Current Report Filing (8-k)

Date : 08/02/2018 @ 8:25PM
Source : Edgar (US Regulatory)
Stock : Eog Resources, Inc. (EOG)
Quote : 94.01  -2.2 (-2.29%) @ 5:05AM

Current Report Filing (8-k)



 
 
 
 
 

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

FORM 8-K


CURRENT REPORT

Pursuant to Section 13 OR 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported):  August 2, 2018

_______________

EOG RESOURCES, INC.
(Exact name of registrant as specified in its charter)


Delaware
(State or other jurisdiction
 of incorporation)
1-9743
(Commission File
 Number)
47-0684736
(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)


Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

[ ]    Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

[ ]    Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

[ ]    Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

[ ]    Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

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



 
 
 
 
 




EOG RESOURCES, INC.

Item 2.02     Results of Operations and Financial Condition.

On August 2, 2018, EOG Resources, Inc. issued a press release announcing second quarter 2018 financial and operational results and third quarter and full year 2018 forecast and benchmark commodity pricing information (see Item 7.01 below).  A copy of this release is attached as Exhibit 99.1 to this filing and is incorporated herein by reference.  This information shall not be deemed to be "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section, and is not incorporated by reference into any filing under the Securities Act of 1933, as amended, or Securities Exchange Act of 1934, as amended.

Item 7.01     Regulation FD Disclosure.

Accompanying the press release announcing second quarter 2018 financial and operational results attached hereto as Exhibit 99.1 is third quarter and full year 2018 forecast and benchmark commodity pricing information for EOG Resources, Inc., which information is incorporated herein by reference.  This information shall not be deemed to be "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section, and is not incorporated by reference into any filing under the Securities Act of 1933, as amended, or Securities Exchange Act of 1934, as amended.

Item 9.01     Financial Statements and Exhibits.

(d)          Exhibits



2



SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

 
 
EOG RESOURCES, INC.
(Registrant)
 
 
 
 
 
 
 
 
 
Date: August 2, 2018
By:
/s/ TIMOTHY K. DRIGGERS
Timothy K. Driggers
Executive Vice President and Chief Financial Officer
(Principal Financial Officer and Duly Authorized Officer)


3


EXHIBIT 99.1

EOG Resources, Inc.
P.O. Box 4362, Houston, TX 77210-4362
News Release
 
For Further Information Contact:
Investors
 
David J. Streit
 
(713) 571-4902
 
Neel Panchal
 
(713) 571-4884
 
W. John Wagner
 
(713) 571-4404
 
 
 
Media and Investors
 
Kimberly M. Ehmer
 
(713) 571-4676

EOG Resources Announces Excellent Second Quarter 2018 Results; Adds Two New Premium Shale Plays and Significant Resource Potential in the Powder River Basin; Raises Common Stock Dividend 19 Percent
Beats Oil, Natural Gas and NGL Production Targets
Maintains Full-Year Exploration and Development Expenditure Target
Announces Powder River Basin Mowry and Niobrara Shale Plays and Expands Turner Sand Inventory, Adding 1,560 Net Premium Drilling Locations and 1.9 BnBoe Net Resource Potential
Increases Common Stock Dividend a Second Time in 2018; Year-to-Date Increase 31 Percent

FOR IMMEDIATE RELEASE: Thursday, August 2, 2018

HOUSTON - EOG Resources, Inc. (EOG) today reported second quarter 2018 net income of $696.7 million, or $1.20 per share. This compares to second quarter 2017 net income of $23.1 million, or $0.04 per share.
Adjusted non-GAAP net income for the second quarter 2018 was $794.9 million, or $1.37 per share, compared to adjusted non-GAAP net income of $46.7 million, or $0.08 per share, for the same prior year period.
EOG’s premium portfolio of high-return plays generated strong financial performance in the second quarter 2018. Higher commodity prices, increased production volumes and overall per-unit cost reductions resulted in a dramatic increase in adjusted non-GAAP net income, compared to the second quarter 2017. Higher commodity prices and production volumes also resulted in significant increases in discretionary cash flow and adjusted EBITDAX. Adjusted non-GAAP net income is calculated by matching hedge realizations to settlement months and making certain other adjustments in order to exclude non-recurring and certain other items. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.




Operational Highlights
EOG grew total crude oil production 15 percent year-over-year to 384,600 barrels of oil per day (Bopd), setting a company record. Total company production increased 16 percent in the second quarter 2018 compared to the same prior year period. Growth in the Delaware Basin, Eagle Ford and Powder River Basin drove EOG’s strong performance. The company maintained its target for 18 percent crude oil growth for full year 2018.
Total per-unit operating expenses declined during the second quarter 2018 compared to the same prior year period. A 16 percent reduction in depreciation, depletion and amortization rates and an 18 percent decrease in transportation rates were the largest contributors to the overall per-unit cost reduction.
EOG maintained its forecast for 2018 exploration and development expenditures of $5.4 to $5.8 billion, excluding acquisitions and non-cash transactions. The company also maintained its target to reduce average well costs by five percent in 2018.
“EOG delivered a strong quarter, meeting or exceeding expectations for production volumes, price realizations and operating expenses,” said William R. “Bill” Thomas, Chairman and Chief Executive Officer. “The EOG machine is firing on all cylinders. We grew crude oil production in five operating areas while reducing costs. Our disciplined investments across a diverse array of premium plays are generating record rates of return.”

