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Section 1: 10-Q (10-Q)

Document
 

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

 
FORM 10-Q
 

(Mark One)

ý            QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 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
395601104_image00001aa11.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 every Interactive Data File required to be submitted 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
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
 
579,903,041 (as of October 26, 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 
 September 30,
 
Nine Months Ended 
 September 30,
 
2018
 
2017
 
2018
 
2017
Operating Revenues and Other
 
 
 
 
 
 
 
Crude Oil and Condensate
$
2,655,278

 
$
1,451,410

 
$
7,134,114

 
$
4,326,925

Natural Gas Liquids
353,704

 
180,038

 
861,473

 
480,389

Natural Gas
311,713

 
220,402

 
912,324

 
675,012

Gains (Losses) on Mark-to-Market Commodity Derivative Contracts
(52,081
)
 
(6,606
)
 
(297,735
)
 
64,860

Gathering, Processing and Marketing
1,360,992

 
784,368

 
3,899,250

 
2,289,702

Gains (Losses) on Asset Dispositions, Net
115,944

 
(8,202
)
 
94,658

 
(33,876
)
Other, Net
36,074

 
23,434

 
96,779

 
64,869

Total
4,781,624

 
2,644,844

 
12,700,863

 
7,867,881

Operating Expenses
 

 
 

 
 

 
 

Lease and Well
321,568

 
251,943

 
936,236

 
762,906

Transportation Costs
196,027

 
183,565

 
550,781

 
548,635

Gathering and Processing Costs
114,063

 
32,590

 
324,577

 
105,480

Exploration Costs
32,823

 
30,796

 
115,137

 
122,401

Dry Hole Costs
358

 
50

 
5,260

 
77

Impairments
44,617

 
53,677

 
160,934

 
325,798

Marketing Costs
1,326,974

 
793,536

 
3,853,827

 
2,320,671

Depreciation, Depletion and Amortization
918,180

 
846,222

 
2,515,445

 
2,527,642

General and Administrative
111,284

 
111,717

 
310,065

 
317,462

Taxes Other Than Income
209,043

 
125,912

 
582,395

 
386,319

Total
3,274,937

 
2,430,008

 
9,354,657

 
7,417,391

Operating Income
1,506,687

 
214,836

 
3,346,206

 
450,490

Other Income (Expense), Net
3,308

 
226

 
(4,516
)
 
8,349

Income Before Interest Expense and Income Taxes
1,509,995

 
215,062

 
3,341,690

 
458,839

Interest Expense, Net
63,632

 
69,082

 
189,032

 
211,010

Income Before Income Taxes
1,446,363

 
145,980

 
3,152,658

 
247,829

Income Tax Provision
255,411

 
45,439

 
626,386

 
95,718

Net Income
$
1,190,952

 
$
100,541

 
$
2,526,272

 
$
152,111

Net Income Per Share
 

 
 

 
 

 
 

Basic
$
2.06

 
$
0.17

 
$
4.38

 
$
0.26

Diluted
$
2.05

 
$
0.17

 
$
4.35

 
$
0.26

Dividends Declared per Common Share
$
0.2200

 
$
0.1675

 
$
0.5900

 
$
0.5025

Average Number of Common Shares
 

 
 

 
 

 
 

Basic
577,254

 
574,783

 
576,431

 
574,370

Diluted
581,559

 
578,736

 
580,442

 
578,453

Comprehensive Income
 

 
 

 
 

 
 

Net Income
$
1,190,952

 
$
100,541

 
$
2,526,272

 
$
152,111

Other Comprehensive Income (Loss)
 

 
 

 
 

 
 

Foreign Currency Translation Adjustments
(1,952
)
 
355

 
(179
)
 
1,924

Other, Net of Tax
6

 
(25
)
 
18

 
(74
)
Other Comprehensive Income (Loss)
(1,946
)
 
330

 
(161
)
 
1,850

Comprehensive Income
$
1,189,006

 
$
100,871

 
$
2,526,111

 
$
153,961



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)
 
September 30,
2018
 
December 31,
2017
ASSETS
Current Assets
 
 
 
Cash and Cash Equivalents
$
1,274,132

 
$
834,228

Accounts Receivable, Net
2,151,247

 
1,597,494

Inventories
766,964

 
483,865

Assets from Price Risk Management Activities
1,569

 
7,699

Income Taxes Receivable
320,938

 
113,357

Other
302,242

 
242,465

Total
4,817,092

 
3,279,108

Property, Plant and Equipment
 

 
 

Oil and Gas Properties (Successful Efforts Method)
56,799,237

 
52,555,741

Other Property, Plant and Equipment
4,191,958

 
3,960,759

Total Property, Plant and Equipment
60,991,195

 
56,516,500

Less:  Accumulated Depreciation, Depletion and Amortization
(33,043,454
)
 
(30,851,463
)
Total Property, Plant and Equipment, Net
27,947,741

 
25,665,037

Deferred Income Taxes
16,880

 
17,506

Other Assets
856,023

 
871,427

Total Assets
$
33,637,736

 
$
29,833,078

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
 

 
 

Accounts Payable
$
2,435,773

 
$
1,847,131

Accrued Taxes Payable
249,234

 
148,874

Dividends Payable
126,829

 
96,410

Liabilities from Price Risk Management Activities
132,618

 
50,429

Current Portion of Long-Term Debt
1,262,874

 
356,235

Other
217,819

 
226,463

Total
4,425,147

 
2,725,542

 
 
 
 
Long-Term Debt
5,171,949

 
6,030,836

Other Liabilities
1,302,249

 
1,275,213

Deferred Income Taxes
4,199,921

 
3,518,214

Commitments and Contingencies (Note 8)


 


 
 
 
 
Stockholders' Equity
 

 
 

Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 580,308,937 Shares Issued at September 30, 2018 and 578,827,768 Shares Issued at December 31, 2017
205,803

 
205,788

Additional Paid in Capital
5,626,259

 
5,536,547

Accumulated Other Comprehensive Loss
(19,458
)
 
(19,297
)
Retained Earnings
12,778,104

 
10,593,533

Common Stock Held in Treasury, 478,042 Shares at September 30, 2018 and 350,961 Shares at December 31, 2017
(52,238
)
 
