HOUSTON, Feb. 27, 2018 /PRNewswire/ --
- Delivers 20 Percent U.S. Crude Oil Production Growth and Pays
Dividend within Cash Flow
- Lowers Per-Unit Transportation and DD&A Expenses Below
Targets
- Increases Proved Reserves 18 Percent and Replaces 201 Percent
of 2017 Production at Low Finding Costs
- Raises Common Stock Dividend 10 Percent
- Targets 18 Percent Crude Oil Production Growth and 16 Percent
Total Production Growth for 2018 with Significant Free Cash Flow at
$60 Oil
- Expects to Earn Double-Digit ROCE in 2018
EOG Resources, Inc. (NYSE: EOG) (EOG) today reported fourth
quarter 2017 net income of $2,430
million, or $4.20 per share.
This compares to a fourth quarter 2016 net loss of $142 million, or $0.25 per share. For the full year 2017,
EOG reported net income of $2,583
million, or $4.46 per share,
compared to a net loss of $1,097
million, or $1.98 per share,
for the full year 2016.
Adjusted non-GAAP net income for the fourth quarter 2017 was
$401 million, or $0.69 per share, compared to an adjusted non-GAAP
net loss of $7 million, or
$0.01 per share, for the same prior
year period. Adjusted non-GAAP net income for the full year
2017 was $648 million, or
$1.12 per share, compared to an
adjusted non-GAAP net loss of $893
million, or $1.61 per share,
for the full year 2016. Adjusted non-GAAP net income (loss)
is calculated by matching hedge realizations to settlement months
and making certain other adjustments in order to exclude
non-recurring and certain other items. One of the adjusting
items in the fourth quarter and full year 2017 was a non-cash
reduction in income tax expense of $2.2
billion, or $3.75 per share,
related to the revaluation of EOG's deferred tax liability and
certain other items resulting from the Tax Cuts and Jobs Act.
For a reconciliation of non-GAAP measures to GAAP measures, please
refer to the attached tables.
Higher commodity prices, increased production volumes, well
productivity improvements and per-unit cost reductions resulted in
significant increases to adjusted non-GAAP net income,
discretionary cash flow and EBITDAX for the fourth quarter 2017
compared to the fourth quarter 2016. For a reconciliation of
non-GAAP measures to GAAP measures, please refer to the attached
tables.
Operational Highlights
Crude oil and condensate volumes in the U.S. increased 20 percent
in 2017 to 335,000 barrels of oil per day (Bopd). Increased
development activity and well productivity improvements supported
the volume increase. Total company natural gas liquids (NGLs)
volumes grew 8 percent while natural gas volumes decreased 6
percent primarily due to the sale of the company's Barnett and
Haynesville Shale dry gas assets in late 2016. Transportation
expenses decreased 11 percent and depreciation, depletion and
amortization expenses decreased 12 percent, on a per-unit
basis.
Increased development activity drove substantial volume
increases in the Eagle Ford and Delaware Basin during the fourth
quarter. Total company crude oil and condensate volumes
increased 40,200 Bopd compared to the third quarter 2017.
Natural gas liquids volumes grew 15 percent while natural gas
volumes increased 6 percent, compared to the third quarter
2017.
"EOG emerged from the industry downturn in 2017 with
unprecedented levels of efficiency and productivity, driving oil
production volumes to record levels with capital expenditures
approximately one half the prior peak," said William R. "Bill"
Thomas, Chairman and Chief Executive Officer. "EOG's
integrated teams demonstrated superb operational performance,
overcoming a major hurricane and other challenges to deliver record
production volumes and cost savings which surpassed original
targets set at the beginning of the year."
2018 Capital Plan
EOG's disciplined capital plan is designed to achieve strong
returns on capital employed and healthy growth while spending
within cash flow. The company expects to grow total company
crude oil volumes by 18 percent, generate double-digit ROCE and
cover capital investment and dividend payments within discretionary
cash flow. EOG can deliver on its 2018 plan at oil prices
below $50 and generates significant
free cash flow at a $60 oil
price.
EOG's return-based culture continues to drive cost
reductions. The company targets lower well costs and per-unit
operating expenses in 2018 despite a potentially inflationary
operating environment. EOG is also focused on driving
continued improvements in well productivity and pursuing
exploration efforts in new plays.
Capital expenditures for 2018 are expected to range from
$5.4 to $5.8
billion, including production facilities and gathering,
processing and other expenditures, and excluding
acquisitions. EOG expects to complete approximately 690 net
wells in 2018, compared to 536 net wells in 2017. Capital
will be allocated primarily to EOG's highest rate-of-return oil
assets in the Delaware Basin,
Eagle Ford, Rockies, Woodford and the Bakken.
At least 90 percent of the wells completed in 2018 are expected
to be premium. EOG has an inventory of approximately 8,000
such wells, which have a direct after-tax rate of return of at
least 30 percent assuming $40 flat
crude oil prices and $2.50 flat
natural gas prices.
"EOG enters 2018 better positioned than ever to generate
significant shareholder value through the development of its large
and diverse inventory of high rate-of-return premium wells," Thomas
said. "We are determined to maintain the discipline,
record-level operational efficiency and performance gained through
the downturn. Our deep inventory of premium wells across the
U.S. offers flexibility to adjust to changing conditions. We
also see significant opportunities to increase our premium well
inventory through organic exploration and development technology to
further extend EOG's return on capital advantage."
Dividend Increase
The board of directors increased the cash dividend on the common
stock by 10.4 percent. Effective with the dividend payable
April 30, 2018, to stockholders of
record as of April 16, 2018, the
board declared a quarterly dividend of $0.185 per share on the common stock. The
indicated annual rate is $0.74 per
share.
Delaware Basin
2017 was a watershed year for EOG in the Delaware Basin, where it successfully
integrated the Yates acquisition, identified 1,240 additional net
premium well locations, added the First Bone Spring as its fourth
premium play and reduced completed well costs by $800,000 per well. Delaware Basin crude oil and condensate
volumes increased over 80 percent in 2017 and exceeded 100,000 Bopd
in the fourth quarter 2017.
EOG continued active development of its 416,000 net acre
position in the Delaware Basin in
the fourth quarter 2017, completing 65 wells.
In the Delaware Basin Wolfcamp,
in Lea County, NM, EOG completed a
four-well package, the Calm Breeze 2 Fed Com #701-704H, with an
average treated lateral length of 7,100 feet per well and average
30-day initial production rates per well of 2,605 Bopd, 440 barrels
per day (Bpd) of NGLs and 3.7 million cubic feet per day (MMcfd) of
natural gas.
In the Delaware Basin First
Bone Spring, in Lea County, NM,
EOG completed the Righteous 6 State Com #301H with a treated
lateral length of 7,100 feet and 30-day initial production rate of
1,305 Bopd, 170 Bpd of NGLs and 1.4 MMcfd of natural gas.
In the Delaware Basin
Leonard, in Loving County, TX, EOG completed a four-well
package, the State Atlas A#3H – D#6H, with an average treated
lateral length of 9,800 feet per well and average 30-day initial
production rates per well of 1,215 Bopd, 270 Bpd of NGLs and 2.3
MMcfd of natural gas.
South Texas Eagle Ford and Austin
Chalk
EOG continues to enhance the productivity of its bellwether asset
in the South Texas Eagle Ford. Eight years after initiating
development, EOG further reduced well costs and improved well
performance during 2017 in its 520,000 net acre position in the
crude oil window of this world class play. EOG also expanded
its enhanced oil recovery program, adding 56 wells last year.
For the full year 2017, crude oil production in the Eagle
Ford and Austin Chalk increased one
percent year-over-year despite interruption to producing volumes as
a result of Hurricane Harvey.
In the fourth quarter, EOG completed 74 wells in the Eagle
Ford. These included 13 wells with lateral lengths of more
than 10,000 feet. In LaSalle County, EOG completed a
four-well package, the White 5H-8H, with an average treated lateral
length of 12,900 feet per well and average 30-day initial
production rates per well of 1,545 Bopd, 80 Bpd of NGLs and 0.5
MMcfd of natural gas. In DeWitt County, EOG completed a
four-well package, the Hendrix 8H-10H and the Hendrix 12H, with an
average treated lateral length of 6,700 feet per well and average
30-day initial production rates per well of 2,545 Bopd, 420 Bpd of
NGLs and 2.4 MMcfd of natural gas.
EOG continued to test its position in the South Texas Austin
Chalk, a geologically complex formation which lies above the South
Texas Eagle Ford, completing four net wells in the fourth
quarter.