Dividend Increase
EOG’s Board of Directors increased the cash dividend on the common stock by 19 percent. Effective with the dividend payable October 31, 2018, to holders of record as of October 17, 2018, the board declared a quarterly dividend of $0.22 per share on the common stock. The indicated annual rate is $0.88 per share.
"EOG's premium drilling strategy has reset the profitability of the company and we are confident our premium investments can sustain a larger dividend. Therefore, we increased the common stock dividend for a second time in 2018, reaffirming our commitment to deliver more value for long-term stockholders," Thomas said.

Powder River Basin
EOG significantly expanded the estimated resource potential of its 400,000 net acre position in the pressure cell of the Powder River Basin in Wyoming. The Mowry and Niobrara shales along with the Turner sand have combined estimated net resource potential of 2.1 billion barrels of oil equivalent (BnBoe). The company has identified over 1,600 net premium drilling locations, representing more than



30 years of drilling inventory at the current pace. The Powder River Basin is now EOG’s third largest asset.
EOG is operating a two-rig program in 2018 and expects to complete approximately 45 net wells. Targeted well costs across these plays range from $4.5 to $6.1 million per well. These costs have declined significantly due to faster drilling speeds and more efficient completion operations. The company plans to increase its drilling activity during 2019 and install additional infrastructure in preparation for initiating a long-term development program.
EOG has identified 141,000 net acres prospective for the Mowry. The company has identified an initial 875 net premium locations with estimated net resource potential of 1.2 BnBoe. EOG completed two Mowry wells in the second quarter. The Ballista 204-1102H and the Flatbow 423-1720H were completed with an average treated lateral length of 9,100 feet per well and average 30-day initial production rates per well of 2,190 barrels of oil equivalent per day (Boed), or 760 Bopd, 495 barrels per day (Bpd) of natural gas liquids (NGLs) and 5.6 million cubic feet per day (MMcfd) of natural gas. Well costs are targeted at $6.1 million for a 9,500 foot lateral well. Reserves per well are estimated to be 1,400 thousand barrels of oil equivalent (MBoe), net after royalty, with an oil mix of 28 percent.
In the Niobrara, EOG has identified 89,000 prospective net acres with an initial 555 net premium locations. The Niobrara has estimated net resource potential of 640 million barrels of oil equivalent (MMBoe). Reserves per well are estimated to be 1,150 MBoe, net after royalty, with a 48 percent oil mix. Targeted well cost is $5.9 million for a 9,500 foot lateral well.
EOG has completed five horizontal Niobrara wells in the past two years. The Ballista 213-1301H was brought to sales in June 2016 with a treated lateral length of 9,500 feet and 30-day initial production rate of 2,090 Boed, or 1,180 Bopd, 310 Bpd of NGLs and 3.6 MMcfd of natural gas. Since coming on-line, the well has produced 225,000 barrels of crude oil and over one billion cubic feet of natural gas.
EOG holds 169,000 net acres prospective for the Turner with 200 net premium locations remaining to be drilled. The company has completed 50 wells in the play since the last premium inventory assessment in 2017. Reserves per well are estimated to be 500 MBoe, net after royalty, with a 46 percent oil mix. Targeted well cost is $4.5 million for an 8,000 foot lateral well.
In the second quarter, EOG completed seven Turner wells with an average well cost of $4.1 million per well. These wells were completed with an average treated lateral length of 6,200 feet per well and average 30-day initial production rates per well of 915 Boed, or 760 Bopd, 50 Bpd of NGLs and 0.6 MMcfd of natural gas.
“These two new high-return plays in the Powder River Basin further diversify EOG’s premium portfolio, supporting high-return organic growth,” Thomas said. “We acquired the acreage at low cost and applied our industry-leading exploration expertise to identify the best targets. We further leveraged this



position with our low-cost operating culture. The Powder River Basin, with 2.1 BnBoe of resource potential, is poised to become a major asset in EOG’s diverse portfolio of premium plays.”