(33,298
)
Total Stockholders' Equity
18,538,470

 
16,283,273

Total Liabilities and Stockholders' Equity
$
33,637,736

 
$
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)
 
Nine Months Ended 
 September 30,
 
2018
 
2017
Cash Flows from Operating Activities
 
 
 
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
 
 
 
Net Income
$
2,526,272

 
$
152,111

Items Not Requiring (Providing) Cash
 

 
 

Depreciation, Depletion and Amortization
2,515,445

 
2,527,642

Impairments
160,934

 
325,798

Stock-Based Compensation Expenses
116,290

 
101,537

Deferred Income Taxes
681,702

 
114,850

(Gains) Losses on Asset Dispositions, Net
(94,658
)
 
33,876

Other, Net
15,314

 
(4,514
)
Dry Hole Costs
5,260

 
77

Mark-to-Market Commodity Derivative Contracts
 

 
 

Total (Gains) Losses
297,735

 
(64,860
)
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts
(180,228
)
 
4,730

Other, Net
1,652

 
270

Changes in Components of Working Capital and Other Assets and Liabilities
 

 
 

Accounts Receivable
(553,529
)
 
(25,445
)
Inventories
(286,817
)
 
(17,674
)
Accounts Payable
537,525

 
112,894

Accrued Taxes Payable
(36,891
)
 
(49,967
)
Other Assets
(103,334
)
 
(83,940
)
Other Liabilities
(14,776
)
 
(69,224
)
Changes in Components of Working Capital Associated with Investing and Financing Activities
95,484

 
(120,373
)
Net Cash Provided by Operating Activities
5,683,380

 
2,937,788

Investing Cash Flows
 

 
 

Additions to Oil and Gas Properties
(4,571,932
)
 
(2,927,988
)
Additions to Other Property, Plant and Equipment
(202,384
)
 
(139,558
)
Proceeds from Sales of Assets
11,582

 
191,593

Other Investing Activities
(19,993
)
 

Changes in Components of Working Capital Associated with Investing Activities
(95,541
)
 
120,469

Net Cash Used in Investing Activities
(4,878,268
)
 
(2,755,484
)
Financing Cash Flows
 

 
 

Long-Term Debt Repayments

 
(600,000
)
Dividends Paid
(311,075
)
 
(289,261
)
Treasury Stock Purchased
(58,558
)
 
(50,374
)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan
12,098

 
11,174

Repayment of Capital Lease Obligation
(5,052
)
 
(4,897
)
Changes in Components of Working Capital Associated with Financing Activities
57

 
(96
)
Net Cash Used in Financing Activities
(362,530
)
 
(933,454
)
Effect of Exchange Rate Changes on Cash
(2,678
)
 
(2,607
)
Increase (Decrease) in Cash and Cash Equivalents
439,904

 
(753,757
)
Cash and Cash Equivalents at Beginning of Period
834,228

 
1,599,895

Cash and Cash Equivalents at End of Period
$
1,274,132

 
$
846,138


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 nine months ended September 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 as 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 nine months ended September 30, 2018, were as follows (in thousands):

-6-

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


 
Three Months Ended 
 September 30, 2018
 
Nine Months Ended 
 September 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
$
2,655,278

 
$
2,655,278

 
$

 
$
7,134,114

 
$
7,134,114

 
$

Natural Gas Liquids
353,704

 
352,084

 
1,620

 
861,473

 
856,628

 
4,845

Natural Gas
311,713

 
256,169

 
55,544

 
912,324

 
770,441

 
141,883

Gathering, Processing and Marketing
1,360,992

 
1,355,909

 
5,083

 
3,899,250

 
3,883,222

 
16,028

Total Operating Revenues and Other
4,781,624

 
4,719,377

 
62,247

 
12,700,863

 
12,538,107

 
162,756

Operating Expenses
 
 
 
 
 
 
 
 
 
 
 
Gathering and Processing Costs
114,063

 
56,899

 
57,164

 
324,577

 
177,849

 
146,728

Marketing Costs
1,326,974

 
1,321,891

 
5,083

 
3,853,827

 
3,837,799

 
16,028

Total Operating Expenses
3,274,937

 
3,212,690

 
62,247

 
9,354,657

 
9,191,901

 
162,756

Operating Income
1,506,687

 
1,506,687

 

 
3,346,206

 
3,346,206

 


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 September 30, 2018, were $1,343 million and $1,812 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 based on contract terms which reflect prevailing market prices. 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 for third-party facilities, revenue is recognized after processing upon the transfer of control of the NGLs, 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.


-7-

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


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 gathering and processing 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 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 nine months ended September 30, 2018 in accordance with ASU 2018-05. As discussed in EOG’s 2017 Annual Report, provisional amounts were recorded for tax accruals of certain aspects of the TCJA. EOG has updated and finalized the 2017 U.S. federal provisional amounts. The 2017 state provisional amounts will be finalized in the fourth quarter of 2018.

During the third quarter of 2018, EOG filed its consolidated 2017 U.S. federal income tax return, along with certain tax elections, and finalized its foreign earnings and profits study. The deemed repatriation tax decreased from the provisional amount of $179 million to $40 million mostly as a result of reducing the repatriation taxable income by net operating losses (NOLs), which had previously been expected to be utilized in future years. EOG is no longer electing to pay the repatriation tax in installments over eight years after considering recent Internal Revenue Service (IRS) guidance which indicated that no tax refunds would be issued until the entire repatriation tax liability is satisfied regardless of an installment election. EOG has reviewed the tax consequences of the repatriation tax on its outside basis differences in its investment in non-U.S. subsidiaries and has confirmed that no U.S. federal deferred tax liability is required at this time.

EOG has analyzed the impact of the new "global intangible low-taxed income" (GILTI) inclusion and, while no taxable income inclusion is required in 2018, EOG may become subject to GILTI inclusion in future years and will treat any resulting tax as a period expense.

The remeasurement of U.S. deferred tax assets and liabilities resulted in a provisional tax benefit of $2.2 billion in 2017, which was increased by approximately $52 million in the third quarter of 2018 due to the utilization of the aforementioned NOLs at the 2017 U.S. federal corporate income tax rate of 35% instead of the future tax rate of 21%. This additional tax benefit along with other less significant tax reform adjustments has lowered the 2018 year-to-date effective tax rate approximately two percentage points.

