Eog Resources Inc (EOG) SEC Quarterly Report (10-Q) for Q1 2018

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

(Mark One)

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2018

or

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 1-9743

(Exact name of registrant as specified in its charter)

1111 Bagby, Sky Lobby 2, Houston, Texas 77002

(Address of principal executive offices)       (Zip Code)

713-651-7000

(Registrant's telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  

Yes  ý  No  o

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

Large accelerated filer  ý    Accelerated filer  o    Non-accelerated filer  o (Do not check if a smaller reporting company)

Smaller reporting company  o   Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  

Yes  o  No  ý

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.

EOG RESOURCES, INC.

TABLE OF CONTENTS

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)

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

EOG RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Data)

(Unaudited)

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

EOG RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

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

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 months ended March 31, 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 for certain processing and marketing agreements within its United States segment as Gathering and Processing Costs, instead of a deduction to Revenues within its Condensed Consolidated Statements of Income and Comprehensive Income. There was no impact to operating income, net income or cash flows resulting from changes to the presentation of natural gas processing fees. The impacts of the adoption of ASU 2014-09 for the three months ended March 31, 2018, were as follows (in thousands):

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 March 31, 2018, were $1,343 million and $1,428 million , respectively, and are included in Accounts Receivable, Net on the Condensed Consolidated Balance Sheets. Losses incurred on receivables from contracts with customers are infrequent and have been immaterial.

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

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

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

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

Gathering, Processing and Marketing. Gathering, processing and marketing revenues represent sales of third-party crude oil and condensate, NGLs and natural gas, as well as fees associated with processing and gathering third-party natural gas and revenues from sales of EOG-owned sand. EOG evaluates whether it is the principal or agent under these transactions. As control of the underlying commodity is transferred to EOG prior to the gathering, processing and marketing activities, EOG considers itself the principal of these arrangements. Accordingly, EOG recognizes these transactions on a gross basis. Purchases of third-party 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 months ended March 31, 2018 in accordance with ASU 2018-05. EOG expects to have all provisional amounts finalized by the fourth quarter of 2018.

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

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

In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" (ASU 2016-02), which significantly changes accounting for leases by requiring that lessees recognize a right-of-use asset and a related lease liability representing the obligation to make lease payments, for certain lease transactions. Additional disclosures about an entity's lease transactions will also be required. ASU 2016-02 defines a lease as "a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment (an identified asset) for a period of time in exchange for consideration." In January 2018, the FASB issued ASU 2018-01, "Leases (Topic 842) - Land Easement Practical Expedient for Transition to Topic 842" (ASU 2018-01), which permits an entity an optional election to not evaluate under ASU 2016-02 those existing or expired land easements that were not previously accounted for as leases prior to the adoption of ASU 2016-02. ASU 2016-02 and ASU 2018-01 are effective for interim and annual periods beginning after December 31, 2018, and early application is permitted. Lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented in the financial statements using a modified retrospective approach. EOG is continuing its assessment of ASU 2016-02 by implementing its project plan, evaluating certain operational and corporate policies and processes, further defining its population of leases, reviewing certain contracts and considering the election of practical expedients.

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):

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 March 31, 2018 , approximately 16.8 million common shares remained available for grant under the 2008 Plan. EOG's policy is to issue shares related to the 2008 Plan from previously authorized unissued shares or treasury shares to the extent treasury shares are available.

Stock Options and Stock-Settled Stock Appreciation Rights and Employee Stock Purchase Plan . The fair value of stock option grants and SAR grants is estimated using the Hull-White II binomial option pricing model. The fair value of Employee Stock Purchase Plan (ESPP) grants is estimated using the Black-Scholes-Merton model. Stock-based compensation expense related to stock option, SAR and ESPP grants totaled $12.0 million and $11.0 million during the three months ended March 31, 2018 and 2017 , respectively.

Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants during the three -month periods ended March 31, 2018 and 2017 are as follows:

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 three -month periods ended March 31, 2018 and 2017 (stock options and SARs in thousands):

At March 31, 2018 , unrecognized compensation expense related to non-vested stock option, SAR and ESPP grants totaled $88.2 million . Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 1.7 years .

Restricted Stock and Restricted Stock Units. Employees may be granted restricted (non-vested) stock and/or restricted stock units without cost to them. Stock-based compensation expense related to restricted stock and restricted stock units totaled $22.4 million and $18.6 million for the three months ended March 31, 2018 and 2017 , respectively.

The following table sets forth restricted stock and restricted stock unit transactions for the three -month periods ended March 31, 2018 and 2017 (shares and units in thousands):

At March 31, 2018 , unrecognized compensation expense related to restricted stock and restricted stock units totaled $172.7 million . Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.4 years .