Delaware Basin
EOG has identified an additional 375 net undrilled premium locations in the Delaware Basin, raising the total to 4,815 locations and more than replacing the 250 locations drilled since the last premium inventory assessment in 2017. Cost reductions from infrastructure investments and the delineation of additional drilling targets supported the identification of the new premium locations.
During the second quarter 2018, EOG continued development of its 416,000 net acre position in the Delaware Basin with ongoing testing of additional targets and spacing. Lateral lengths increased further during the quarter, and the company increased its use of locally sourced sand beginning in June. Operations also commenced at additional locations on EOG’s new crude oil gathering system commissioned earlier in 2018.
In the Delaware Basin Wolfcamp, EOG completed the Quanah Parker 8H-11H. This four-well package was drilled on 440-foot spacing staggered across two target intervals. The wells were completed with an average treated lateral length of 9,900 feet per well and average 30-day initial production rates per well of 2,565 Boed, or 1,535 Bopd, 525 Bpd of NGLs and 3.0 MMcfd of natural gas.
In the Delaware Basin Second Bone Spring, EOG completed the Bandit 29 State Com 501H-503H and 504Y, a four-well package with an average treated lateral length of 7,100 feet per well and average 30-day initial production rates per well of 2,410 Boed, or 2,035 Bopd, 170 Bpd of NGLs and 1.3 MMcfd of natural gas.

South Texas Eagle Ford and Austin Chalk
EOG also updated its premium inventory in the Eagle Ford, which now stands at 2,300 net undrilled premium locations. The company completed 270 net wells since the last premium inventory assessment in 2017. Lower well costs and further efficiencies from shifting to longer laterals enabled EOG to convert 145 additional locations to premium.
The South Texas Eagle Ford remained a focal point of EOG’s high-rate-of-return drilling program in the second quarter 2018. With approximately two-thirds of the 7,200 total identified drilling locations remaining to be developed, the company is utilizing the flexibility of its contiguous 520,000 net acre position in the oil window of this world-class play to increase the size of drilling units to accommodate longer-lateral wells. Wells completed in the second quarter had average treated lateral lengths of 7,200 feet per well. In the western half of the field, wells completed in the second quarter had average treated lateral lengths in excess of 10,000 feet per well. At the same time, EOG continues to test various spacing



patterns and lateral targets. Strong well results speak to the play’s status as an important contributor to total company crude oil production growth.
Notable wells in the second quarter included the Sandies Creek A-F 1H-6H, a six-well package in DeWitt County, TX with an average treated lateral length of 6,500 feet per well and average 30-day initial production rates per well of 3,205 Boed, or 2,320 Bopd, 450 Bpd of NGLs and 2.6 MMcfd of natural gas. In Karnes County, TX, EOG completed the Hickok 5H-8H, a four-well package with an average treated lateral length of 5,000 feet per well and average 30-day initial production rates per well of 2,685 Boed, or 2,020 Bopd, 340 Bpd of NGLs and 2.0 MMcfd of natural gas. On the western side of the Eagle Ford in McMullen County, TX, EOG completed the Antrim Cook Unit 15H-18H, a four-well package with an average treated lateral length of 11,200 feet per well and average 30-day initial production rates per well of 2,240 Boed, or 2,210 Bopd, 15 Bpd of NGLs and 0.1 MMcfd of natural gas.
EOG also continued delineation of the South Texas Austin Chalk, completing five wells in the second quarter 2018.

Williston Basin and DJ Basin
During the second quarter 2018, EOG resumed completion activity in the Williston Basin as part of its seasonal development program and continued development of its premium DJ Basin Codell play in Wyoming. The company further lowered well costs by improving drilling and completion times and making other efficiency improvements.
In the North Dakota Williston Basin, EOG drilled nine wells and began production from two wells in the second quarter. The Clarks Creek 108 and 155-0706H targeted the Three Forks formation in McKenzie County, ND and were completed with an average treated lateral length of 9,200 feet per well and average 30-day initial production rates per well of 2,980 Boed, or 2,240 Bopd, 345 Bpd of NGLs and 2.4 MMcfd of natural gas.
EOG began production from eight wells in the DJ Basin during the second quarter 2018. In particular, a four-well package of DJ Basin Codell wells in Laramie County, WY, the Windy 576 and 577-1702H and the Windy 591 and 593-1705H, was completed with an average treated lateral length of 9,300 feet per well and average 30-day initial production rates per well of 870 Boed, or 755 Bopd, 70 Bpd of NGLs and 0.3 MMcfd of natural gas. All four of these wells are premium. They were drilled in an average of 4.4 days per well with an average cost of $3.4 million per well.

Capital Structure
At June 30, 2018, EOG’s total debt outstanding was $6.4 billion for a debt-to-total capitalization ratio of 27 percent. Considering cash on the balance sheet at the end of the second quarter, EOG’s net



debt was $5.4 billion for a net debt-to-total capitalization ratio of 24 percent. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
    
Hedging Activity
During the second quarter 2018, EOG entered into additional crude oil derivative contracts. A comprehensive summary of crude oil and natural gas derivative contracts is provided in the attached tables.