Rockies
EOG's Wyoming Powder River Basin and DJ Basin activity both
contributed to the company's 2017 crude oil production
growth. In the Powder River Basin, EOG continued exploration
activity on its 400,000 net acre position in the core of the
play. The company tested the prospectivity of multiple target
zones and also tested the aerial extent of various targets in the
Powder River Basin during the year. In the DJ Basin, EOG
achieved significant well cost reductions during 2017 through a
focus on efficiency improvements in drilling and completion
operations.
In the fourth quarter, EOG completed nine wells in the Powder
River Basin. In Converse County, EOG completed the Mary's
Draw 453-0310H and 455-0310H wells with an average treated lateral
length of 7,300 feet per well and average 30-day initial production
rates per well of 1,280 Bopd, 610 Bpd of NGLs and 7.6 MMcfd of
natural gas. In the DJ Basin, EOG completed three wells in
the fourth quarter. This included the Big Sandy 522-2536H with a treated lateral
length of 8,800 feet and 30-day initial production rate of 1,100
Bopd, 110 Bpd of NGLs and 0.2 MMcfd of natural gas.
Reserves
At year-end 2017, total company net proved reserves were 2,527
million barrels of oil equivalent (MMBoe), an increase of 18
percent compared to year-end 2016. Net proved reserve
additions from all sources, excluding revisions due to price,
replaced 201 percent of EOG's 2017 production at a finding and
development cost of $8.71 per barrel
of oil equivalent. Revisions due to price increased net
proved reserves by 154 MMBoe and asset divestitures decreased net
proved reserves by 21 MMBoe. (For more reserves detail and a
reconciliation of non-GAAP measures to GAAP measures, please refer
to the attached tables.)
For the 30th consecutive year, internal reserves
estimates were within 5 percent of estimates independently prepared
by DeGolyer and MacNaughton.
Hedging Activity
During the fourth quarter ended December 31,
2017, EOG entered into crude oil financial price swap
contracts and differential basis swap contracts. A
comprehensive summary of crude oil and natural gas derivative
contracts is provided in the attached tables.
Capital Structure and Asset Sales
At December 31, 2017, EOG's total
debt outstanding was $6.4 billion
with a debt-to-total capitalization ratio of 28 percent.
Considering cash on the balance sheet at the end of the fourth
quarter, EOG's net debt was $5.6
billion with a net debt-to-total capitalization ratio of 25
percent. For a reconciliation of non-GAAP measures to GAAP
measures, please refer to the attached tables.
Proceeds from asset sales for the full year 2017 totaled
$227 million.
Conference Call February 28,
2018
EOG's fourth quarter and full year 2017 results conference call
will be available via live audio webcast at 8 a.m. Central time (9
a.m. Eastern time) on Wednesday,
February 28, 2018. To access the live audio webcast
and related presentation materials, log on to the Investors
Overview page on the EOG website at
http://investors.eogresources.com/overview.
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." For additional information about EOG, please visit
www.eogresources.com.
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," "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 or pay
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.
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,
INC.
|
Financial
Report
|
(Unaudited; in
millions, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Twelve Months
Ended
|
|
December
31,
|
|
December
31,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Operating
Revenues and Other
|
$
|
3,340.4
|
|
$
|
2,402.0
|
|
$
|
11,208.3
|
|
$
|
7,650.6
|
Net Income
(Loss)
|
$
|
2,430.5
|
|
$
|
(142.4)
|
|
$
|
2,582.6
|
|
$
|
(1,096.7)
|
Net Income (Loss) Per
Share
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
$
|
4.22
|
|
$
|
(0.25)
|
|
$
|
4.49
|
|
$
|
(1.98)
|
Diluted
|
$
|
4.20
|
|
$
|
(0.25)
|
|
$
|
4.46
|
|
$
|
(1.98)
|
Average Number of
Common Shares
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
575.4
|
|
|
567.3
|
|
|
574.6
|
|
|
553.4
|
Diluted
|
|
579.2
|
|
|
567.3
|
|
|
578.7
|
|
|
553.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Summary Income
Statements
|
(Unaudited; in
thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Twelve Months
Ended
|
|
December
31,
|
|
December
31,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Net Operating
Revenues and Other
|
|
|
|
|
|
|
|
Crude Oil
and Condensate
|
$
|
1,929,471
|
|
$
|
1,366,223
|
|
$
|
6,256,396
|
|
$
|
4,317,341
|
Natural
Gas Liquids
|
|
249,172
|
|
|
137,849
|
|
|
729,561
|
|
|
437,250
|
Natural
Gas
|
|
246,922
|
|
|
215,373
|
|
|
921,934
|
|
|
742,152
|
Gains
(Losses) on Mark-to-Market Commodity Derivative
Contracts
|
|
(45,032)
|
|
|
(65,787)
|
|
|
19,828
|
|
|
(99,608)
|
Gathering,
Processing and Marketing
|
|
1,008,385
|
|
|
614,594
|
|
|
3,298,087
|
|
|
1,966,259
|
Gains
(Losses) on Asset Dispositions, Net
|
|
(65,220)
|
|
|
104,034
|
|
|
(99,096)
|
|
|
205,835
|
Other,
Net
|
|
16,741
|
|
|
29,753
|
|
|
81,610
|
|
|
81,403
|
Total
|
|
3,340,439
|
|
|
2,402,039
|
|
|
11,208,320
|
|
|
7,650,632
|
Operating
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
Lease and
Well
|
|
281,941
|
|
|
241,846
|
|
|
1,044,847
|
|
|
927,452
|
Transportation Costs
|
|
191,717
|
|
|
193,319
|
|
|
740,352
|
|
|
764,106
|
Gathering
and Processing Costs
|
|
43,295
|
|
|
32,516
|
|
|
148,775
|
|
|
122,901
|
Exploration Costs
|
|
22,941
|
|
|
39,110
|
|
|
145,342
|
|
|
124,953
|
Dry Hole
Costs
|
|
4,532
|
|
|
193
|
|
|
4,609
|
|
|
10,657
|
Impairments
|
|
153,442
|
|
|
297,946
|
|
|
479,240
|
|
|
620,267
|
Marketing
Costs
|
|
1,009,566
|
|
|
634,248
|
|
|
3,330,237
|
|
|
2,007,635
|
Depreciation, Depletion and Amortization
|
|
881,745
|
|
|
862,524
|
|
|
3,409,387
|
|
|
3,553,417
|
General
and Administrative
|
|
117,005
|
|
|
102,182
|
|
|
434,467
|
|
|
394,815
|
Taxes
Other Than Income
|
|
158,343
|
|
|
103,642
|
|
|
544,662
|
|
|
349,710
|
Total
|
|
2,864,527
|
|
|
2,507,526
|
|
|
10,281,918
|
|
|
8,875,913
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
(Loss)
|
|
475,912
|
|
|
(105,487)
|
|
|
926,402
|
|
|
(1,225,281)
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income
(Expense), Net
|
|
803
|
|
|
(17,198)
|
|
|
9,152
|
|
|
(50,543)
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) Before
Interest Expense and Income Taxes
|
476,715
|
|
|
(122,685)
|
|
|
935,554
|
|
|
(1,275,824)
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense,
Net
|
|
63,362
|
|
|
71,325
|
|
|
274,372
|
|
|
281,681
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) Before
Income Taxes
|
|
413,353
|
|
|
(194,010)
|
|
|
661,182
|
|
|
(1,557,505)
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax
Benefit
|
|
(2,017,115)
|
|
|
(51,658)
|
|
|
(1,921,397)
|
|
|
(460,819)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
(Loss)
|
$
|
2,430,468
|
|
$
|
(142,352)
|
|
$
|
2,582,579
|
|
$
|
(1,096,686)
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends Declared
per Common Share
|
$
|
0.1675
|
|
$
|
0.1675
|
|
$
|
0.6700
|
|
$
|
0.6700
|
|
|
EOG RESOURCES,
INC.