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 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.


-8-

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


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, including a lease accounting software solution. EOG has assessed the scope of its current contractual arrangements, reviewed the majority of its existing contracts and is continuing to evaluate certain operational and corporate policies and processes in light of these findings. EOG enters into contracts for drilling rig services, fracturing services, compression, real estate and other contracts which contain equipment and other assets used in its exploration, development and production activities and corporate functions. Certain of these contracts are anticipated to require recognition of a right-of-use asset and related lease liability. At this time, the impact upon adoption of ASU 2016-02 and other related ASUs is not quantifiable, but is expected to significantly impact EOG’s consolidated balance sheet by increasing assets and liabilities related to operating leases. EOG plans to elect the practical expedient under ASU 2018-11 and apply the provisions of ASU 2016-02 on the adoption date, January 1, 2019. Additionally, 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, but does not plan to elect the practical expedient of hindsight when determining the lease term of existing contracts at the effective date. EOG also 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.

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 
 September 30,
 
Nine Months Ended 
 September 30,
 
2018
 
2017
 
2018
 
2017
Lease and Well
$
12.9

 
$
9.5

 
$
37.1

 
$
30.0

Gathering and Processing Costs
0.1

 
0.1

 
0.3

 
0.5

Exploration Costs
5.8

 
4.7

 
18.4

 
16.1

General and Administrative
30.2

 
29.2

 
60.5

 
54.9

Total
$
49.0

 
$
43.5

 
$
116.3

 
$
101.5


The Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (2008 Plan) provides for grants of stock options, stock-settled stock appreciation rights (SARs), restricted stock and restricted stock units, performance units and performance stock and other stock-based awards.

At September 30, 2018, approximately 13.7 million common shares remained available for grant under the 2008 Plan. EOG's policy is to issue shares related to 2008 Plan grants from previously authorized unissued shares or treasury shares to the extent treasury shares are available.

-9-

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



Stock Options and Stock-Settled Stock Appreciation Rights and Employee Stock Purchase Plan. The fair value of stock option grants and SAR grants is estimated using the Hull-White II binomial option pricing model. The fair value of Employee Stock Purchase Plan (ESPP) grants is estimated using the Black-Scholes-Merton model. Stock-based compensation expense related to stock option, SAR and ESPP grants totaled $21.7 million and $20.9 million during the three months ended September 30, 2018 and 2017, respectively, and $45.4 million and $42.9 million during the nine months ended September 30, 2018 and 2017, respectively.

Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants during the nine-month periods ended September 30, 2018 and 2017 are as follows:
 
Stock Options/SARs
 
ESPP
 
Nine Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2018
 
2017
 
2018
 
2017
Weighted Average Fair Value of Grants
$
33.49

 
$
23.94

 
$
25.52

 
$
22.10

Expected Volatility
28.22
%
 
28.28
%
 
24.36
%
 
26.96
%
Risk-Free Interest Rate
2.68
%
 
1.52
%
 
1.86
%
 
0.89
%
Dividend Yield
0.72
%
 
0.75
%
 
0.64
%
 
0.71
%
Expected Life
5.0 years

 
5.1 years

 
0.5 years

 
0.5 years


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

The following table sets forth stock option and SAR transactions for the nine-month periods ended September 30, 2018 and 2017 (stock options and SARs in thousands):
 
Nine Months Ended 
 September 30, 2018
 
Nine Months Ended 
 September 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
1,884

 
126.65

 
2,260

 
96.24

Exercised (1)
(2,144
)
 
69.62

 
(1,674
)
 
55.63

Forfeited
(167
)
 
91.89

 
(269
)
 
90.22

Outstanding at September 30 (2)
8,676

 
$
96.55

 
10,167

 
$
83.02

Vested or Expected to Vest (3)
8,316

 
$
96.08

 
9,799

 
$
82.69

Exercisable at September 30 (4)
4,202

 
$
85.80

 
5,517

 
$
75.59


(1)
The total intrinsic value of stock options/SARs exercised for the nine months ended September 30, 2018 and 2017 was $103.7 million and $66.6 million, respectively. The intrinsic value is based upon the difference between the market price of EOG's common stock on the date of exercise and the grant price of the stock options/SARs.
(2)
The total intrinsic value of stock options/SARs outstanding at September 30, 2018 and 2017 was $269.1 million and $147.8 million, respectively. At September 30, 2018 and 2017, the weighted average remaining contractual life was 4.8 years and 4.3 years, respectively.
(3)
The total intrinsic value of stock options/SARs vested or expected to vest at September 30, 2018 and 2017 was $261.9 million and $145.9 million, respectively. At September 30, 2018 and 2017, the weighted average remaining contractual life was 4.7 years and 4.3 years, respectively.
(4)
The total intrinsic value of stock options/SARs exercisable at September 30, 2018 and 2017 was $175.5 million and $123.2 million, respectively. At September 30, 2018 and 2017, the weighted average remaining contractual life was 3.4 years and 2.8 years, respectively.

At September 30, 2018, unrecognized compensation expense related to non-vested stock option, SAR and ESPP grants totaled $119.7 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.3 years.

-10-

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



Restricted Stock and Restricted Stock Units. Employees may be granted restricted (non-vested) stock and/or restricted stock units without cost to them. Stock-based compensation expense related to restricted stock and restricted stock units totaled $17.5 million and $15.8 million for the three months ended September 30, 2018 and 2017, respectively, and $58.8 million and $50.0 million for the nine months ended September 30, 2018 and 2017, respectively.

The following table sets forth restricted stock and restricted stock unit transactions for the nine-month periods ended September 30, 2018 and 2017 (shares and units in thousands):
 
Nine Months Ended 
 September 30, 2018
 
Nine Months Ended 
 September 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
792

 
117.67

 
1,061

 
97.26

Released (1)
(708
)
 
77.46

 
(837
)
 
59.67

Forfeited
(150
)
 
91.36

 
(190
)
 
84.66

Outstanding at September 30 (2)
3,839

 
$
96.52

 
3,996

 
$
88.25

 
(1)
The total intrinsic value of restricted stock and restricted stock units released for the nine months ended September 30, 2018 and 2017 was $80.2 million and $81.6 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date the restricted stock and restricted stock units are released.
(2)
The total intrinsic value of restricted stock and restricted stock units outstanding at September 30, 2018 and 2017 was $489.7 million and $386.6 million, respectively.