Conference Call August 3, 2018
EOG’s second quarter 2018 results conference call will be available via live audio webcast at 9 a.m. Central time (10 a.m. Eastern time) on Friday, August 3, 2018. To listen, log on to the Investors Overview page on the EOG website at http://investors.eogresources.com/overview. The webcast will be archived on EOG’s website for one year.
EOG Resources, Inc. 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 Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG."
This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "aims," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, reduce or otherwise control operating and capital costs, generate income or cash flows, pay down indebtedness or pay and/or increase dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Furthermore, EOG has presented or referenced herein or in its accompanying disclosures certain forward-looking, non-GAAP financial measures, such as free cash flow and discretionary cash flow, and certain related estimates regarding future performance, results and financial position. These forward-looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented. EOG’s actual results may differ materially from the measure and estimates presented or referenced herein. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:




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



political conditions and developments around the world (such as political instability and armed conflict), including in the areas in which EOG operates;
the use of competing energy sources and the development of alternative energy sources;
the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;
acts of war and terrorism and responses to these acts;
physical, electronic and cyber security breaches; and
the other factors described under ITEM 1A, Risk Factors, on pages 14 through 23 of EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017, and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

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

The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only “proved” reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also “probable” reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as “possible” reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC’s latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
###





EOG RESOURCES, INC.
Financial Report
(Unaudited; in millions, except per share data)
 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2018
 
2017
 
2018
 
2017
 
 
 
 
 
 
 
 
 
 
 
 
Operating Revenues and Other
$
4,238.1

 
$
2,612.5

 
$
7,919.2

 
$
5,223.0

Net Income
$
696.7

 
$
23.1

 
$
1,335.3

 
$
51.6

Net Income Per Share
 
 
 
 
 
 
 
 
 
 
 
Basic
$
1.21

 
$
0.04

 
$
2.32

 
$
0.09

Diluted
$
1.20

 
$
0.04

 
$
2.30

 
$
0.09

Average Number of Common Shares
 
 
 
 
 
 
 
 
 
 
 
Basic
   
576.1

 
 
574.4

 
 
576.0

 
 
574.2

Diluted
 
580.4

 
 
578.5

 
 
580.0

 
 
578.6

 
 
 
 
 
 
 
 
 
 
 
 
Summary Income Statements
(Unaudited; in thousands, except per share data)
 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2018
 
2017
 
2018
 
2017
Operating Revenues and Other
 
 
 
 
 
 
 
Crude Oil and Condensate
$
2,377,528

 
 $
1,445,454

 
$
4,478,836

 
$
2,875,515

Natural Gas Liquids
 
286,354

 
 
146,907

 
 
507,769

 
 
300,351

Natural Gas
 
300,845

 
 
224,008

 
 
600,611

 
 
454,610

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

 
 
(245,654
)
 
 
71,466

Gathering, Processing and Marketing
 
1,436,436

 
 
778,797

 
 
2,538,258

 
 
1,505,334

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

 
 
16,776

 
 
60,705

 
 
41,435

Total
 
4,238,077

 
 
2,612,472

 
 
7,919,239

 
 
5,223,037

Operating Expenses
 
 
 
 
 
 
 
 
 
 
 
Lease and Well
 
314,604

 
 
255,186

 
 
614,668

 
 
510,963

Transportation Costs
 
177,797

 
 
186,356

 
 
354,754

 
 
365,070

Gathering and Processing Costs
 
109,169

 
 
34,746

 
 
210,514

 
 
72,890

Exploration Costs
 
47,478

 
 
34,711

 
 
82,314

 
 
91,605

Dry Hole Costs
 
4,902

 
 
27

 
 
4,902

 
 
27

Impairments
 
51,708

 
 
78,934

 
 
116,317

 
 
272,121

Marketing Costs
 
1,420,463

 
 
790,599

 
 
2,526,853

 
 
1,527,135

Depreciation, Depletion and Amortization
 
848,674

 
 
865,384

 
 
1,597,265

 
 
1,681,420

General and Administrative
 
104,083

 
 
108,507

 
 
198,781

 
 
205,745

Taxes Other Than Income
 
194,268

 
 
130,114

 
 
373,352

 
 
260,407

Total
 
3,273,146

 
 
2,484,564

 
 
6,079,720

 
 
4,987,383

 
 
 
 
 
 
 
 
 
 
 
 
Operating Income
 
964,931

 
 
127,908

 
 
1,839,519

 
 
235,654

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

 
 
(7,824
)
 
 
8,123

 
 
 
 
 
 
 
 
 
 
 
 
Income Before Interest Expense and Income Taxes
 
956,380

 
 
132,880

 
 
1,831,695

 
 
243,777

 
 
 
 
 
 
 
 
 
 
 
 
Interest Expense, Net
 
63,444

 
 
70,413

 
 
125,400

 
 
141,928

 
 
 
 
 
 
 
 
 
 
 
 
Income Before Income Taxes
 
892,936

 
 
62,467

 
 
1,706,295

 
 
101,849

 
 
 
 
 
 
 
 
 
 
 
 
Income Tax Provision
 
196,205

 
 
39,414

 
 
370,975

 
 
50,279

 
 
 
 
 
 
 
 
 
 
 
 