|
Operating
Highlights
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Twelve Months
Ended
|
|
December
31,
|
|
December
31,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Wellhead Volumes
and Prices
|
|
|
|
Crude Oil and
Condensate Volumes (MBbld) (A)
|
|
|
|
United
States
|
|
366.9
|
|
|
306.0
|
|
|
335.0
|
|
|
278.3
|
Trinidad
|
|
1.1
|
|
|
0.9
|
|
|
0.9
|
|
|
0.8
|
Other International
(B)
|
|
0.1
|
|
|
4.8
|
|
|
0.8
|
|
|
3.4
|
Total
|
|
368.1
|
|
|
311.7
|
|
|
336.7
|
|
|
282.5
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Crude Oil and
Condensate Prices ($/Bbl) (C)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$
|
56.95
|
|
$
|
47.93
|
|
$
|
50.91
|
|
$
|
41.84
|
Trinidad
|
|
46.56
|
|
|
40.04
|
|
|
42.30
|
|
|
33.76
|
Other International
(B)
|
|
45.72
|
|
|
38.96
|
|
|
57.20
|
|
|
36.72
|
Composite
|
|
56.97
|
|
|
47.76
|
|
|
50.91
|
|
|
41.76
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids
Volumes (MBbld) (A)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
|
100.6
|
|
|
80.9
|
|
|
88.4
|
|
|
81.6
|
Other International
(B)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
Total
|
|
100.6
|
|
|
80.9
|
|
|
88.4
|
|
|
81.6
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Natural Gas
Liquids Prices ($/Bbl) (C)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$
|
26.92
|
|
$
|
18.51
|
|
$
|
22.61
|
|
$
|
14.63
|
Other International
(B)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
Composite
|
|
26.92
|
|
|
18.51
|
|
|
22.61
|
|
|
14.63
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Volumes
(MMcfd) (A)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
|
829
|
|
|
800
|
|
|
765
|
|
|
810
|
Trinidad
|
|
299
|
|
|
323
|
|
|
313
|
|
|
340
|
Other International
(B)
|
|
32
|
|
|
22
|
|
|
25
|
|
|
25
|
Total
|
|
1,160
|
|
|
1,145
|
|
|
1,103
|
|
|
1,175
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Natural Gas
Prices ($/Mcf) (C)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$
|
2.17
|
|
$
|
2.05
|
|
$
|
2.20
|
|
$
|
1.60
|
Trinidad
|
|
2.52
|
|
|
1.89
|
|
|
2.38
|
|
|
1.88
|
Other International
(B)
|
|
4.23
|
|
|
3.85
|
|
|
3.89
|
|
|
3.64
|
Composite
|
|
2.31
|
|
|
2.04
|
|
|
2.29
|
|
|
1.73
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Equivalent
Volumes (MBoed) (D)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
|
605.6
|
|
|
520.3
|
|
|
551.0
|
|
|
494.9
|
Trinidad
|
|
51.0
|
|
|
54.6
|
|
|
53.0
|
|
|
57.5
|
Other International
(B)
|
|
5.4
|
|
|
8.6
|
|
|
4.9
|
|
|
7.6
|
Total
|
|
662.0
|
|
|
583.5
|
|
|
608.9
|
|
|
560.0
|
|
|
|
|
|
|
|
|
|
|
|
|
Total MMBoe
(D)
|
|
60.9
|
|
|
53.7
|
|
|
222.3
|
|
|
205.0
|
|
|
|
|
|
|
|
|
|
|
|
|
(A) Thousand barrels
per day or million cubic feet per day, as applicable.
|
(B) Other
International includes EOG's United Kingdom, China, Canada and
Argentina operations. The Argentina operations were sold in
the third quarter of 2016.
|
(C) Dollars per
barrel or per thousand cubic feet, as applicable. Excludes
the impact of financial commodity derivative
instruments.
|
(D) Thousand barrels
of oil equivalent per day or million barrels of oil equivalent, as
applicable; 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. 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)
|
|
|
|
|
|
|
|
December
31,
|
|
December
31,
|
|
2017
|
|
2016
|
ASSETS
|
Current
Assets
|
|
|
|
|
|
Cash and Cash
Equivalents
|
$
|
834,228
|
|
$
|
1,599,895
|
Accounts Receivable,
Net
|
|
1,597,494
|
|
|
1,216,320
|
Inventories
|
|
483,865
|
|
|
350,017
|
Assets from Price Risk
Management Activities
|
|
7,699
|
|
|
-
|
Income Taxes
Receivable
|
|
113,357
|
|
|
12,305
|
Other
|
|
242,465
|
|
|
206,679
|
Total
|
|
3,279,108
|
|
|
3,385,216
|
|
|
|
|
|
|
Property, Plant
and Equipment
|
|
|
|
|
|
Oil and Gas Properties
(Successful Efforts Method)
|
|
52,555,741
|
|
|
49,592,091
|
Other Property, Plant and
Equipment
|
|
3,960,759
|
|
|
4,008,564
|
Total Property, Plant and Equipment
|
|
56,516,500
|
|
|
53,600,655
|
Less: Accumulated
Depreciation, Depletion and Amortization
|
|
(30,851,463)
|
|
|
(27,893,577)
|
Total Property, Plant and Equipment, Net
|
|
25,665,037
|
|
|
25,707,078
|
Deferred Income
Taxes
|
|
17,506
|
|
|
16,140
|
Other
Assets
|
|
871,427
|
|
|
190,767
|
Total
Assets
|
$
|
29,833,078
|
|
$
|
29,299,201
|
|
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS' EQUITY
|
Current
Liabilities
|
|
|
|
|
|
Accounts Payable
|
$
|
1,847,131
|
|
$
|
1,511,826
|
Accrued Taxes
Payable
|
|
148,874
|
|
|
118,411
|
Dividends Payable
|
|
96,410
|
|
|
96,120
|
Liabilities from Price Risk
Management Activities
|
|
50,429
|
|
|
61,817
|
Current Portion of Long-Term
Debt
|
|
356,235
|
|
|
6,579
|
Other
|
|
226,463
|
|
|
232,538
|
Total
|
|
2,725,542
|
|
|
2,027,291
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term
Debt
|
|
6,030,836
|
|
|
6,979,779
|
Other
Liabilities
|
|
1,275,213
|
|
|
1,282,142
|
Deferred Income
Taxes
|
|
3,518,214
|
|
|
5,028,408
|
Commitments and
Contingencies
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders'
Equity
|
|
|
|
|
|
Common Stock, $0.01 Par,
1,280,000,000 Shares and 640,000,000
Shares Authorized
at December 31, 2017 and 2016, respectively, and
578,827,768 Shares and
576,950,272 Shares Issued at
December 31, 2017 and
2016, respectively
|
|
205,788
|
|
|
205,770
|
Additional Paid in
Capital
|
|
5,536,547
|
|
|
5,420,385
|
Accumulated Other
Comprehensive Loss
|
|
(19,297)
|
|
|
(19,010)
|
Retained Earnings
|
|
10,593,533
|
|
|
8,398,118
|
Common Stock Held in
Treasury, 350,961 Shares and 250,155 Shares at December 31, 2017
and 2016, respectively
|
|
(33,298)
|
|
|
(23,682)
|
Total Stockholders' Equity
|
|
16,283,273
|
|
|
13,981,581
|
Total Liabilities
and Stockholders' Equity
|
$
|
29,833,078
|
|
$
|
29,299,201
|
|
|
EOG RESOURCES,
INC.