At September 30, 2018, unrecognized compensation expense related to restricted stock and restricted stock units totaled $194.5 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.2 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 $9.8 million and $6.8 million for the three-month periods ended September 30, 2018 and 2017, respectively, and $12.1 million and $8.6 million for the nine-month periods ended September 30, 2018 and 2017, respectively.


-11-

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


The following table sets forth the Performance Awards transactions for the nine-month periods ended September 30, 2018 and 2017 (units in thousands):
 
Nine Months Ended 
 September 30, 2018
 
Nine Months Ended 
 September 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

 
$
90.96

 
545

 
$
80.92

Granted
107

 
127.00

 
78

 
96.29

Granted for Performance Multiple (1)
72

 
101.87

 
119

 
84.43

Released (2)
(148
)
 
84.43

 
(240
)
 
66.69

Forfeited

 

 

 

Outstanding at September 30 (3)
533

(4)
$
101.50

 
502

 
$
90.96

 
(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 nine months ended September 30, 2018 and 2017 was approximately $17.7 million and $23.6 million, respectively. 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 September 30, 2018 and 2017 was approximately $68.0 million and $48.6 million, respectively.
(4)
Upon the application of the relevant performance multiple at the completion of each of the remaining Performance Periods, a minimum of 143,610 and a maximum of 921,940 Performance Awards could be outstanding.

At September 30, 2018, unrecognized compensation expense related to Performance Awards totaled $11.0 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 1.7 years.

3.    Net Income Per Share

The following table sets forth the computation of Net Income Per Share for the three-month and nine-month periods ended September 30, 2018 and 2017 (in thousands, except per share data):
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2018
 
2017
 
2018
 
2017
Numerator for Basic and Diluted Earnings Per Share -
 
 
 
 
 
 
 
Net Income
$
1,190,952

 
$
100,541

 
$
2,526,272

 
$
152,111

Denominator for Basic Earnings Per Share -
 

 
 

 
 

 
 

Weighted Average Shares
577,254

 
574,783

 
576,431

 
574,370

Potential Dilutive Common Shares -
 

 
 

 
 

 
 

Stock Options/SARs
1,432

 
1,451

 
1,317

 
1,518

Restricted Stock/Units and Performance Units/Stock
2,873

 
2,502

 
2,694

 
2,565

Denominator for Diluted Earnings Per Share -
 

 
 

 
 

 
 

Adjusted Diluted Weighted Average Shares
581,559

 
578,736

 
580,442

 
578,453

Net Income Per Share
 

 
 

 
 

 
 

Basic
$
2.06

 
$
0.17

 
$
4.38

 
$
0.26

Diluted
$
2.05

 
$
0.17

 
$
4.35

 
$
0.26



-12-

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


The diluted earnings per share calculation excludes stock options and SARs that were anti-dilutive. Shares underlying the excluded stock options and SARs were 0.5 million and 4.2 million shares for the three months ended September 30, 2018 and 2017, respectively, and were 0.2 million and 3.6 million shares, respectively, for the nine months ended September 30, 2018 and 2017, respectively.

4.    Supplemental Cash Flow Information

Net cash paid for interest and income taxes was as follows for the nine-month periods ended September 30, 2018 and 2017 (in thousands):
 
Nine Months Ended 
 September 30,
 
2018
 
2017
Interest (1)
$
172,076

 
$
202,320

Income Taxes, Net of Refunds Received
$
81,059

 
$
92,391

 
(1)
Net of capitalized interest of $18 million and $21 million for the nine months ended September 30, 2018 and 2017, respectively.

EOG's accrued capital expenditures at September 30, 2018 and 2017 were $702 million and $545 million, respectively.

Non-cash investing activities for the nine months ended September 30, 2018, included additions of $222 million to EOG's oil and gas properties as a result of property exchanges and an addition of $49 million to EOG's other property, plant and equipment primarily in connection with a capital lease transaction in the Permian Basin. Non-cash investing activities for the nine months ended September 30, 2017, included additions of $214 million to EOG's oil and gas properties as a result of property exchanges.

5.    Segment Information

Selected financial information by reportable segment is presented below for the three-month and nine-month periods ended September 30, 2018 and 2017 (in thousands):
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2018
 
2017
 
2018
 
2017
Operating Revenues and Other
 
 
 
 
 
 
 
United States
$
4,653,342

 
$
2,569,867

 
$
12,339,086

 
$
7,620,601

Trinidad
84,648

 
63,800

 
247,272

 
210,022

Other International (1)
43,634

 
11,177

 
114,505

 
37,258

Total
$
4,781,624

 
$
2,644,844

 
$
12,700,863

 
$
7,867,881

Operating Income (Loss)
 

 
 

 
 

 
 

United States
$
1,458,641

 
$
207,173

 
$
3,251,377

 
$
457,018

Trinidad
48,988

 
21,739

 
117,106

 
70,512

Other International (1)
(942
)
 
(14,076
)
 
(22,277
)
 
(77,040
)
Total
1,506,687

 
214,836

 
3,346,206

 
450,490

Reconciling Items
 

 
 

 
 

 
 

Other Income (Expense), Net
3,308

 
226

 
(4,516
)
 
8,349

Interest Expense, Net
(63,632
)
 
(69,082
)
 
(189,032
)
 
(211,010
)
Income Before Income Taxes
$
1,446,363

 
$
145,980

 
$
3,152,658

 
$
247,829

 
(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)


Total assets by reportable segment are presented below at September 30, 2018 and December 31, 2017 (in thousands):
 
At
September 30,
2018
 
At
December 31,
2017
Total Assets
 
 
 
United States
$
32,656,676

 
$
28,312,599

Trinidad
619,127

 
974,477

Other International (1)
361,933

 
546,002

Total
$
33,637,736

 
$
29,833,078

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

6.    Asset Retirement Obligations

The following table presents the reconciliation of the beginning and ending aggregate carrying amounts of short-term and long-term legal obligations associated with the retirement of property, plant and equipment for the nine-month periods ended September 30, 2018 and 2017 (in thousands):
 
Nine Months Ended 
 September 30,
 
2018
 
2017
Carrying Amount at January 1
$
946,848

 
$
912,926

Liabilities Incurred
63,443

 
30,114

Liabilities Settled (1)
(15,319
)
 
(53,638
)
Accretion
27,306

 
25,963

Revisions
(39,137
)
 
(1,791
)
Foreign Currency Translations
(2,197
)
 
16,902

Carrying Amount at September 30
$
980,944

 
$
930,476

 
 
 
 
Current Portion
$
18,209

 
$
23,606

Noncurrent Portion
$
962,735

 
$
906,870

 
(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.