Net Income
$
696,731

 
 $
23,053

 
$
1,335,320

 
$
51,570

 
 
 
 
 
 
 
 
 
 
 
 
Dividends Declared per Common Share
$
0.1850

 
$
0.1675

 
$
0.3700

 
$
0.3350

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 





EOG RESOURCES, INC.
Operating Highlights
(Unaudited)
 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2018
 
2017
 
2018
 
2017
Wellhead Volumes and Prices
 
 
 
Crude Oil and Condensate Volumes (MBbld) (A)
 
 
 
United States
 
379.2

 
 
333.1

 
 
369.5

 
 
322.8

Trinidad
 
0.8

 
 
0.8

 
 
0.9

 
 
0.8

Other International (B)
 
4.6

 
 
0.8

 
 
3.6

 
 
1.6

Total
 
384.6

 
 
334.7

 
 
374.0

 
 
325.2

 
 
 
 
 
 
 
 
 
 
 
 
Average Crude Oil and Condensate Prices ($/Bbl) (C)
 
 
 
 
 
 
 
 
 
 
 
United States
$
67.91

 
$
47.51

 
$
66.13

 
$
48.89

Trinidad
 
60.57

 
 
39.64

 
 
57.59

 
 
40.63

Other International (B)
 
70.88

 
 
35.13

 
 
71.14

 
 
44.66

Composite
 
67.93

 
 
47.46

 
 
66.16

 
 
48.85

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

 
 
86.6

 
 
106.8

 
 
82.7

Other International (B)
 

 
 

 
 

 
 

Total
 
112.9

 
 
86.6

 
 
106.8

 
 
82.7

 
 
 
 
 
 
 
 
 
 
 
 
Average Natural Gas Liquids Prices ($/Bbl) (C)
 
 
 
 
 
 
 
 
 
 
 
United States
$
27.86

 
$
18.65

 
$
26.27

 
$
20.06

Other International (B)
 

 
 

 
 

 
 

Composite
 
27.86

 
 
18.65

 
 
26.27

 
 
20.06

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

 
 
755

 
 
884

 
 
742

Trinidad
 
282

 
 
320

 
 
288

 
 
314

Other International (B)
 
32

 
 
21

 
 
30

 
 
21

Total
 
1,228

 
 
1,096

 
 
1,202

 
 
1,077

 
 
 
 
 
 
 
 
 
 
 
 
Average Natural Gas Prices ($/Mcf) (C)
 
 
 
 
 
 
 
 
 
 
 
United States
$
2.56

 
$
2.14

 
$
2.65

 
$
2.23

Trinidad
 
2.98

 
 
2.40

 
 
2.93

 
 
2.48

Other International (B)
 
4.10

 
 
3.66

 
 
4.22

 
 
3.71

Composite
 
2.69

(D) 
 
2.25

 
 
2.76

(D) 
 
2.33

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

 
 
545.6

 
 
623.6

 
 
529.2

Trinidad
 
47.8

 
 
54.1

 
 
48.8

 
 
53.1

Other International (B)
 
10.0

 
 
4.2

 
 
8.8

 
 
5.1

Total
 
702.2

 
 
603.9

 
 
681.2

 
 
587.4

 
 
 
 
 
 
 
 
 
 
 
 
Total MMBoe (E)
 
63.9

 
 
55.0

 
 
123.3

 
 
106.3


(A)
Thousand barrels per day or million cubic feet per day, as applicable.
(B)
Other International includes EOG's United Kingdom, China and Canada operations.
(C)
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 on EOG's Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2018).
(D)
Includes positive revenue adjustments of $0.39 per Mcf and $0.40 per Mcf for the three and six months ended June 30, 2018, respectively, 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 on EOG's Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2018). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees relating to certain processing and marketing agreements as Gathering and Processing Costs, instead of a deduction to Natural Gas revenues.
(E)
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.






EOG RESOURCES, INC.
Summary Balance Sheets
(Unaudited; in thousands, except share data)
 
 
June 30,
 
December 31,
 
2018
 
2017
ASSETS
Current Assets
 
 
 
 
 
Cash and Cash Equivalents
$
1,008,215

 
$
834,228

Accounts Receivable, Net
 
1,907,990

 
 
1,597,494

Inventories
 
670,994

 
 
483,865

Assets from Price Risk Management Activities
 
1,840

 
 
7,699

Income Taxes Receivable
 
364,119

 
 
113,357

Other
 
278,694

 
 
242,465

Total
 
4,231,852

 
 
3,279,108

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

 
 
52,555,741

Other Property, Plant and Equipment
 
4,141,479

 
 
3,960,759

Total Property, Plant and Equipment
 
59,460,529

 
 
56,516,500

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

 
 
25,665,037

Deferred Income Taxes
 
17,067

 
 
17,506

Other Assets
 
689,666

 
 
871,427

Total Assets
$
32,092,380

 
$
29,833,078

 
 
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
 
 
 
 
 