|
Summary Statements
of Cash Flows
|
(Unaudited; in
thousands)
|
|
|
|
|
|
|
|
Twelve Months
Ended
|
|
December
31,
|
|
2017
|
|
2016
|
Cash Flows from
Operating Activities
|
|
|
|
|
|
Reconciliation of Net
Income (Loss) to Net Cash Provided by Operating
Activities:
|
|
|
|
|
|
Net Income (Loss)
|
$
|
2,582,579
|
|
|
(1,096,686)
|
Items Not Requiring
(Providing) Cash
|
|
|
|
|
|
Depreciation, Depletion and Amortization
|
|
3,409,387
|
|
|
3,553,417
|
Impairments
|
|
479,240
|
|
|
620,267
|
Stock-Based Compensation Expenses
|
|
133,849
|
|
|
128,090
|
Deferred Income Taxes
|
|
(1,473,872)
|
|
|
(515,206)
|
(Gains) Losses on Asset Dispositions, Net
|
|
99,096
|
|
|
(205,835)
|
Other, Net
|
|
6,546
|
|
|
61,690
|
Dry Hole Costs
|
|
4,609
|
|
|
10,657
|
Mark-to-Market Commodity
Derivative Contracts
|
|
|
|
|
|
Total (Gains) Losses
|
|
(19,828)
|
|
|
99,608
|
Net Cash Received from (Payments for) Settlements of Commodity
Derivative Contracts
|
|
7,438
|
|
|
(22,219)
|
Excess Tax Benefits from
Stock-Based Compensation
|
|
-
|
|
|
(29,357)
|
Other, Net
|
|
1,204
|
|
|
10,971
|
Changes in Components of
Working Capital and Other Assets and Liabilities
|
|
|
|
|
|
Accounts Receivable
|
|
(392,131)
|
|
|
(232,799)
|
Inventories
|
|
(174,548)
|
|
|
170,694
|
Accounts Payable
|
|
324,192
|
|
|
(74,048)
|
Accrued Taxes Payable
|
|
(63,937)
|
|
|
92,782
|
Other Assets
|
|
(658,609)
|
|
|
(40,636)
|
Other Liabilities
|
|
(89,871)
|
|
|
(16,225)
|
Changes in Components of
Working Capital Associated with Investing and Financing
Activities
|
|
89,992
|
|
|
(156,102)
|
Net Cash Provided
by Operating Activities
|
|
4,265,336
|
|
|
2,359,063
|
|
|
|
|
|
|
Investing Cash
Flows
|
|
|
|
|
|
Additions to Oil and Gas
Properties
|
|
(3,950,918)
|
|
|
(2,489,756)
|
Additions to Other Property,
Plant and Equipment
|
|
(173,324)
|
|
|
(93,039)
|
Proceeds from Sales of
Assets
|
|
226,768
|
|
|
1,119,215
|
Net Cash Received from Yates
Transaction
|
|
-
|
|
|
54,534
|
Changes in Components of
Working Capital Associated with Investing Activities
|
|
(89,935)
|
|
|
156,102
|
Net Cash Used in
Investing Activities
|
|
(3,987,409)
|
|
|
(1,252,944)
|
|
|
|
|
|
|
Financing Cash
Flows
|
|
|
|
|
|
Net Commercial Paper
Repayments
|
|
-
|
|
|
(259,718)
|
Long-Term Debt
Borrowings
|
|
-
|
|
|
991,097
|
Long-Term Debt
Repayments
|
|
(600,000)
|
|
|
(563,829)
|
Dividends Paid
|
|
(386,531)
|
|
|
(372,845)
|
Excess Tax Benefits from
Stock-Based Compensation
|
|
-
|
|
|
29,357
|
Treasury Stock
Purchased
|
|
(63,408)
|
|
|
(82,125)
|
Proceeds from Stock Options
Exercised and Employee Stock Purchase Plan
|
|
20,840
|
|
|
23,296
|
Debt Issuance
Costs
|
|
-
|
|
|
(1,602)
|
Repayment of Capital Lease
Obligation
|
|
(6,555)
|
|
|
(6,353)
|
Other, Net
|
|
(57)
|
|
|
-
|
Net Cash Used in
Financing Activities
|
|
(1,035,711)
|
|
|
(242,722)
|
|
|
|
|
|
|
Effect of Exchange
Rate Changes on Cash
|
|
(7,883)
|
|
|
17,992
|
|
|
|
|
|
|
Increase
(Decrease) in Cash and Cash Equivalents
|
|
(765,667)
|
|
|
881,389
|
Cash and Cash
Equivalents at Beginning of Period
|
|
1,599,895
|
|
|
718,506
|
Cash and Cash
Equivalents at End of Period
|
$
|
834,228
|
|
$
|
1,599,895
|
|
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Adjusted Net Income (Loss)
(Non-GAAP)
|
To Net Income
(Loss) (GAAP)
|
(Unaudited; in
thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following chart
adjusts the three-month and twelve-month periods ended December 31,
2017 and 2016 reported Net Income (Loss) (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
(gains) losses on asset dispositions in 2017 and 2016, to add back
impairment charges related to certain of EOG's assets in 2017 and
2016, to eliminate the impact of the Trinidad tax settlement in
2016, to add back certain voluntary retirement expense in 2016, to
add back acquisition costs and state apportionment change related
to the Yates transaction in 2016, 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, to add back joint interest billings deemed uncollectible
in 2017, and to eliminate the impact of tax reform in 2017.
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 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
|
|
December 31,
2017
|
|
December 31,
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
|
|
|
|
Diluted
|
|
|
|
Income
|
|
|
|
Diluted
|
|
Before
|
|
Tax
|
|
After
|
|
Earnings
|
|
Before
|
|
Tax
|
|
After
|
|
Earnings
|
|
Tax
|
|
Impact
|
|
Tax
|
|
per
Share
|
|
Tax
|
|
Impact
|
|
Tax
|
|
per
Share
|
Reported Net
Income (Loss) (GAAP)
|
$
413,353
|
|
$2,017,115
|
|
$
2,430,468
|
|
$
4.20
|
|
$
(194,010)
|
|
$
51,658
|
|
$
(142,352)
|
|
$
(0.25)
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Gains) Losses on
Mark-to-Market Commodity
Derivative Contracts
|
45,032
|
|
(16,142)
|
|
28,890
|
|
0.05
|
|
65,787
|
|
(23,583)
|
|
42,204
|
|
0.07
|
Net Cash Received
from (Payments for)
Settlements of Commodity
Derivative
Contracts
|
2,708
|
|
(971)
|
|
1,737
|
|
-
|
|
-
|
|
29
|
|
29
|
|
-
|
Add: Net
(Gains) Losses on Asset Dispositions
|
65,220
|
|
(23,315)
|
|
41,905
|
|
0.07
|
|
(104,034)
|
|
36,856
|
|
(67,178)
|
|
(0.12)
|
Add:
Impairments
|
100,304
|
|
(35,954)
|
|
64,350
|
|
0.11
|
|
217,839
|
|
(76,728)
|
|
141,111
|
|
0.25
|
Add: Voluntary
Retirement Expense
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(57)
|
|
(57)
|
|
-
|
Add:
Acquisition - State Apportionment Change
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
16,424
|
|
16,424
|
|
0.03
|
Add:
Acquisition Costs
|
-
|
|
-
|
|
-
|
|
-
|
|
2,173
|
|
955
|
|
3,128
|
|
0.01
|
Add: Joint
Interest Billings Deemed Uncollectible
|
4,528
|
|
(1,623)
|
|
2,905
|
|
0.01
|
|
-
|
|
-
|
|
-
|
|
-
|
Less: Tax
Reform Impact
|
-
|
|
(2,169,376)
|
|
(2,169,376)
|
|
(3.75)
|
|
-
|
|
-
|
|
-
|
|
-
|
Adjustments to Net
Income (Loss)
|
217,792
|
|
(2,247,381)
|
|
(2,029,589)
|
|
(3.51)
|
|
181,765
|
|
(46,104)
|
|
135,661
|
|
0.24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Net
Income (Loss) (Non-GAAP)
|
$
631,145
|
|
$
(230,266)
|
|
$
400,879
|
|
$
0.69
|
|
$
(12,245)
|
|
$
5,554
|
|
$
(6,691)
|
|
$
(0.01)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Number of
Common Shares (GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
575,394
|
|
|
|
|
|
|
|
567,337
|
Diluted
|
|
|
|
|
|
|
579,203
|
|
|
|
|
|
|
|
567,337
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve Months
Ended
|
|
Twelve Months
Ended
|
|
December 31,
2017
|
|
December 31,
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
|
|
|
|
Diluted
|
|
|
|
Income
|
|
|
|
Diluted
|
|
Before
|
|
Tax
|
|
After
|
|
Earnings
|
|
Before
|
|
Tax
|
|
After
|
|
Earnings
|
|
Tax
|
|
Impact
|
|
Tax
|
|
per
Share
|
|
Tax
|
|
Impact
|
|
Tax
|
|
per
Share
|
Reported Net
Income (Loss) (GAAP)
|
$
661,182
|
|
$1,921,397
|
|
$
2,582,579
|
|
$
4.46
|
|
$(1,557,505)
|
|
$
460,819
|
|
$(1,096,686)
|
|
$
(1.98)
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Gains) Losses on
Mark-to-Market Commodity
Derivative Contracts
|
(19,828)
|
|
7,107
|
|
(12,721)
|
|
(0.02)
|
|
99,608
|
|
(35,640)
|
|
63,968
|
|
0.12
|
Net Cash Received
from (Payments for)
Settlements of Commodity
Derivative
Contracts
|
7,438
|
|
(2,666)
|
|
4,772
|
|
0.01
|
|
(22,219)
|
|
7,950
|
|
(14,269)
|
|
(0.03)
|
Add: Net
(Gains) Losses on Asset Dispositions
|
99,096
|
|
(35,270)
|
|
63,826
|
|
0.11
|
|
(205,835)
|
|
61,491
|
|
(144,344)
|
|
(0.26)
|
Add:
Impairments
|
261,452
|
|
(93,718)
|
|
167,734
|
|
0.29
|
|
320,617
|
|
(113,368)
|
|
207,249
|
|
0.37
|
Add: Trinidad
Tax Settlement
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
43,000
|
|
43,000
|
|
0.08
|
Add: Voluntary
Retirement Expense
|
-
|
|
-
|
|
-
|
|
-
|
|
42,054
|
|
(15,047)
|
|
27,007
|
|
0.05
|
Add:
Acquisition - State Apportionment Change
