2017 state income tax apportionment changes.


-27-

        



Six Months Ended June 30, 2018 vs. Six Months Ended June 30, 2017

Operating Revenues. During the first six months of 2018, operating revenues increased $2,696 million, or 52%, to $7,919 million from $5,223 million for the same period of 2017. Total wellhead revenues for the first six months of 2018 increased $1,956 million, or 54%, to $5,587 million from $3,631 million for the same period of 2017. During the first six months of 2018, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $246 million compared to net gains of $71 million for the same period of 2017. Gathering, processing and marketing revenues for the first six months of 2018 increased $1,033 million, or 69%, to $2,538 million from $1,505 million for the same period of 2017. Net losses on asset dispositions were $21 million for the first six months of 2018 compared to $26 million for the same period of 2017.


-28-

        



Wellhead volume and price statistics for the six-month periods ended June 30, 2018 and 2017 were as follows:
 
Six Months Ended 
 June 30,
 
 
2018
 
 
2017
 
Crude Oil and Condensate Volumes (MBbld)
 
 
 
 
 
United States
369.5

 
 
322.8

 
Trinidad
0.9

 
 
0.8

 
Other International
3.6

 
 
1.6

 
Total
374.0

 
 
325.2

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

 
 
 

 
United States
$
66.13

 
 
$
48.89

 
Trinidad
57.59

 
 
40.63

 
Other International
71.14

 
 
44.66

 
Composite
66.16

 
 
48.85

 
Natural Gas Liquids Volumes (MBbld)
 
 
 
 
 
United States
106.8

 
 
82.7

 
Other International

 
 

 
Total
106.8

 
 
82.7

 
Average Natural Gas Liquids Prices ($/Bbl)
 

 
 
 

 
United States
$
26.27

 
 
$
20.06

 
Other International

 
 

 
Composite
26.27

 
 
20.06

 
Natural Gas Volumes (MMcfd)
 
 
 
 
 
United States
884

 
 
742

 
Trinidad
288

 
 
314

 
Other International
30

 
 
21

 
Total
1,202

 
 
1,077

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

 
 
 

 
United States
$
2.65

 
 
$
2.23

 
Trinidad
2.93

 
 
2.48

 
Other International
4.22

 
 
3.71

 
Composite
2.76

(2)
 
2.33

 
Crude Oil Equivalent Volumes (MBoed)
 
 
 
 
 
United States
623.6

 
 
529.2

 
Trinidad
48.8

 
 
53.1

 
Other International
8.8

 
 
5.1

 
Total
681.2

 
 
587.4

 
 
 
 
 
 
 
Total MMBoe
123.3

 
 
106.3

 
 
(1)
Excludes the impact of financial commodity derivative instruments (see Note 12 to the Condensed Consolidated Financial Statements).
(2)
Includes a positive revenue adjustment of $0.40 per Mcf related to the adoption of ASU 2014-09 (see Note 1 to the Condensed Consolidated Financial Statements). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees relating to certain processing and marketing agreements as Gathering and Processing Costs, instead of a deduction to Natural Gas revenues.

-29-

        



Wellhead crude oil and condensate revenues for the first six months of 2018 increased $1,603 million, or 56%, to $4,479 million from $2,876 million for the same period of 2017 due primarily to a higher composite wellhead crude oil and condensate price ($1,172 million) and an increase of 49 MBbld, or 15%, in wellhead crude oil and condensate production ($431 million). Increased production was primarily due to increases in the Permian Basin and the Eagle Ford. EOG's composite wellhead crude oil and condensate price for the first six months of 2018 increased 35% to $66.16 per barrel compared to $48.85 per barrel for the same period of 2017.

NGL revenues for the first six months of 2018 increased $208 million, or 69%, to $508 million from $300 million for the same period of 2017 due primarily to a higher composite average price ($120 million) and an increase of 24 MBbld, or 29%, in NGL deliveries ($88 million) primarily in the Permian Basin and the Eagle Ford. EOG's composite NGL price for the first six months of 2018 increased 31% to $26.27 per barrel compared to $20.06 per barrel for the same period of 2017.

Wellhead natural gas revenues for the first six months of 2018 increased $146 million, or 32%, to $601 million from $455 million for the same period of 2017. The increase was due to a higher composite wellhead natural gas price ($93 million) and an increase in natural gas deliveries ($53 million). Natural gas deliveries for the first six months of 2018 increased 125 MMcfd, or 12%, compared to the same period of 2017 due primarily to higher deliveries in the United States resulting from increased production of associated natural gas from the Permian Basin and the Eagle Ford, partially offset by lower natural gas deliveries in Trinidad. EOG's composite wellhead natural gas price for the first six months of 2018 increased 18% to $2.76 per Mcf compared to $2.33 per Mcf for the same period of 2017. The increase in composite wellhead natural gas prices includes a positive revenue adjustment of $0.40 per Mcf related to the adoption of ASU 2014-09.