Accounts Payable
$
2,336,952

 
$
1,847,131

Accrued Taxes Payable
 
213,461

 
 
148,874

Dividends Payable
 
106,569

 
 
96,410

Liabilities from Price Risk Management Activities
 
195,457

 
 
50,429

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

 
 
356,235

Other
 
182,322

 
 
226,463

Total
 
4,297,301

 
 
2,725,542

 
 
 
 
 
 
 
 
 
 
 
 
Long-Term Debt
 
5,172,257

 
 
6,030,836

Other Liabilities
 
1,304,624

 
 
1,275,213

Deferred Income Taxes
 
3,865,804

 
 
3,518,214

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

 
 
205,788

Additional Paid in Capital
 
5,591,643

 
 
5,536,547

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

 
 
10,593,533

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

 
 
16,283,273

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

 
$
29,833,078








EOG RESOURCES, INC.
Summary Statements of Cash Flows
(Unaudited; in thousands)
 
Six Months Ended
 
June 30,
 
2018
 
2017
Cash Flows from Operating Activities
 
 
 
 
 
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
 
 
 
 
 
Net Income
$
1,335,320

 
$
51,570

Items Not Requiring (Providing) Cash
 
 
 
 
 
Depreciation, Depletion and Amortization
 
1,597,265

 
 
1,681,420

Impairments
 
116,317

 
 
272,121

Stock-Based Compensation Expenses
 
67,289

 
 
58,061

Deferred Income Taxes
 
347,586

 
 
35,162

Losses on Asset Dispositions, Net
 
21,286

 
 
25,674

Other, Net
 
13,507

 
 
(6,691
)
Dry Hole Costs
 
4,902

 
 
27

Mark-to-Market Commodity Derivative Contracts
 
 
 
 
 
Total (Gains) Losses
 
245,654

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

Other, Net
 
(261
)
 
 
(185
)
Changes in Components of Working Capital and Other Assets and Liabilities
 
 
 
 
 
Accounts Receivable
 
(309,751
)
 
 
103,786

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

 
 
76,704

Accrued Taxes Payable
 
22,535

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

 
 
1,976,425

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

 
 
175,260

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

 
 
79,138

Net Cash Used in Investing Activities
 
(3,089,618
)
 
 
(1,719,095
)
 
 
 
 
 
 
Financing Cash Flows
 
 
 
 
 
Dividends Paid
 
(203,610
)
 
 
(192,984
)
Treasury Stock Purchased
 
(32,023
)
 
 
(21,678
)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan
 
11,145

 
 
9,608

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

 
 

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

 
 
 
 
 
 
Increase in Cash and Cash Equivalents
 
173,987

 
 
49,548

Cash and Cash Equivalents at Beginning of Period
 
834,228

 
 
1,599,895

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

 
$
1,649,443






EOG RESOURCES, INC.
Second Quarter 2018 Well Results by Play
(Unaudited)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Wells Online
 
 
 
Initial Gross 30-Day Average Production Rate
 
 
Gross
 
Net
 
Lateral Length
(ft)
 
Crude Oil and Condensate
(Bbld) (A)
 
Natural Gas Liquids
(Bbld) (A)
 
Natural Gas
(MMcfd) (A)
 
Crude Oil Equivalent
(Boed) (B)
Delaware Basin
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Wolfcamp
 
62

 
58

 
6,400

 
1,255

 
320

 
2.3

 
1,960

Bone Spring
 
13

 
9

 
5,700

 
1,150

 
190

 
1.6

 
1,615

Leonard
 
7

 
3

 
4,500

 
965

 
350

 
2.6

 
1,745

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
South Texas Eagle Ford
 
74

 
67

 
7,200

 
1,530

 
195

 
1.1

 
1,920

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
South Texas Austin Chalk
 
5

 
5

 
7,900

 
2,355

 
470

 
2.7

 
3,275

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Powder River Basin Turner
 
7

 
6

 
6,200

 
760

 
50

 
0.6

 
915

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DJ Basin Codell
 
8

 
4

 
9,300

 
675

 
55

 
0.2

 
765

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Williston Basin Bakken/Three Forks
 
2

 
2

 
9,200

 
2,240

 
345

 
2.4

 
2,980

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(A) Barrels per day or million cubic feet per day, as applicable.
(B) Barrels of oil equivalent per day; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas.