Performance Units and Performance Stock. EOG has granted performance units and/or performance stock (collectively, Performance Awards) to its executive officers annually since 2012. As more fully discussed in the grant agreements, the performance metric applicable to the Performance Awards is EOG's total shareholder return over a three -year performance period relative to the total shareholder return of a designated group of peer companies (Performance Period). Upon the application of the performance multiple at the completion of the Performance Period, a minimum of 0% and a maximum of 200% of the Performance Awards granted could be outstanding. The fair value of the Performance Awards is estimated using a Monte Carlo simulation. Stock-based compensation expense related to the Performance Award grants totaled $1.1 million and $0.9 million for the three -month periods ended March 31, 2018 and 2017 , respectively.

The following table sets forth the Performance Awards transactions for the three -month periods ended March 31, 2018 and 2017 :

At March 31, 2018 , unrecognized compensation expense related to Performance Awards totaled $7.2 million . Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 1.8 years .

3. Net Income Per Share

The following table sets forth the computation of Net Income Per Share for the three -month periods ended March 31, 2018 and 2017 (in thousands, except per share data):

The diluted earnings per share calculation excludes stock options, SARs, restricted stock and units and performance units that were anti-dilutive. Shares underlying the excluded stock options and SARs totaled 0.2 million and 2.0 million shares for the three months ended March 31, 2018 and 2017 , respectively.

4. Supplemental Cash Flow Information

Net cash paid for interest and income taxes was as follows for the three -month periods ended March 31, 2018 and 2017 (in thousands):

EOG's accrued capital expenditures at March 31, 2018 and 2017 were $593 million and $415 million , respectively.

Non-cash investing activities for the three months ended March 31, 2018 , included a non-cash addition of $48 million to EOG's other property, plant and equipment in connection with a capital lease transaction in the Permian Basin and non-cash additions of $9 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 periods ended March 31, 2018 and 2017 (in thousands):

Total assets by reportable segment are presented below at March 31, 2018 and December 31, 2017 (in thousands):

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 three -month periods ended March 31, 2018 and 2017 (in thousands):

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

7. Exploratory Well Costs

EOG's net changes in capitalized exploratory well costs for the three -month period ended March 31, 2018 , are presented below (in thousands):

At March 31, 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 three months ended March 31, 2018 and 2017 , EOG's total costs recognized for these pension plans were $9.9 million and $10.0 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

During the three months ended March 31, 2018, EOG utilized commercial paper borrowings, bearing market interest rates, for various corporate financing purposes. EOG did not utilize any such borrowings during the three months ended March 31, 2017. At March 31, 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 $18 million and zero during the three months ended March 31, 2018 and March 31, 2017, respectively. The weighted average interest rate for commercial paper borrowings during the three months ended March 31, 2018, was 1.76% .

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 March 31, 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 March 31, 2018, would have been 2.88% and 4.75% , respectively.

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 March 31, 2018 and December 31, 2017 (in millions):

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 $151 million were written down to their fair value of $129 million , resulting in pretax impairment charges of $22 million for the three months ended March 31, 2018 . Included in the $22 million pretax impairment charges are $21 million for a commodity price-related write-down of other assets.

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

Fair Value of Debt. At March 31, 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 $6,470 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.

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 three months ended March 31, 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.

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 three months ended March 31, 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.

Presented below is a comprehensive summary of EOG's crude oil price swap contracts for the three months ended March 31, 2018 , with notional volumes expressed in Bbld and prices expressed in $/Bbl.

Presented below is a comprehensive summary of EOG's natural gas price swap contracts for the three months ended March 31, 2018 , with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).

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 three months ended March 31, 2018 , with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.

The following table sets forth the amounts and classification of EOG's outstanding financial derivative instruments at March 31, 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):

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

13.  Acquisitions and Divestitures

During the three months ended March 31, 2018 , EOG recognized a net loss on asset dispositions of $(15) million , primarily due to the disposition of inventory and other assets, and received proceeds of approximately $3 million . During the three months ended March 31, 2017 , EOG recognized a net loss on asset dispositions of $(17) million and received proceeds of approximately $47 million primarily from the sale of other property, plant and equipment in Texas.

PART I.  FINANCIAL INFORMATION

ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EOG RESOURCES, INC.

Overview

EOG Resources, Inc., together with its subsidiaries (collectively, EOG), is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG operates under a consistent business and operational strategy that focuses predominantly on maximizing the rate of return on investment of capital by controlling operating and capital costs and maximizing reserve recoveries. Pursuant to this strategy, each prospective drilling location is evaluated by its estimated rate of return. This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-effective basis, allowing EOG to deliver long-term production growth while maintaining a strong balance sheet. EOG implements its strategy by emphasizing the drilling of internally generated prospects in order to find and develop low-cost reserves. Maintaining the lowest possible operating cost structure that is consistent with prudent and safe operations is also an important goal in the implementation of EOG's strategy.