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
16,424
|
|
16,424
|
|
0.03
|
Add:
Acquisition Costs
|
-
|
|
-
|
|
-
|
|
-
|
|
5,100
|
|
(88)
|
|
5,012
|
|
0.01
|
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
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
Add: Joint
Interest Billings Deemed Uncollectible
|
4,528
|
|
(1,623)
|
|
2,905
|
|
0.01
|
|
-
|
|
-
|
|
-
|
|
-
|
Less: Tax
Reform Impact
|
-
|
|
(2,169,376)
|
|
(2,169,376)
|
|
(3.75)
|
|
-
|
|
-
|
|
-
|
|
-
|
Adjustments to Net
Income (Loss)
|
365,944
|
|
(2,300,298)
|
|
(1,934,354)
|
|
(3.34)
|
|
239,325
|
|
(35,278)
|
|
204,047
|
|
0.37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Net
Income (Loss) (Non-GAAP)
|
$
1,027,126
|
|
$
(378,901)
|
|
$
648,225
|
|
$
1.12
|
|
$(1,318,180)
|
|
$
425,541
|
|
$
(892,639)
|
|
$
(1.61)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Number of
Common Shares (GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
574,620
|
|
|
|
|
|
|
|
553,384
|
Diluted
|
|
|
|
|
|
|
578,693
|
|
|
|
|
|
|
|
553,384
|
|
|
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 twelve-month periods ended December
31, 2017 and 2016 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), Excess Tax Benefits from Stock-Based
Compensation, Other Non-Current Taxes,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 twelve months ended December 31,
2017. EOG management uses this information for comparative
purposes within the industry.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Twelve Months
Ended
|
|
|
December
31,
|
|
December
31,
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by
Operating Activities (GAAP)
|
$
|
1,327,548
|
|
$
|
804,745
|
|
$
|
4,265,336
|
|
$
|
2,359,063
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration Costs
(excluding Stock-Based Compensation Expenses)
|
|
|
16,420
|
|
|
33,931
|
|
|
122,688
|
|
|
104,199
|
Excess Tax Benefits
from Stock-Based Compensation
|
|
|
-
|
|
|
7,286
|
|
|
-
|
|
|
29,357
|
Other Non-Current
Taxes (Non-Current Impact of the Tax Cut Jobs Act)
|
|
|
(513,404)
|
|
|
-
|
|
|
(513,404)
|
|
|
-
|
Changes in Components
of Working Capital and Other Assets and Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
Receivable
|
|
|
366,686
|
|
|
220,939
|
|
|
392,131
|
|
|
232,799
|
Inventories
|
|
|
156,874
|
|
|
(33,131)
|
|
|
174,548
|
|
|
(170,694)
|
Accounts
Payable
|
|
|
(211,298)
|
|
|
(127,165)
|
|
|
(324,192)
|
|
|
74,048
|
Accrued Taxes
Payable
|
|
|
13,970
|
|
|
21,214
|
|
|
63,937
|
|
|
(92,782)
|
Other
Assets
|
|
|
574,669
|
|
|
28,110
|
|
|
658,609
|
|
|
40,636
|
Other
Liabilities
|
|
|
20,647
|
|
|
53,024
|
|
|
89,871
|
|
|
16,225
|
Changes in Components
of Working Capital Associated with Investing and Financing Activities
|
|
|
(210,365)
|
|
|
36,342
|
|
|
(89,992)
|
|
|
156,102
|
|
Discretionary Cash
Flow (Non-GAAP)
|
|
$
|
1,541,747
|
|
$
|
1,045,295
|
|
$
|
4,839,532
|
|
$
|
2,748,953
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discretionary Cash
Flow (Non-GAAP) - Percentage Increase
|
|
|
47%
|
|
|
|
|
|
76%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discretionary Cash
Flow (Non-GAAP)
|
|
|
|
$
|
4,839,532
|
|
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Cash
Expenditures Excluding Acquisitions
(Non-GAAP)(a)
|
|
|
(4,228,859)
|
|
|
|
Dividends Paid
(GAAP)
|
|
|
|
|
|
(386,531)
|
|
|
|
Free Cash Flow
(Non-GAAP)
|
|
|
|
|
$
|
224,142
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) See below
reconciliation of Total Expenditures (GAAP) to Total Cash
Expenditures Excluding Acquisitions (Non-GAAP) for the twelve
months ended December 31, 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Expenditures
(GAAP)
|
|
|
|
|
$
|
4,612,746
|
|
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Retirement Costs
|
|
|
|
|
|
(55,592)
|
|
|
|
Non-Cash Acquisition Costs of Unproved Properties
|
|
|
(255,711)
|
|
|
|
Acquisition Costs of Proved Properties
|
|
|
|
|
(72,584)
|
|
|
|
Total Cash
Expenditures Excluding Acquisitions (Non-GAAP)
|
|
$
|
4,228,859
|
|
|
|
|
|
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 (Loss) (GAAP)
|
(Unaudited; in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
The following chart
adjusts the three-month and twelve-month periods ended December 31,
2017 and 2016 reported Net Income (Loss) (GAAP) to Earnings Before
Interest Expense (Net), Income Taxes (Income Tax Provision
(Benefit)), 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 net (gains) 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 (Loss) (GAAP) to add back
Interest Expense (Net), Income Taxes (Income Tax Provision
(Benefit)), 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
|
|
Twelve Months
Ended
|
|
December
31,
|
|
December
31,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
(GAAP)
|
$
|
2,430,468
|
|
$
|
(142,352)
|
|
$
|
2,582,579
|
|
$
|
(1,096,686)
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense,
Net
|
|
63,362
|
|
|
71,325
|
|
|
274,372
|
|
|
281,681
|
Income Tax Provision
(Benefit)
|
|
(2,017,115)
|
|
|
(51,658)
|
|
|
(1,921,397)
|
|
|
(460,819)
|
Depreciation, Depletion and
Amortization
|
|
881,745
|
|
|
862,524
|
|
|
3,409,387
|
|
|
3,553,417
|
Exploration Costs
|
|
22,941
|
|
|
39,110
|
|
|
145,342
|
|
|
124,953
|
Dry Hole Costs
|
|
4,532
|
|
|
193
|
|
|
4,609
|
|
|
10,657
|
Impairments
|
|
153,442
|
|
|
297,946
|
|
|
479,240
|
|
|
620,267
|
EBITDAX
(Non-GAAP)
|
|
1,539,375
|
|
|
1,077,088
|
|
|
4,974,132
|
|
|
3,033,470
|
Total (Gains) Losses on MTM
Commodity Derivative Contracts
|
|
45,032
|
|
|
65,787
|
|
|
(19,828)
|
|
|
99,608
|
Net Cash Received from
(Payments for) Settlements of Commodity Derivative
Contracts
|
|
2,708
|
|
|
-
|
|
|
7,438
|
|
|
(22,219)
|
(Gains) Losses on Asset
Dispositions, Net
|
|
65,220
|
|
|
(104,034)
|
|
|
99,096
|
|
|
(205,835)
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX
(Non-GAAP)
|
$
|
1,652,335
|
|
$
|
1,038,841
|
|
$
|
5,060,838
|
|
$
|
2,905,024
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX
(Non-GAAP) - Percentage Increase
|
|
59%
|
|
|
|
|
|
74%
|
|
|
|
|
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Net Debt (Non-GAAP) and Total
|
Capitalization
(Non-GAAP) as Used in the Calculation of
|
The Net
Debt-to-Total Capitalization Ratio (Non-GAAP) to
|
Current and
Long-Term Debt (GAAP) and Total Capitalization
(GAAP)
|
(Unaudited; in
millions, except ratio data)
|
|
|
|
|
|
|
The following chart
reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP)
and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP),
as used in the Net Debt-to-Total Capitalization ratio
calculation. A portion of the cash is associated with
international subsidiaries; tax considerations may impact debt
paydown. EOG believes this presentation may be useful to
investors who follow the practice of some industry analysts who
utilize Net Debt and Total Capitalization (Non-GAAP) in their Net
Debt-to-Total Capitalization ratio calculation. EOG
management uses this information for comparative purposes within
the industry.
|
|
|
|
|
|
|
|
At
|
|
At
|
|
December
31,
|
|
December
31,
|
|
2017
|
|
2016
|
|
|
|
|
|
|
Total Stockholders'
Equity - (a)
|
$
|
16,283
|
|
$
|
13,982
|
|
|
|
|
|
|
Current and Long-Term
Debt (GAAP) - (b)
|
|
6,387
|
|
|
6,986
|
Less:
Cash
|
|
(834)
|
|
|
(1,600)
|
Net Debt (Non-GAAP) -
(c)
|
|
5,553
|
|
|
5,386
|
|
|
|
|
|
|
Total Capitalization
(GAAP) - (a) + (b)
|
$
|
22,670
|
|
$
|
20,968
|
|
|
|
|
|
|
Total Capitalization
(Non-GAAP) - (a) + (c)
|
$
|
21,836
|
|
$
|
19,368
|
|
|
|
|
|
|
Debt-to-Total
Capitalization (GAAP) - (b) / [(a) + (b)]
|
|
28%
|
|
|
33%
|
|
|
|
|
|
|
Net Debt-to-Total
Capitalization (Non-GAAP) - (c) / [(a) + (c)]
|
|
25%
|
|
|
28%
|
|
|
EOG RESOURCES,
INC.