EOG RESOURCES, INC.
Quantitative Reconciliation of Adjusted Net Income (Non-GAAP)
To Net Income (GAAP)
(Unaudited; in thousands, except per share data)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
The following chart adjusts the three-month and six-month periods ended June 30, 2018 and 2017 reported Net Income (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net losses on asset dispositions in 2018 and 2017, to add back impairment charges related to certain of EOG's assets in 2018 and 2017, to add back an early lease termination payment as the result of a legal settlement in 2017, to add back the transaction costs for the formation of a joint venture in 2017 and to eliminate certain adjustments in 2018 related to the 2017 U.S. tax reform. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
 
Three Months Ended
 
 
June 30, 2018
 
 
June 30, 2017
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Before Tax
 
 
Income Tax Impact
 
 
After
Tax
 
 
Diluted Earnings per Share
 
 
Before Tax
 
 
Income Tax Impact
 
 
After
Tax
 
 
Diluted Earnings per Share
Reported Net Income (GAAP)
$
892,936

 
$
(196,205
)
 
$
696,731

 
$
1.20

 
$
62,467

 
$
(39,414
)
 
$
23,053

 
$
0.04

Adjustments:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(Gains) Losses on Mark-to-Market Commodity Derivative Contracts
 
185,883

 
 
(40,944
)
 
 
144,939

 
 
0.25

 
 
(9,446
)
 
 
3,426

 
 
(6,020
)
 
 
(0.01
)
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts
 
(66,369
)
 
 
14,619

 
 
(51,750
)
 
 
(0.09
)
 
 
679

 
 
(245
)
 
 
434

 
 

Add: Net Losses on Asset Dispositions
 
6,317

 
 
(1,375
)
 
 
4,942

 
 
0.01

 
 
8,916

 
 
(3,151
)
 
 
5,765

 
 
0.01

Add: Impairments
 

 
 

 
 

 
 

 
 
23,397

 
 
(8,477
)
 
 
14,920

 
 
0.03

Add: Legal Settlement - Early Lease Termination
 

 
 

 
 

 
 

 
 
10,202

 
 
(3,657
)
 
 
6,545

 
 
0.01

Add: Joint Venture Transaction Costs
 

 
 

 
 

 
 

 
 
3,056

 
 
(1,095
)
 
 
1,961

 
 

Adjustments to Net Income
 
125,831

 
 
(27,700
)
 
 
98,131

 
 
0.17

 
 
36,804

 
 
(13,199
)
 
 
23,605

 
 
0.04

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Adjusted Net Income (Non-GAAP)
$
1,018,767

 
$
(223,905
)
 
$
794,862

 
$
1.37

 
$
99,271

 
$
(52,613
)
 
$
46,658

 
$
0.08

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average Number of Common Shares (GAAP)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Basic
 
 
 
 
 
 
 
 
 
 
576,135

 
 
 
 
 
 
 
 
 
 
 
574,439

Diluted
 
 
 
 
 
 
 
 
 
 
580,375

 
 
 
 
 
 
 
 
 
 
 
578,483









 
 
Six Months Ended
 
 
Six Months Ended
 
 
June 30, 2018
 
 
June 30, 2017
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Before
Tax
 
 
Income Tax Impact
 
 
After
Tax
 
 
Diluted Earnings per Share
 
 
Before
Tax
 
 
Income Tax Impact
 
 
After
Tax
 
 
Diluted Earnings per Share
Reported Net Income (GAAP)
$
1,706,295
 
$
(370,975)
 
$
1,335,320

 
$
2.30

 
$
101,849
 
$
(50,279)
 
$
51,570
 
$
0.09

Adjustments:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(Gains) Losses on Mark-to-Market Commodity Derivative Contracts
 
245,654
 
 
(54,110)
 
 
191,544

 
 
0.33

 
 
(71,466)
 
 
25,617
 
 
(45,849)
 
 
(0.08
)
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts
 
(88,334)
 
 
19,457
 
 
(68,877
)
 
 
(0.12
)
 
 
2,591
 
 
(929)
 
 
1,662
 
 

Add: Net Losses on Asset Dispositions
 
21,286
 
 
(4,699)
 
 
16,587

 
 
0.03

 
 
25,674
 
 
(8,887)
 
 
16,787
 
 
0.03

Add: Impairments
 
20,876
 
 
(4,598)
 
 
16,278

 
 
0.03

 
 
161,148
 
 
(57,764)
 
 
103,384
 
 
0.18

Add: Legal Settlement - Early Lease Termination
 
 
 
 
 

 
 

 
 
10,202
 
 
(3,657)
 
 
6,545
 
 
0.01

Add: Joint Venture Transaction Costs
 
 
 
 
 

 
 

 
 
3,056
 
 
(1,095)
 
 
1,961
 
 

Less: Tax Reform Impact
 
 
 
(6,524)
 
 
(6,524
)
 
 
(0.01
)
 
 
 
 
 
 
 
 

Adjustments to Net Income
 
199,482
 
 
(50,474)
 
 
149,008

 
 
0.26

 
 
131,205
 
 
(46,715)
 
 
84,490
 
 
0.14

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Adjusted Net Income (Non-GAAP)
$
1,905,777
 
$
(421,449)
 
$
1,484,328

 
$
2.56

 
$
233,054
 
$
(96,994)
 
$
136,060
 
$
0.23

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average Number of Common Shares (GAAP)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Basic
 
 
 
 
 
 
 
 
 
 
575,953

 
 
 
 
 
 
 
 
 
 
 
574,162

Diluted
 
 
 
 
 
 
 
 
 