-14-

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


7.    Exploratory Well Costs

EOG's net changes in capitalized exploratory well costs for the nine-month period ended September 30, 2018, are presented below (in thousands):
 
Nine Months Ended 
 September 30, 2018
Balance at January 1
$
2,167

Additions Pending the Determination of Proved Reserves
6,497

Reclassifications to Proved Properties
(5,346
)
Costs Charged to Expense
(433
)
Balance at September 30
$
2,885


At September 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.

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 nine months ended September 30, 2018 and 2017, EOG's total costs recognized for these pension plans were $30 million and $27 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 nine months ended September 30, 2018 and 2017, EOG utilized commercial paper borrowings, bearing market interest rates, for various corporate financing purposes. At September 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 $11 million and $9 million during the nine months ended September 30, 2018 and 2017, respectively. The weighted average interest rate for commercial paper borrowings during the nine months ended September 30, 2018 and 2017, was 1.97% and 1.39%, respectively.

On October 1, 2018, EOG repaid upon maturity the $350 million aggregate principal amount of its 6.875% Senior Notes due 2018.

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 September 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 September 30, 2018, would have been 3.16% and 5.25%, 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 September 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 September 30, 2018
 

 
 

 
 

 
 

Financial Assets:
 

 
 

 
 

 
 

Crude Oil Basis Swaps
$

 
$
35

 
$

 
$
35

Financial Liabilities:
 
 
 
 
 
 
 
Crude Oil Swaps
$

 
$
159

 
$

 
$
159

Crude Oil Basis Swaps

 
2

 

 
2

 
 
 
 
 
 
 
 
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 $165 million were written down to their fair value of $131 million, resulting in pretax impairment charges of $34 million for the nine months ended September 30, 2018. Included in the $34 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 and estimated discounted cash flows as the basis for determining the fair value of unproved and proved properties, respectively, received in non-cash property exchanges. See Note 4.

Fair Value of Debt. At September 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 $6,400 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 nine months ended September 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 October 31, 2018 (closed)
 
15,000

 
$
1.063

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

 
1.063

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

 
$
1.075


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 nine months ended September 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 September 30, 2018 (closed)
 
37,000

 
$
3.818

 
October 2018 (closed)
 
52,000

 
3.911

 
November 1, 2018 through December 31, 2018
 
52,000

 
3.911

 
 
 
 
 
 
 
2019
 
 
 
 
 
January 1, 2019 through December 31, 2019
 
10,000

 
$
5.558



-17-

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


Presented below is a comprehensive summary of EOG's crude oil price swap contracts for the nine months ended September 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 September 30, 2018 (closed)
 
134,000

 
$
60.04

October 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 nine months ended September 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 October 31, 2018 (closed)
 
35,000

 
$
3.00

November 2018
 
35,000

 
3.00


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

In addition, EOG has purchased put options which establish a floor price for the sale of notional volumes of natural gas as specified in the put option contracts. The put options grant EOG the right to receive the difference between the put option strike price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the put option strike price. Presented below is a comprehensive summary of EOG's natural gas call and put option contracts for the nine months ended September 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 October 31, 2018 (closed)
120,000

 
$
3.38

 
96,000

 
$
2.94

November 2018
120,000

 
3.38

 
96,000

 
2.94




-18-

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


The following table sets forth the amounts and classification of EOG's outstanding financial derivative instruments at September 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
 
September 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
 
5

 

Liability Derivatives
 
 
 
 
 
 

Crude oil and natural gas derivative contracts -
 
 
 
 
 
 

Current portion
 
Liabilities from Price Risk Management Activities (1)
 
$
133

 
$
50

Noncurrent portion
 
Other Liabilities
 

 
7

 
(1)
The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $161 million, partially offset by gross assets of $28 million at September 30, 2018, and gross liabilities of $55 million, partially offset by gross assets of $5 million at December 31, 2017.

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

13.  Acquisitions and Divestitures

During the nine months ended September 30, 2018, EOG recognized a net gain on asset dispositions of $95 million, primarily due to non-cash property exchanges in Texas, New Mexico and Wyoming and received proceeds of approximately $12 million. Additionally, in the third quarter of 2018, EOG's wholly-owned subsidiary signed a share purchase and sale agreement for the sale of all of its interest in EOG Resources United Kingdom Limited, which is expected to close in the fourth quarter of 2018. At September 30, 2018, the book value of the assets held for sale and the related liabilities were $235 million and $65 million, respectively. During the nine months ended September 30, 2017, EOG recognized a net loss on asset dispositions of $(34) million and received proceeds of approximately $192 million primarily from the sale of producing assets, unproved leasehold and other property, plant and equipment in Oklahoma and Texas.


-19-

        



PART I.  FINANCIAL INFORMATION

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

Overview
EOG Resources, Inc., together with its subsidiaries (collectively, EOG), is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, 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 efficient, safe and environmentally responsible 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 nine months of 2018, the average U.S. New York Mercantile Exchange (NYMEX) crude oil and natural gas prices were $66.79 per barrel and $2.86 per million British thermal units (MMBtu), respectively, representing an increase of 35% and a decrease of 8%, 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 nine months of 2018, EOG continued to focus on increasing drilling, completion and operating efficiencies gained in prior years. In addition, EOG continued to evaluate certain potential crude oil and liquids-rich natural gas exploration and development prospects and to look for opportunities to add drilling inventory through leasehold acquisitions, farm-ins, exchanges or tactical acquisitions. On a volumetric basis, as calculated using the ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas, crude oil and condensate and NGL production accounted for approximately 77% of EOG's United States production during both the first nine months of 2018 and 2017. During the first nine months 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. EOG has completed seismic surveys in the SECC Block and will continue to process that data through the remainder of 2018.