|
Reserves
Supplemental Data
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
2017 NET PROVED
RESERVES RECONCILIATION SUMMARY
|
|
|
|
United
|
|
|
|
Other
|
|
|
|
|
States
|
|
Trinidad
|
|
International
|
|
Total
|
|
CRUDE OIL &
CONDENSATE (MMBbl)
|
|
|
|
|
|
|
|
|
Beginning
Reserves
|
1,168.5
|
|
0.8
|
|
8.3
|
|
1,177.6
|
|
Revisions
|
58.0
|
|
0.1
|
|
(0.2)
|
|
57.9
|
|
Purchases in
place
|
1.1
|
|
-
|
|
-
|
|
1.1
|
|
Extensions,
discoveries and other additions
|
207.1
|
|
0.3
|
|
0.1
|
|
207.5
|
|
Sales in
place
|
(8.4)
|
|
-
|
|
-
|
|
(8.4)
|
|
Production
|
(122.2)
|
|
(0.3)
|
|
(0.2)
|
|
(122.7)
|
|
Ending
Reserves
|
1,304.1
|
|
0.9
|
|
8.0
|
|
1,313.0
|
|
|
NATURAL GAS
LIQUIDS (MMBbl)
|
|
|
|
|
|
|
|
|
Beginning
Reserves
|
416.4
|
|
-
|
|
-
|
|
416.4
|
|
Revisions
|
46.9
|
|
-
|
|
-
|
|
46.9
|
|
Purchases in
place
|
0.4
|
|
-
|
|
-
|
|
0.4
|
|
Extensions,
discoveries and other additions
|
75.0
|
|
-
|
|
-
|
|
75.0
|
|
Sales in
place
|
(2.9)
|
|
-
|
|
-
|
|
(2.9)
|
|
Production
|
(32.3)
|
|
-
|
|
-
|
|
(32.3)
|
|
Ending
Reserves
|
503.5
|
|
-
|
|
-
|
|
503.5
|
|
|
NATURAL GAS
(Bcf)
|
|
|
|
|
|
|
|
|
Beginning
Reserves
|
3,021.2
|
|
280.9
|
|
15.8
|
|
3,317.9
|
|
Revisions
|
602.8
|
|
(27.4)
|
|
8.6
|
|
584.0
|
|
Purchases in
place
|
4.8
|
|
-
|
|
-
|
|
4.8
|
|
Extensions,
discoveries and other additions
|
619.3
|
|
174.2
|
|
35.9
|
|
829.4
|
|
Sales in
place
|
(56.4)
|
|
-
|
|
-
|
|
(56.4)
|
|
Production
|
(293.2)
|
|
(114.3)
|
|
(9.1)
|
|
(416.6)
|
|
Ending
Reserves
|
3,898.5
|
|
313.4
|
|
51.2
|
|
4,263.1
|
|
|
OIL EQUIVALENTS
(MMBoe)
|
|
|
|
|
|
|
|
|
Beginning
Reserves
|
2,088.4
|
|
47.7
|
|
10.9
|
|
2,147.0
|
|
Revisions
|
205.3
|
|
(4.5)
|
|
1.2
|
|
202.0
|
|
Purchases in
place
|
2.3
|
|
-
|
|
-
|
|
2.3
|
|
Extensions,
discoveries and other additions
|
385.4
|
|
29.3
|
|
6.1
|
|
420.8
|
|
Sales in
place
|
(20.7)
|
|
-
|
|
-
|
|
(20.7)
|
|
Production
|
(203.4)
|
|
(19.4)
|
|
(1.6)
|
|
(224.4)
|
|
Ending
Reserves
|
2,457.3
|
|
53.1
|
|
16.6
|
|
2,527.0
|
|
|
Net Proved
Developed Reserves (MMBoe)
|
|
|
|
|
|
|
|
|
At December 31,
2016
|
1,038.5
|
|
44.5
|
|
10.9
|
|
1,093.9
|
|
At December 31,
2017
|
1,300.7
|
|
50.8
|
|
12.8
|
|
1,364.3
|
|
|
2017 EXPLORATION
AND DEVELOPMENT EXPENDITURES ($ Millions)
|
|
|
|
United
|
|
|
|
Other
|
|
|
|
|
States
|
|
Trinidad
|
|
International
|
|
Total
|
|
|
Acquisition Cost of
Unproved Properties
|
$
424.1
|
|
$
2.4
|
|
$
-
|
|
$
426.5
|
|
Exploration
Costs
|
144.5
|
|
62.6
|
|
16.5
|
|
223.6
|
|
Development
Costs
|
3,540.7
|
|
107.2
|
|
13.2
|
|
3,661.1
|
|
Total
Drilling
|
4,109.3
|
|
172.2
|
|
29.7
|
|
4,311.2
|
|
Acquisition Cost of
Proved Properties
|
72.6
|
|
-
|
|
-
|
|
72.6
|
|
Asset Retirement
Costs
|
50.2
|
|
2.3
|
|
3.1
|
|
55.6
|
|
Total Exploration
& Development Expenditures
|
4,232.1
|
|
174.5
|
|
32.8
|
|
4,439.4
|
|
Gathering, Processing
and Other
|
173.0
|
|
0.1
|
|
0.2
|
|
173.3
|
|
Total
Expenditures
|
4,405.1
|
|
174.6
|
|
33.0
|
|
4,612.7
|
|
Proceeds from Sales
in Place
|
(226.6)
|
|
-
|
|
-
|
|
(226.6)
|
|
Net
Expenditures
|
$
4,178.5
|
|
$
174.6
|
|
$
33.0
|
|
$
4,386.1
|
|
|
RESERVE
REPLACEMENT COSTS ($ / Boe ) *
|
|
|
|
|
|
|
|
|
All-in Total, Net
of Revisions
|
$
6.58
|
|
$
6.94
|
|
$
4.07
|
|
$
6.56
|
|
All-in Total,
Excluding Revisions Due to Price
|
$
8.88
|
|
$
6.94
|
|
$
4.07
|
|
$
8.71
|
|
|
RESERVE
REPLACEMENT *
|
|
|
|
|
|
|
|
|
Drilling
Only
|
190%
|
|
151%
|
|
381%
|
|
188%
|
|
All-in Total, Net
of Revisions & Dispositions
|
281%
|
|
128%
|
|
456%
|
|
269%
|
|
All-in Total,
Excluding Revisions Due to Price
|
206%
|
|
128%
|
|
456%
|
|
201%
|
|
All-in Total,
Liquids
|
244%
|
|
133%
|
|
-50%
|
|
244%
|
|
|
*
See attached reconciliation schedule for calculation
methodology
|
|
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Total Exploration and Development Expenditures
(Non-GAAP)
|
As Used in the
Calculation of Reserve Replacement Costs ($ / BOE)
|
To Total Costs
Incurred in Exploration and Development Activities
(GAAP)
|
(Unaudited; in
millions, except ratio information)
|
|
|
|
|
|
|
|
|
|
The following chart
reconciles Total Costs Incurred in Exploration and Development
Activities (GAAP) to Total Exploration and Development Expenditures
(Non-GAAP), as used in the calculation of Reserve Replacement Costs
per Boe. There are numerous ways that industry participants
present Reserve Replacement Costs, including an "All-In"
calculation, which reflects total exploration and development
expenditures divided by total net proved reserve additions from all
sources. Combined with Reserve Replacement, these statistics
provide management and investors with an indication of the results
of the current year capital investment program. Reserve
Replacement Cost statistics are widely recognized and reported by
industry participants and are used by EOG management and other
third parties for comparative purposes within the industry.