During the first six months of 2018, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $246 million compared to net gains of $71 million for the same period of 2017. During the first six months of 2018, net cash paid for settlements of financial commodity derivative contracts was $88 million compared to net cash received for settlements of financial commodity derivative contracts of $3 million for the same period of 2017. 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 2018 increased $33 million as compared to the same period of 2017 primarily due to higher margins on crude oil marketing activities.

Operating and Other Expenses. For the first six months of 2018, operating expenses of $6,080 million were $1,093 million higher than the $4,987 million incurred during the same period of 2017. The following table presents the costs per Boe for the six-month periods ended June 30, 2018 and 2017:
 
Six Months Ended 
 June 30,
 
2018
 
2017
Lease and Well
$
4.99

 
$
4.81

Transportation Costs
2.88

 
3.43

DD&A -
 
 
 
Oil and Gas Properties
12.49

 
15.28

Other Property, Plant and Equipment
0.46

 
0.54

G&A
1.61

 
1.94

Interest Expense, Net
1.02

 
1.33

Total (1)
$
23.45

 
$
27.33

 
(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 net interest expense for the six months ended June 30, 2018, compared to the same period of 2017 are set forth below. See "Operating Revenues" above for a discussion of wellhead volumes.


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Lease and well expenses of $615 million for the first six months of 2018 increased $104 million from $511 million for the same prior year period primarily due to higher operating and maintenance costs ($78 million), higher workover expenditures ($16 million) and higher lease and well administrative costs ($14 million), all in the United States, partially offset by lower operating and maintenance costs in the United Kingdom ($6 million). Lease and well expenses increased in the United States primarily due to increased operating activities resulting in increased production.

Transportation costs of $355 million for the first six months of 2018 decreased $10 million from $365 million for the same prior year period primarily due to decreased transportation costs in the Barnett Shale ($32 million), the Rocky Mountain area ($15 million) and the Eagle Ford ($12 million), partially offset by increased transportation costs in the Permian Basin ($52 million).

DD&A expenses for the first six months of 2018 decreased $84 million to $1,597 million from $1,681 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first six months of 2018 were $84 million lower than the same prior year period. The decrease primarily reflects decreased unit rates in the United States ($366 million), partially offset by increased production in the United States ($275 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 from drilling and completions operations.

G&A expenses of $199 million for the first six months of 2018 decreased $7 million from $206 million for the same prior year period primarily due to decreased professional, legal and other services ($15 million), partially offset by increased employee-related expenses ($5 million) and information systems costs ($4 million).

Interest expense, net of $125 million for the first six months of 2018 decreased $17 million compared to the same prior year period primarily due to repayment in September 2017 of the $600 million aggregate principal amount of 5.875% Senior Notes due 2017.

Gathering and processing costs for the first six months of 2018 increased $138 million to $211 million compared to the same prior year period primarily due to the adoption of ASU 2014-09 ($90 million) and increased operating costs in the Eagle Ford ($22 million) and the Permian Basin ($19 million).

Exploration costs of $82 million for the first six months of 2018 decreased $10 million from $92 million for the same prior year period primarily due to decreased geological and geophysical costs in the United States.

Impairments of $116 million for the first six months of 2018 were $156 million lower than impairments for the same prior year period primarily due to decreased impairments of proved properties and other assets in the United States ($129 million) and decreased amortization of unproved property costs in the United States ($27 million), which was caused by a decrease in EOG's estimates of undeveloped properties not expected to be developed before lease expiration. EOG recorded impairments of proved properties, other property, plant and equipment and other assets of $32 million and $161 million for the first six months of 2018 and 2017, respectively.

Taxes other than income for the first six months of 2018 increased $113 million to $373 million (6.7% of wellhead revenues) from $260 million (7.2% of wellhead revenues) for the same prior year period. The increase in taxes other than income was primarily due to increased severance/production taxes in the United States as a result of increased wellhead revenues.

Other income (expense), net for the first six months of 2018 decreased $16 million compared to the same prior year period primarily due to an increase in foreign currency exchange losses ($9 million) and increased deferred compensation expense ($6 million).

EOG recognized an income tax provision of $371 million for the first six months of 2018 compared to an income tax provision of $50 million for the same period in 2017, primarily due to an increase in pretax income. The net effective tax rate for the first six months of 2018 decreased to 22% from 49% for the first six months of 2017. The lower effective tax rate is mostly due to the reduction in the U.S. federal statutory tax rate to 21% in 2018 from 35% in 2017, foreign income in the United Kingdom for which no taxes are recorded due to valuation allowances and the absence of certain 2017 state income tax apportionment changes, partially offset by a reduction in tax benefits from stock-based compensation.