-20-

        



Other International. In the United Kingdom, EOG produces crude oil from its 100% working interest East Irish Sea Conwy Development project. In the third quarter of 2018, EOG's wholly-owned subsidiary signed a share purchase and sale agreement for the sale of all of its interest in EOG Resources United Kingdom Limited, which is expected to close in the fourth quarter of 2018.

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 Company Limited. EOG commenced a seven-well drilling program during the third quarter of 2018 and completed one of these wells in October 2018. This drilling program is expected to continue.

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 26% at September 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.

On October 1, 2018, EOG repaid upon maturity the $350 million aggregate principal amount of its 6.875% Senior Notes due 2018.

Total anticipated 2018 capital expenditures are estimated to range from approximately $5.8 billion to $6.0 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.

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



-21-

        



Results of Operations

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

Operating Revenues. During the third quarter of 2018, operating revenues increased $2,137 million, or 81%, to $4,782 million from $2,645 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 third quarter of 2018 increased $1,470 million, or 79%, to $3,321 million from $1,851 million for the same period of 2017. EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $52 million for the third quarter of 2018 compared to net losses of $7 million for the same period of 2017. Gathering, processing and marketing revenues for the third quarter of 2018 increased $577 million, or 74%, to $1,361 million from $784 million for the same period of 2017. Net gains on asset dispositions were $116 million for the third quarter of 2018 compared to net losses of $8 million for the same period of 2017.


-22-

        



Wellhead volume and price statistics for the three-month periods ended September 30, 2018 and 2017 were as follows:
 
Three Months Ended 
 September 30,
 
2018
 
 
2017
Crude Oil and Condensate Volumes (MBbld) (1)
 
 
 
 
United States
409.2

 
 
327.1

Trinidad
0.8

 
 
0.8

Other International (2)
5.0

 
 

Total
415.0

 
 
327.9

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

 
 
 
United States
$
69.53

 
 
$
48.06

Trinidad
61.71

 
 
39.42

Other International (2)
72.81

 
 

Composite
69.55

 
 
48.11

Natural Gas Liquids Volumes (MBbld) (1)
 
 
 
 
United States
127.8

 
 
87.4

Other International (2)

 
 

Total
127.8

 
 
87.4

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

 
 
 

United States
$
30.09

 
 
$
22.38

Other International (2)

 
 

Composite
30.09

 
 
22.38

Natural Gas Volumes (MMcfd) (1)
 
 
 
 
United States
948

 
 
748

Trinidad
260

 
 
323

Other International (2)
28

 
 
25

Total
1,236

 
 
1,096

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

 
 
 

United States
$
2.67

 
 
$
2.20

Trinidad
2.88

 
 
2.04

Other International (2)
3.83

 
 
3.74

Composite
2.74

(4) 
 
2.19

Crude Oil Equivalent Volumes (MBoed) (5)
 
 
 
 
United States
695.0

 
 
539.2

Trinidad
44.1

 
 
54.6

Other International (2)
9.7

 
 
4.3

Total
748.8

 
 
598.1

 
 
 
 
 
Total MMBoe (5)
68.9

 
 
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 $0.49 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 as 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.


-23-

        




Wellhead crude oil and condensate revenues for the third quarter of 2018 increased $1,204 million, or 83%, to $2,655 million from $1,451 million for the same period of 2017. The increase was due to a higher composite wellhead crude oil and condensate price ($819 million) and an increase of 87 MBbld, or 27%, in wellhead crude oil and condensate production ($385 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 third quarter of 2018 increased 45% to $69.55 per barrel compared to $48.11 per barrel for the same period of 2017.

NGL revenues for the third quarter of 2018 increased $174 million, or 96%, to $354 million from $180 million for the same period of 2017 due to a higher composite average price ($91 million) and an increase of 40 MBbld, or 46%, in production ($83 million). Increased production was primarily in the Permian Basin and the Eagle Ford. EOG's composite NGL price for the third quarter of 2018 increased 34% to $30.09 per barrel compared to $22.38 per barrel for the same period of 2017.

Wellhead natural gas revenues for the third quarter of 2018 increased $92 million, or 41%, to $312 million from $220 million for the same period of 2017. The increase was due to a higher composite wellhead natural gas price ($63 million) and an increase in natural gas deliveries ($28 million). Natural gas deliveries for the third quarter of 2018 increased 140 MMcfd, or 13%, compared to the same period of 2017 due primarily to higher deliveries in the United States primarily resulting from increased production of associated natural gas from the Permian Basin and the Eagle Ford and higher natural gas volumes from the Marcellus Shale, partially offset by lower natural gas deliveries in Trinidad. EOG's composite wellhead natural gas price for the third quarter of 2018 increased 25% to $2.74 per Mcf compared to $2.19 per Mcf for the same period of 2017. This increase in composite wellhead natural gas prices includes a positive revenue adjustment of $0.49 per Mcf related to the adoption of ASU 2014-09.