Please note that the actual cost of adding reserves will vary from
the reported statistics due to timing differences in reserve
bookings and capital expenditures. Accordingly, some analysts
use three or five year averages of reported statistics, while
others prefer to estimate future costs. EOG has not included
future capital costs to develop proved undeveloped reserves in
exploration and development expenditures.
|
|
|
|
|
|
|
|
|
|
For the Twelve
Months Ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
United
|
|
|
|
Other
|
|
|
|
|
States
|
|
Trinidad
|
|
International
|
|
Total
|
|
|
Total Costs Incurred
in Exploration and Development Activities (GAAP)
|
$
4,232.1
|
|
$
174.5
|
|
$
32.8
|
|
$
4,439.4
|
|
Less: Asset
Retirement Costs
|
(50.2)
|
|
(2.3)
|
|
(3.1)
|
|
(55.6)
|
|
Non-Cash Acquisition Costs of Unproved Properties
|
(255.7)
|
|
-
|
|
-
|
|
(255.7)
|
|
Non-Cash Acquisition Costs of Proved Properties
|
(26.2)
|
|
-
|
|
-
|
|
(26.2)
|
|
Total Exploration
& Development Expenditures (Non-GAAP) (a)
|
$
3,900.0
|
|
$
172.2
|
|
$
29.7
|
|
$
4,101.9
|
|
|
Total Expenditures
(GAAP)
|
$
4,405.1
|
|
$
174.6
|
|
$
33.0
|
|
$
4,612.7
|
|
Less: Asset
Retirement Costs
|
(50.2)
|
|
(2.3)
|
|
(3.1)
|
|
(55.6)
|
|
Non-Cash Acquisition Costs of Unproved Properties
|
(255.7)
|
|
-
|
|
-
|
|
(255.7)
|
|
Non-Cash Acquisition Costs of Proved Properties
|
(26.2)
|
|
-
|
|
-
|
|
(26.2)
|
|
Total Cash
Expenditures (Non-GAAP)
|
$
4,073.0
|
|
$
172.3
|
|
$
29.9
|
|
$
4,275.2
|
|
|
Net Proved Reserve
Additions From All Sources - Oil Equivalents
(MMBoe)
|
|
|
|
|
|
|
|
|
Revisions due to
price (b)
|
154.0
|
|
-
|
|
-
|
|
154.0
|
|
Revisions other than
price
|
51.3
|
|
(4.5)
|
|
1.2
|
|
48.0
|
|
Purchases in
place
|
2.3
|
|
-
|
|
-
|
|
2.3
|
|
Extensions,
discoveries and other additions (c)
|
385.4
|
|
29.3
|
|
6.1
|
|
420.8
|
|
Total Proved
Reserve Additions (d)
|
593.0
|
|
24.8
|
|
7.3
|
|
625.1
|
|
Sales in
place
|
(20.7)
|
|
-
|
|
-
|
|
(20.7)
|
|
Net Proved Reserve
Additions From All Sources (e)
|
572.3
|
|
24.8
|
|
7.3
|
|
604.4
|
|
|
Production
(f)
|
203.4
|
|
19.4
|
|
1.6
|
|
224.4
|
|
|
RESERVE
REPLACEMENT COSTS ($ / Boe)
|
|
|
|
|
|
|
|
|
All-in Total, Net
of Revisions (a / d)
|
$
6.58
|
|
$
6.94
|
|
$
4.07
|
|
$
6.56
|
|
All-in Total,
Excluding Revisions Due to Price (a / (d - b))
|
$
8.88
|
|
$
6.94
|
|
$
4.07
|
|
$
8.71
|
|
|
RESERVE
REPLACEMENT
|
|
|
|
|
|
|
|
|
Drilling Only (c /
f)
|
190%
|
|
151%
|
|
381%
|
|
188%
|
|
All-in Total, Net
of Revisions & Dispositions (e / f)
|
281%
|
|
128%
|
|
456%
|
|
269%
|
|
All-in Total,
Excluding Revisions Due to Price ((e - b ) /
f)
|
206%
|
|
128%
|
|
456%
|
|
201%
|
|
|
Net Proved Reserve
Additions From All Sources - Liquids (MMBbl)
|
|
|
|
|
|
|
|
|
Revisions
|
104.9
|
|
0.1
|
|
(0.2)
|
|
104.8
|
|
Purchases in
place
|
1.5
|
|
-
|
|
-
|
|
1.5
|
|
Extensions,
discoveries and other additions (g)
|
282.1
|
|
0.3
|
|
0.1
|
|
282.5
|
|
Total Proved
Reserve Additions
|
388.5
|
|
0.4
|
|
(0.1)
|
|
388.8
|
|
Sales in
place
|
(11.3)
|
|
-
|
|
-
|
|
(11.3)
|
|
Net Proved Reserve
Additions From All Sources (h)
|
377.2
|
|
0.4
|
|
(0.1)
|
|
377.5
|
|
|
Production
(i)
|
154.5
|
|
0.3
|
|
0.2
|
|
155.0
|
|
|
RESERVE
REPLACEMENT - LIQUIDS
|
|
|
|
|
|
|
|
|
Drilling Only (g /
i)
|
183%
|
|
100%
|
|
50%
|
|
182%
|
|
All-in Total, Net
of Revisions & Dispositions (h / i)
|
244%
|
|
133%
|
|
-50%
|
|
244%
|
|
|
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Drillbit Exploration and Development Expenditures
(Non-GAAP)
|
As Used in the
Calculation of Proved Developed Reserve Replacement Costs ($ /
BOE)
|
To Total Costs
Incurred in Exploration and Development Activities
(GAAP)
|
(Unaudited; in
millions, except ratio information)
|
|
|
|
|
|
|
|
|
|
The following chart
reconciles Total Costs Incurred in Exploration and Development
Activities (GAAP) to Drillbit Exploration and Development
Expenditures (Non-GAAP), as used in the calculation of Proved
Developed Reserve Replacement Costs per Boe. These statistics
provide management and investors with an indication of the results
of the current year capital investment program. Reserve
Replacement Cost statistics are widely recognized and reported by
industry participants and are used by EOG management and other
third parties for comparative purposes within the
industry.
|
|
|
|
|
|
|
|
|
|
|
For the Twelve
Months Ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
PROVED DEVELOPED
RESERVE REPLACEMENT COSTS ($ / Boe)
|
|
|
|
|
|
|
|
|
Total Costs Incurred
in Exploration and Development Activities (GAAP)
|
|
|
|
|
|
|
$
4,439.4
|
|
Less: Asset
Retirement Costs
|
|
|
|
|
|
|
(55.6)
|
|
Acquisition Costs of Unproved Properties
|
|
|
|
|
|
|
(426.5)
|
|
Acquisition Cost of Proved Properties
|
|
|
|
|
|
|
(72.6)
|
|
Drillbit
Exploration & Development Expenditures (Non-GAAP)
(j)
|
|
|
|
|
|
|
$
3,884.7
|
|
|
Total Proved Reserves
- Extensions, discoveries and other additions (MMBoe)
|
|
|
|
|
|
|
420.8
|
|
Add: Conversion of
proved undeveloped reserves to proved developed
|
|
|
|
|
|
|
152.6
|
|
Less: Proved
undeveloped extensions and discoveries
|
|
|
|
|
|
|
(237.4)
|
|
Proved Developed
Reserves - Extensions and discoveries (MMBoe)
|
|
|
|
|
|
|
336.0
|
|
|
Total Proved Reserves
- Revisions (MMBoe)
|
|
|
|
|
|
|
202.0
|
|
Less: Proved
Undeveloped Reserves - Revisions
|
|
|
|
|
|
|
(33.1)
|
|
Proved Developed - Revisions due to price
|
|
|
|
|
|
|
(143.0)
|
|
Proved Developed
Reserves - Revisions other than price (MMBoe)
|
|
|
|
|
|
|
25.9
|
|
|
Proved Developed
Reserves - Extensions and discoveries plus revisions other than
price (MMBoe) (k)
|
|
|
|
361.9
|
|
|
|
|
|
|
|
|
|
|
Proved Developed
Reserve Replacement Cost Excluding Revisions Due to Price ($ / Boe)
(j / k)
|
|
|
|
$
10.73
|
|
|
|
EOG RESOURCES,
INC.