United States. EOG's efforts to identify plays with large reserve potential have proven to be successful. EOG continues to drill numerous wells in large acreage plays, which in the aggregate have contributed substantially to, and are expected to continue to contribute substantially to, EOG's crude oil and liquids-rich natural gas production. EOG has placed an emphasis on applying its horizontal drilling and completion expertise to unconventional crude oil and liquids-rich reservoirs.

Crude oil and natural gas prices have been volatile, and this volatility is expected to continue. As a result of the many uncertainties associated with the world political environment, worldwide supplies of, and demand for, crude oil and condensate, natural gas liquids (NGLs) and natural gas and the availability of other worldwide energy supplies, EOG is unable to predict what changes may occur in crude oil and condensate, NGL, and natural gas prices in the future. The market prices of crude oil and condensate, NGLs and natural gas in 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 three months of 2018 , the average U.S. New York Mercantile Exchange (NYMEX) crude oil and natural gas prices were $62.89 per barrel and $2.93 per million British thermal units (MMBtu), respectively, representing an increase of 21% and a decrease of 10%, respectively, from the average NYMEX prices for the same period in 2017 . 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 three months of 2018 , EOG continued to focus on increasing drilling, completion and operating efficiencies gained in prior years. In addition, EOG continued to look for opportunities to add drilling inventory through leasehold acquisitions, farm-ins, exchanges or tactical acquisitions and to evaluate certain potential crude oil and liquids-rich natural gas exploration and development prospects. On a volumetric basis, as calculated using the ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas, crude oil and condensate and NGL production accounted for approximately 76% of EOG's United States production during the first three months of 2018 and for the same comparable period of 2017 . During the first three 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 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. In 2018 , EOG expects to conduct a seismic survey in the SECC Block.

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

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

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

Capital Structure . One of management's key strategies is to maintain a strong balance sheet with a consistently below average debt-to-total capitalization ratio as compared to those in EOG's peer group. EOG's debt-to-total capitalization ratio was 28% at both March 31, 2018 and December 31, 2017 . As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

Total anticipated 2018 capital expenditures are estimated to range from approximately $5.4 billion to $5.8 billion, excluding acquisitions and non-cash transactions. The majority of 2018 expenditures will be focused on United States crude oil activities. EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program and other uncommitted credit facilities, bank borrowings, borrowings under its $2.0 billion senior unsecured revolving credit facility, joint development agreements and similar arrangements and equity and debt offerings.

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

Results of Operations

The following review of operations for the three months ended March 31, 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 March 31, 2018 vs. Three Months Ended March 31, 2017

Operating Revenues. During the first quarter of 2018 , operating revenues increased $1,070 million, or 41%, to $3,681 million from $2,611 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 first quarter of 2018 increased $808 million, or 45%, to $2,622 million from $1,814 million for the same period of 2017 . EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $60 million for the first quarter of 2018 compared to net gains of $62 million for the same period of 2017 . Gathering, processing and marketing revenues for the first quarter of 2018 increased $375 million, or 52%, to $1,102 million from $727 million for the same period of 2017 . Net losses on asset dispositions for the first quarter of 2018 were $15 million compared to net losses of $17 million for the same period of 2017 .

Wellhead volume and price statistics for the three-month periods ended March 31, 2018 and 2017 were as follows:

Wellhead crude oil and condensate revenues for the first quarter of 2018 increased $671 million, or 47%, to $2,101 million from $1,430 million for the same period of 2017 . The increase was primarily due to a higher composite wellhead crude oil and condensate price ($456 million) and an increase of 48 MBbld, or 15%, in wellhead crude oil and condensate production ($215 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 quarter of 2018 increased 28% to $64.27 per barrel compared to $50.34 per barrel for the same period of 2017 .

NGL revenues for the first quarter of 2018 increased $68 million, or 44%, to $221 million from $153 million for the same period of 2017 due primarily to an increase of 22 MBbld, or 28%, in production ($42 million) and a higher composite average price ($26 million). Increased production was primarily in the Permian Basin and the Eagle Ford. EOG's composite NGL price for the first quarter of 2018 increased 13% to $24.46 per barrel compared to $21.63 per barrel for the same period of 2017 .

Wellhead natural gas revenues for the first quarter of 2018 increased $69 million, or 30%, to $300 million from $231 million for the same period of 2017 . The increase was due to a higher composite wellhead natural gas price ($43 million) and an increase in natural gas deliveries ($26 million). Natural gas deliveries for the first quarter of 2018 increased 118 MMcfd, or 11%, compared to the same period of 2017 due primarily to higher deliveries in the United States primarily due to increased production of associated natural gas from the Permian Basin and the Eagle Ford. EOG's composite wellhead natural gas price for the first quarter of 2018 increased 17% to $2.83 per Mcf compared to $2.42 per Mcf for the same period of 2017 . This increase in composite wellhead natural gas prices includes a positive revenue adjustment of $0.41 per Mcf related to the adoption of ASU 2014-09.