 
580,007

 
 
 
 
 
 
 
 
 
 
 
578,573








EOG RESOURCES, INC.
Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP)
To Net Cash Provided by Operating Activities (GAAP)
(Unaudited; in thousands)

Calculation of Free Cash Flow (Non-GAAP)
(Unaudited; in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
The following chart reconciles the three-month and six-month periods ended June 30, 2018 and 2017 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Other Non-Current Income Taxes - Net Receivable, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG defines Free Cash Flow (Non-GAAP) for a given period as Discretionary Cash Flow (Non-GAAP) (see below reconciliation) for such period less the total cash capital expenditures excluding acquisitions incurred (Non-GAAP) during such period and dividends paid (GAAP) during such period, as is illustrated below for the six months ended June 30, 2018. EOG management uses this information for comparative purposes within the industry.
 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2018
 
2017
 
2018
 
2017
 
 
 
 
 
 
 
 
 
 
 
 
Net Cash Provided by Operating Activities (GAAP)
$
1,941,617

 
$
1,078,376

 
$
3,493,783

 
$
1,976,425

 
 
 
 
 
 
 
 
 
 
 
 
Adjustments:
 
 
 
 
 
 
 
 
 
 
 
Exploration Costs (excluding Stock-Based Compensation Expenses)
 
41,748

 
 
29,402

 
 
69,684

 
 
80,136

Other Non-Current Income Taxes - Net Receivable
 
73,441

 
 

 
 
192,362

 
 

Changes in Components of Working Capital and Other Assets and Liabilities
 
 
 
 
 
 
 
 
 
 
 
Accounts Receivable
 
200,097

 
 
(75,098
)
 
 
309,751

 
 
(103,786
)
Inventories
 
85,420

 
 
30,865

 
 
192,219

 
 
6,129

Accounts Payable
 
(402,325
)
 
 
(56,278
)
 
 
(455,977
)
 
 
(76,704
)
Accrued Taxes Payable
 
(585
)
 
 
511

 
 
(22,535
)
 
 
39,124

Other Assets
 
53,980

 
 
16,412

 
 
62,843

 
 
61,089

Other Liabilities
 
24,113

 
 
15,618

 
 
53,168

 
 
66,869

Changes in Components of Working Capital Associated with Investing and Financing Activities
 
45,267

 
 
15,814

 
 
27,279

 
 
79,138

 
 
 
 
 
 
 
 
 
 
 
 
Discretionary Cash Flow (Non-GAAP)
$
2,062,773

 
$
1,055,622

 
$
3,922,577

 
$
2,128,420

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Discretionary Cash Flow (Non-GAAP) - Percentage Increase
 
95
%
 
 
 
 
 
84
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Discretionary Cash Flow (Non-GAAP)
 
 
 
 
 
 
$
3,922,577

 
 
 
Less:
 
 
 
 
 
 
 
 
 
 
 
Total Cash Expenditures Excluding Acquisitions (Non-GAAP) (a)
 
 
 
 
 
 
 
(3,198,028
)
 
 
 
Dividends Paid (GAAP)
 
 
 
 
 
 
 
(203,610
)
 
 
 
Free Cash Flow (Non-GAAP)
 


 
 
 
 
$
520,939

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 





(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Expenditures Excluding Acquisitions (Non-GAAP) for the six months ended June 30, 2018:
 
 
 
 
 
 
 
 
 
 
 
 
Total Expenditures (GAAP)
 
 
 
 
 
 
$
3,373,573

 
 
 
Less:
 
 
 
 
 
 
 
 
 
 
 
Asset Retirement Costs
 
 
 
 
 
 
 
(30,956
)
 
 
 
Non-Cash Capital Lease Expenditures
 
 
 
 
 
 
 
(47,680
)
 
 
 
Non-Cash Acquisition Costs of Unproved Properties
 
 
 
 
 
 
 
(60,002
)
 
 
 
Acquisition Costs of Proved Properties
 
 
 
 
 
 
 
(36,907
)
 
 
 
Total Cash Expenditures Excluding Acquisitions (Non-GAAP)
 


 
 
 
 
$
3,198,028

 
 
 






EOG RESOURCES, INC.
Quantitative Reconciliation of Adjusted Earnings Before Interest Expense, Net,
Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs,
Dry Hole Costs, Impairments and Additional Items (Adjusted EBITDAX)
(Non-GAAP) to Net Income (GAAP)
(Unaudited; in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
The following chart adjusts the three-month and six-month periods ended June 30, 2018 and 2017 reported Net Income (GAAP) to Earnings Before Interest Expense (Net), Income Taxes (Income Tax Provision), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the losses on asset dispositions (Net). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (GAAP) to add back Interest Expense (Net), Income Taxes (Income Tax Provision), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2018
 
2017
 
2018
 
2017
 
 
 
 
 
 
 
 
 
 
 
 
Net Income (GAAP)
$
696,731

 
$
23,053

 
$
1,335,320