During the third quarter of 2018, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $52 million compared to $7 million for the same period of 2017. During the third quarter of 2018, net cash paid for settlements of financial commodity derivative contracts was $92 million compared to net cash received of $2 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 third quarter of 2018 increased $43 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 third quarter of 2018, operating expenses of $3,275 million were $845 million higher than the $2,430 million incurred during the third quarter of 2017.  The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended September 30, 2018 and 2017:
 
Three Months Ended 
 September 30,
 
2018
 
2017
Lease and Well
$
4.67

 
$
4.58

Transportation Costs
2.85

 
3.34

Depreciation, Depletion and Amortization (DD&A) -
 
 
 
Oil and Gas Properties
12.89

 
14.87

Other Property, Plant and Equipment
0.44

 
0.51

General and Administrative (G&A)
1.62

 
2.03

Interest Expense, Net
0.92

 
1.26

Total (1)
$
23.39

 
$
26.59

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


-24-

        



The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A and net interest expense for the three months ended September 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 $322 million for the third quarter of 2018 increased $70 million from $252 million for the same prior year period primarily due to increased operating and maintenance costs ($44 million), workover expenditures ($19 million) and lease and well administrative expenses ($14 million), all in the United States, partially offset by decreased 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 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 $196 million for the third quarter of 2018 increased $12 million from $184 million for the same prior year period primarily due to increased transportation costs in the Permian Basin ($33 million), partially offset by decreased transportation costs in the Barnett Shale ($11 million), the Rocky Mountain area ($5 million) and the Eagle Ford ($4 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 third quarter of 2018 increased $72 million to $918 million from $846 million for the same prior year period. DD&A expenses associated with oil and gas properties for the third quarter of 2018 were $70 million higher than the same prior year period. The increase primarily reflects increased production in the United States ($224 million), partially offset by decreased unit rates in the United States ($155 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.

Interest expense, net of $64 million for the third quarter of 2018 decreased $5 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.

Gathering and processing costs increased $81 million to $114 million for the third quarter of 2018 compared to $33 million for the same prior year period primarily due to the adoption of ASU 2014-09 ($57 million) and increased operating costs in the United Kingdom ($21 million) and the Permian Basin ($7 million), partially offset by decreased operating costs in the Barnett Shale ($7 million).


-25-

        



Impairments include amortization of unproved oil and gas property costs as well as impairments of proved oil and gas properties; other property, plant and equipment; and other assets. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. 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 $45 million for the third quarter of 2018 were $9 million lower than impairments for the same prior year period primarily due to decreased amortization of unproved property costs in the United States, 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 $1 million and $3 million for the third 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 third quarter of 2018 increased $83 million to $209 million (6.3% of wellhead revenues) compared to $126 million (6.8% 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 in the United States as a result of increased wellhead revenues ($68 million) and increased ad valorem/property taxes in the United States ($13 million).

EOG recognized an income tax provision of $255 million for the third quarter of 2018 compared to an income tax provision of $45 million in the third quarter of 2017, primarily due to an increase in pretax income. The net effective tax rate for 2018 decreased to 18% from 31% 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 and an overall net tax benefit from certain tax reform measurement-period adjustments primarily related to the repatriation tax, partially offset by a reduction in tax benefits from stock-based compensation.


-26-

        



Nine Months Ended September 30, 2018 vs. Nine Months Ended September 30, 2017

Operating Revenues. During the first nine months of 2018, operating revenues increased $4,833 million, or 61%, to $12,701 million from $7,868 million for the same period of 2017. Total wellhead revenues for the first nine months of 2018 increased $3,426 million, or 62%, to $8,908 million from $5,482 million for the same period of 2017. During the first nine months of 2018, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $298 million compared to net gains of $65 million for the same period of 2017. Gathering, processing and marketing revenues for the first nine months of 2018 increased $1,609 million, or 70%, to $3,899 million from $2,290 million for the same period of 2017. Net gains on asset dispositions were $95 million for the first nine months of 2018 compared to net losses of $34 million for the same period of 2017.


-27-

        



Wellhead volume and price statistics for the nine-month periods ended September 30, 2018 and 2017 were as follows:
 
Nine Months Ended 
 September 30,
 
 
2018
 
 
2017
 
Crude Oil and Condensate Volumes (MBbld)
 
 
 
 
 
United States
382.9

 
 
324.3

 
Trinidad
0.8

 
 
0.8

 
Other International
4.1

 
 
1.0

 
Total
387.8

 
 
326.1

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

 
 
 

 
United States
$
67.35

 
 
$
48.61

 
Trinidad
58.91

 
 
40.24

 
Other International
71.83

 
 
51.55

 
Composite
67.38

 
 
48.60

 
Natural Gas Liquids Volumes (MBbld)
 
 
 
 
 
United States
113.9

 
 
84.3

 
Other International

 
 

 
Total
113.9

 
 
84.3

 
Average Natural Gas Liquids Prices ($/Bbl)
 

 
 
 

 
United States
$
27.71

 
 
$
20.87

 
Other International

 
 

 
Composite
27.71

 
 
20.87

 
Natural Gas Volumes (MMcfd)
 
 
 
 
 
United States
905

 
 
744

 
Trinidad
278

 
 
317

 
Other International
31

 
 
22

 
Total
1,214

 
 
1,083

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

 
 
 

 
United States
$
2.66

 
 
$
2.22

 
Trinidad
2.91

 
 
2.33

 
Other International
4.10

 
 
3.72

 
Composite
2.75

(2)
 
2.28

 
Crude Oil Equivalent Volumes (MBoed)
 
 
 
 
 
United States
647.6

 
 
532.6

 
Trinidad
47.2

 
 
53.6

 
Other International
9.2

 
 
4.8

 
Total
704.0

 
 
591.0

 
 
 
 
 
 
 
Total MMBoe
192.2

 
 
161.3

 
 
(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 $0.43 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 as a deduction to Natural Gas revenues.

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Wellhead crude oil and condensate revenues for the first nine months of 2018 increased $2,807 million, or 65%, to $7,134 million from $4,327 million for the same period of 2017 due to a higher composite wellhead crude oil and condensate price ($1,989 million) and an increase of 62 MBbld, or 19%, in wellhead crude oil and condensate production ($818 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 nine months of 2018 increased 39% to $67.38 per barrel compared to $48.60 per barrel for the same period of 2017.

NGL revenues for the first nine months of 2018 increased $382 million, or 80%, to $862 million from $480 million for the same period of 2017 due to a higher composite average price ($213 million) and an increase of 30 MBbld, or 35%, in NGL deliveries ($169 million) primarily in the Permian Basin and the Eagle Ford. EOG's composite NGL price for the first nine months of 2018 increased 33% to $27.71 per barrel compared to $20.87 per barrel for the same period of 2017.