During the first quarter of 2018 , EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $60 million compared to net gains of $62 million for the same period of 2017 . During the first quarter of 2018 , net cash paid for settlements of financial commodity derivative contracts was $22 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 first quarter of 2018 increased $5 million as compared to the same period of 2017 . The increase primarily reflects higher margins in 2018 on crude oil and natural gas marketing activities.

Operating and Other Expenses. For the first quarter of 2018 , operating expenses of $2,807 million were $304 million higher than the $2,503 million incurred during the first quarter of 2017 .  The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended March 31, 2018 and 2017 :

The primary factors impacting the cost components of per-unit rates of lease and well, DD&A and net interest expense for the three months ended March 31, 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 $300 million for the first quarter of 2018 increased $44 million from $256 million for the same prior year period primarily due to increased operating and maintenance costs ($36 million) and workover expenditures ($4 million), both in the United States. Lease and well expenses increased in the United States primarily due to increased operating activities resulting in increased production.

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 first quarter of 2018 decreased $67 million to $749 million from $816 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first quarter of 2018 were $67 million lower than the same prior year period. The decrease primarily reflects decreased rates in the United States ($198 million), partially offset by increased production in the United States ($131 million). DD&A unit rates in the United States decreased primarily due to upward reserve revisions and reserves added at lower cost as a result of increased efficiencies.

Exploration costs of $35 million for the first quarter of 2018 decreased $22 million from $57 million for the same prior year period primarily due to decreased geological and geophysical costs in Trinidad.

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

Impairments of $65 million for the first quarter of 2018 were $129 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 ($115 million) and decreased amortization of unproved property costs in the United States ($13 million). EOG recorded impairments of proved properties, other property, plant and equipment and other assets of $22 million and $138 million for the first quarter of 2018 and 2017 , respectively.

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 background on the adoption of ASU 2014-09.

Gathering and processing costs increased $63 million to $101 million for the first quarter of 2018 compared to $38 million for the same prior year period primarily due to the adoption of ASU 2014-09 ($45 million) and increased operating costs in the Eagle Ford ($12 million) and the Permian Basin ($6 million), partially offset by lower operating costs in the United Kingdom ($5 million).

Interest expense, net, of $62 million for the first quarter of 2018 decreased $10 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.

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 first quarter of 2018 increased $49 million to $179 million (6.8% of wellhead revenues) compared to $130 million (7.2% of wellhead revenues) for the same prior year period. The increase in taxes other than income was primarily due to increases in severance/production taxes, primarily as a result of increased wellhead revenues in the United States.

EOG recognized an income tax provision of $175 million for the first quarter of 2018 compared to an income tax provision of $11 million in the first quarter of 2017 , primarily due to an increase of pretax income. The net effective tax rate for 2018 decreased to 21% from 28% in 2017. The lower effective tax rate is mostly due to the reduced U.S. federal statutory tax rate of 21% in 2018 from 35% in 2017 and decreased foreign losses in the United Kingdom for which tax benefits are not recorded due to valuation allowances, partially offset by a reduction in tax benefits from stock-based compensation.

Capital Resources and Liquidity

Cash Flow. The primary sources of cash for EOG during the three months ended March 31, 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 three months of 2018 , EOG's cash balance decreased $18 million to $816 million from $834 million at December 31, 2017 .

Net cash provided by operating activities of $1,552 million for the first three months of 2018 increased $654 million compared to the same period of 2017 primarily due to an increase in wellhead revenues ($808 million), a favorable change in net cash paid for income taxes ($78 million) and a favorable change in net cash paid for interest ($28 million), partially offset by an increase in cash operating expenses ($125 million), an unfavorable change in working capital ($118 million) and an increase in net cash paid for settlements of commodity derivative contracts ($24 million).

Net cash used in investing activities of $1,456 million for the first three months of 2018 increased by $620 million compared to the same period of 2017 due to an increase in additions to oil and gas properties ($453 million), an unfavorable change in components of working capital associated with investing activities ($81 million), a decrease in proceeds from the sales of assets ($44 million) and an increase in additions to other property, plant and equipment ($42 million).

Net cash used in financing activities of $114 million for the first three months of 2018 included cash dividend payments ($97 million) and purchases of treasury stock in connection with stock compensation plans ($17 million). Net cash used in financing activities of $115 million for the first three months of 2017 included cash dividend payments ($97 million) and purchases of treasury stock in connection with stock compensation plans ($19 million).

Total Expenditures. For the year 2018 , EOG's budget for exploration and development and other property, plant and equipment expenditures is approximately $5.4 billion to $5.8 billion, excluding acquisitions. The table below sets out components of total expenditures for the three -month periods ended March 31, 2018 and 2017 (in millions):