Wellhead natural gas revenues for the first nine months of 2018 increased $237 million, or 35%, to $912 million from $675 million for the same period of 2017. The increase was due to a higher composite wellhead natural gas price ($156 million) and an increase in natural gas deliveries ($81 million). Natural gas deliveries for the first nine months of 2018 increased 131 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 and higher natural gas volumes from the Marcellus Shale, partially offset by lower natural gas deliveries in Trinidad. EOG's composite wellhead natural gas price for the first nine months of 2018 increased 21% to $2.75 per Mcf compared to $2.28 per Mcf for the same period of 2017. The increase in composite wellhead natural gas prices includes a positive revenue adjustment of $0.43 per Mcf related to the adoption of ASU 2014-09.

During the first nine months of 2018, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $298 million compared to net gains of $65 million for the same period of 2017. During the first nine months of 2018, net cash paid for settlements of financial commodity derivative contracts was $180 million compared to net cash received for settlements of financial commodity derivative contracts of $5 million for the same period of 2017. The net cash received for financial commodity derivative contracts during the first nine months of 2017 included certain early-terminated crude oil price swaps.

Gathering, processing and marketing revenues less marketing costs for the first nine months of 2018 increased $76 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 nine months of 2018, operating expenses of $9,355 million were $1,938 million higher than the $7,417 million incurred during the same period of 2017. The following table presents the costs per Boe for the nine-month periods ended September 30, 2018 and 2017:
 
Nine Months Ended 
 September 30,
 
2018
 
2017
Lease and Well
$
4.87

 
$
4.73

Transportation Costs
2.87

 
3.40

DD&A -
 
 
 
Oil and Gas Properties
12.64

 
15.14

Other Property, Plant and Equipment
0.45

 
0.53

G&A
1.61

 
1.97

Interest Expense, Net
0.98

 
1.31

Total (1)
$
23.42

 
$
27.08

 
(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, DD&A, G&A and net interest expense for the nine months ended September 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 $936 million for the first nine months of 2018 increased $173 million from $763 million for the same prior year period primarily due to higher operating and maintenance costs ($122 million), higher workover expenditures ($34 million) and higher lease and well administrative costs ($28 million), all in the United States, partially offset by lower operating and maintenance costs in the United Kingdom ($13 million). Lease and well expenses increased in the United States primarily due to increased operating activities resulting in increased production.

DD&A expenses for the first nine months of 2018 decreased $13 million to $2,515 million from $2,528 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first nine months of 2018 were $14 million lower than the same prior year period. The decrease primarily reflects decreased unit rates in the United States ($522 million), partially offset by increased production in the United States ($501 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 $310 million for the first nine months of 2018 decreased $7 million from $317 million for the same prior year period primarily due to decreased professional, legal and other services ($17 million), partially offset by increased employee-related expenses ($7 million) and information systems costs ($6 million).

Interest expense, net of $189 million for the first nine months of 2018 decreased $22 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 of $325 million for the first nine months of 2018 increased $219 million compared to the same prior year period primarily due to the adoption of ASU 2014-09 ($147 million) and increased operating costs in the Eagle Ford ($26 million), the Permian Basin ($25 million) and the United Kingdom ($21 million).

Exploration costs of $115 million for the first nine months of 2018 decreased $7 million from $122 million for the same prior year period primarily due to decreased geological and geophysical costs in the United States.

Impairments of $161 million for the first nine months of 2018 were $165 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 ($34 million), which was caused by a decrease in EOG's estimates of undeveloped properties not expected to be developed before lease expiration. For the first nine months of 2017, proved property and other asset impairments in the United States were primarily related to the sale of legacy natural gas assets. EOG recorded impairments of proved properties, other property, plant and equipment and other assets of $34 million and $165 million for the first nine months of 2018 and 2017, respectively.

Taxes other than income for the first nine months of 2018 increased $196 million to $582 million (6.5% of wellhead revenues) from $386 million (7.0% 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 ($171 million) and increased ad valorem/property taxes in the United States ($17 million).

Other expense of $5 million for the first nine months of 2018 increased $13 million compared to other income of $8 million for the same prior year period primarily due to an increase in foreign currency exchange losses.

EOG recognized an income tax provision of $626 million for the first nine months of 2018 compared to an income tax provision of $96 million for the same period in 2017, primarily due to an increase in pretax income. The net effective tax rate for the first nine months of 2018 decreased to 20% from 39% for the first nine months of 2017. The lower effective tax rate is primarily due to the reduction in the U.S. federal statutory tax rate to 21% in 2018 from 35% in 2017 and foreign income in the United Kingdom for which no taxes are recorded due to valuation allowances, partially offset by a reduction in tax benefits from stock-based compensation.

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Capital Resources and Liquidity

Cash Flow. The primary sources of cash for EOG during the nine months ended September 30, 2018, were funds generated from operations. The primary uses of cash were funds used in operations; exploration and development expenditures; dividend payments to stockholders; other property, plant and equipment expenditures; and purchases of treasury stock in connection with stock compensation plans. During the first nine months of 2018, EOG's cash balance increased $440 million to $1,274 million from $834 million at December 31, 2017.

Net cash provided by operating activities of $5,683 million for the first nine months of 2018 increased $2,745 million compared to the same period of 2017 primarily due to an increase in wellhead revenues ($3,426 million) and favorable changes in gathering, processing and marketing revenues less marketing costs ($76 million), net cash paid for interest ($30 million) and net cash paid for income taxes ($11 million), partially offset by increases in cash operating expenses ($556 million) and net cash paid for settlements of commodity derivative contracts ($185 million) and an unfavorable change in working capital ($132 million).

Net cash used in investing activities of $4,878 million for the first nine months of 2018 increased by $2,123 million compared to the same period of 2017 due to an increase in additions to oil and gas properties ($1,644 million), an unfavorable change in components of working capital associated with investing activities ($216 million), a decrease in proceeds from the sales of assets ($180 million), and an increase in additions to other property, plant and equipment ($63 million).

Net cash used in financing activities of $363 million for the first nine months of 2018 included cash dividend payments ($311 million) and purchases of treasury stock in connection with stock compensation plans ($59 million), partially offset by proceeds from stock options exercised and employee stock purchase plan activity ($12 million). Net cash used in financing activities of $933 million for the first nine months of 2017 included repayments of long-term debt ($600 million), cash dividend payments ($289 million) and purchases of treasury stock in connection with stock compensation plans ($50 million).

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