|
Crude Oil and
Natural Gas Financial Commodity
|
Derivative
Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
EOG accounts for
financial commodity derivative contracts using the mark-to-market
accounting method. Prices received by EOG for its crude oil
production generally vary from NYMEX West Texas Intermediate prices
due to adjustments for delivery location (basis) and other
factors. EOG 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 through February 20, 2018. The weighted average
price differential expressed in $/Bbl represents the amount of
reduction to Cushing, Oklahoma, prices for the notional volumes
expressed in Bbld covered by the basis swap contracts.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Midland
Differential Basis Swap Contracts
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
Average
Price
|
|
|
|
|
|
|
|
|
|
Volume
|
|
Differential
|
|
|
|
|
|
|
|
|
|
(Bbld)
|
|
($/Bbl)
|
2018
|
|
|
|
|
|
|
|
|
|
|
January 1, 2018
through February 28, 2018 (closed)
|
|
|
|
|
|
|
15,000
|
|
$
1.063
|
March 1, 2018 through
December 31, 2018
|
|
|
|
|
|
|
15,000
|
|
1.063
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
|
|
|
|
|
|
|
|
|
January 1, 2019
through December 31, 2019
|
|
|
|
|
|
|
20,000
|
|
$
1.075
|
|
|
|
|
|
|
|
|
|
|
|
|
EOG has entered into
additional 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 through February 20, 2018. The weighted average
price differential expressed in $/Bbl represents the amount of
addition to Cushing, Oklahoma, prices for the notional volumes
expressed in Bbld covered by the basis swap contracts.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast
Differential Basis Swap Contracts
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
Average
Price
|
|
|
|
|
|
|
|
|
|
Volume
|
|
Differential
|
|
|
|
|
|
|
|
|
|
(Bbld)
|
|
($/Bbl)
|
2018
|
|
|
|
|
|
|
|
|
|
|
January 1, 2018
through February 28, 2018 (closed)
|
|
|
|
|
|
|
37,000
|
|
$
3.818
|
March 1, 2018 through
December 31, 2018
|
|
|
|
|
|
|
37,000
|
|
3.818
|
|
|
|
|
|
|
|
|
|
|
|
|
On March 14, 2017,
EOG executed the optional early termination provision granting EOG
the right to terminate certain 2017 crude oil price swaps with
notional volumes of 30,000 Bbld at a weighted average price of
$50.05 per Bbl for the period March 1, 2017 through June 30,
2017. EOG received cash of $4.6 million for the early
termination of these contracts, which are included in the table
below. Presented below is a comprehensive summary of EOG's
crude oil price swap contracts through February 20, 2018, with
notional volumes expressed in Bbld and prices expressed in
$/Bbl.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Price
Swap Contracts
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Volume
|
|
Average
Price
|
|
|
|
|
|
|
|
|
|
(Bbld)
|
|
($/Bbl)
|
2017
|
|
|
|
|
|
|
|
|
|
|
January 1, 2017
through February 28, 2017 (closed)
|
|
|
|
|
|
|
35,000
|
|
$
50.04
|
March 1, 2017 through
June 30, 2017 (closed)
|
|
|
|
|
|
|
30,000
|
|
50.05
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
January 2018
(closed)
|
|
|
|
|
|
|
134,000
|
|
$
60.04
|
February 1, 2018
through December 31, 2018
|
|
|
|
|
|
|
134,000
|
|
60.04
|
|
|
|
|
|
|
|
|
|
|
|
|
On March 14, 2017,
EOG entered into a crude oil price swap contract for the period
March 1, 2017 through June 30, 2017, with notional volumes of 5,000
Bbld at a price of $48.81 per Bbl. This contract offset the
remaining 2017 crude oil price swap contract for the same time
period with notional volumes of 5,000 Bbld at a price of $50.00 per
Bbl. The net cash EOG received for settling these contracts
was $0.7 million. The offsetting contracts are excluded from
the above table.
|
|
|
|
|
|
|
|
|
|
|
|
|
Presented below is a
comprehensive summary of EOG's natural gas price swap contracts
through February 20, 2018, with notional volumes expressed in
MMBtud and prices expressed in $/MMBtu.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Price
Swap Contracts
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Volume
|
|
Average
Price
|
|
|
|
|
|
|
|
|
|
(MMBtud)
|
|
($/MMBtu)
|
2017
|
|
|
|
|
|
|
|
|
|
|
March 1, 2017 through
November 30, 2017 (closed)
|
|
|
|
|
|
|
30,000
|
|
$
3.10
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
March 1, 2018 through
November 30, 2018
|
|
|
|
|
|
|
35,000
|
|
$
3.00
|
|
|
|
|
|
|
|
|
|
|
|
|
EOG has sold call
options which establish a ceiling price for the sale of notional
volumes of natural gas as specified in the call option
contracts. The call options require that EOG pay the
difference between the call option strike price and either the
average or last business day NYMEX Henry Hub natural gas price for
the contract month (Henry Hub Index Price) in the event the Henry
Hub Index Price is above the call option strike
price.
|
|
|
|
|
|
|
|
|
|
|
|
|
In addition, EOG has
purchased put options which establish a floor price for the sale of
notional volumes of natural gas as specified in the put option
contracts. The put options grant EOG the right to receive the
difference between the put option strike price and the Henry Hub
Index Price in the event the Henry Hub Index Price is below the put
option strike price. Presented below is a comprehensive
summary of EOG's natural gas call and put option contracts through
February 20, 2018, with notional volumes expressed in MMBtud and
prices expressed in $/MMBtu.
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Option
Contracts
|
|
|
|
|
|
Call Options
Sold
|
|
Put Options
Purchased
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
Weighted
|
|
|
|
|
|
Volume
|
|
Average
Price
|
|
Volume
|
|
Average
Price
|
|
|
|
|
|
(MMBtud)
|
|
($/MMBtu)
|
|
(MMBtud)
|
|
($/MMBtu)
|
2017
|
|
|
|
|
|
|
|
|
|
|
March 1, 2017 through
November 30, 2017 (closed)
|
|
|
213,750
|
|
$
3.44
|
|
171,000
|
|
$
2.92
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
March 1, 2018 through
November 30, 2018
|
|
|
120,000
|
|
$
3.38
|
|
96,000
|
|
$
2.94
|
|
|
|
|
|
|
|
|
|
|
|
|
EOG has also entered
into natural gas collar contracts, which establish ceiling and
floor prices for the sale of notional volumes of natural gas as
specified in the collar contracts. The collars require that
EOG pay the difference between the ceiling price and the Henry Hub
Index Price in the event the Henry Hub Index Price is above the
ceiling price. The collars grant EOG the right to receive the
difference between the floor price and the Henry Hub Index Price in
the event the Henry Hub Index Price is below the floor price.
Presented below is a comprehensive summary of EOG's natural gas
collar contracts through February 20, 2018, with notional volumes
expressed in MMBtud and prices expressed in
$/MMBtu.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Collar
Contracts
|
|
|
|
|
|
|
|
|
|
Weighted Average
Price ($/MMBtu)
|
|
|
|
|
|
|
|
Volume
|
|
|
|
|
|
|
|
|
|
|
|
(MMBtud)
|
|
Ceiling
Price
|
|
Floor
Price
|
2017
|
|
|
|
|
|
|
|
|
|
|
March 1, 2017 through
November 30, 2017 (closed)
|
|
|
|
|
80,000
|
|
$
3.69
|
|
$
3.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Definitions
|
|
|
|
|
|
|
|
|
|
|
Bbld
|
Barrels per
day
|
|
|
|
|
|
|
|
|
|
$/Bbl
|
Dollars per
barrel
|
|
|
|
|
|
|
MMBtud
|
Million British
thermal units per day
|
|
|
|
|
$/MMBtu
|
Dollars per million
British thermal units
|
|
|
|
|
NYMEX
|
U.S. New York
Mercantile Exchange
|
|
|
|
|
|
EOG RESOURCES,
INC.
|
Direct After-Tax
Rate of Return (ATROR)
|
|
The calculation of
our direct after-tax rate of return (ATROR) with respect to our
capital expenditure program for a particular play or well is based
on the estimated recoverable reserves ("net" to EOG's interest) for
all wells in such play or such well (as the case may be), the
estimated net present value (NPV) of the future net cash flows from
such reserves (for which we utilize certain assumptions regarding
future commodity prices and operating costs) and our direct net
costs incurred in drilling or acquiring (as the case may be) such
wells or well (as the case may be). As such, our direct ATROR
with respect to our capital expenditures for a particular play or
well cannot be calculated from our consolidated financial
statements.
|
|
|
Direct
ATROR
|
Based on Cash Flow
and Time Value of Money
|
- Estimated
future commodity prices and operating costs
|
- Costs
incurred to drill, complete and equip a well, including
facilities
|
Excludes Indirect
Capital
|
- Gathering
and Processing and other Midstream
|
- Land,
Seismic, Geological and Geophysical
|
|
Payback ~12 Months on
100% Direct ATROR Wells
|
First Five Years ~1/2
Estimated Ultimate Recovery Produced but ~3/4 of NPV
Captured
|
|
|
Return on Equity /
Return on Capital Employed
|
Based on GAAP Accrual
Accounting
|
Includes All Indirect
Capital and Growth Capital for Infrastructure
|
- Eagle Ford,
Bakken, Permian Facilities
|
- Gathering
and Processing
|
Includes Legacy Gas
Capital and Capital from Mature Wells
|
|
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of After-Tax Net Interest Expense (Non-GAAP),
Adjusted Net Income (Loss)
|
(Non-GAAP), Net
Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the
Calculations of
|
Return on Capital
Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest
Expense (GAAP),
|
Net Income (Loss)
(GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization
(GAAP), Respectively
|
(Unaudited; in
millions, except ratio data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following chart
reconciles Net Interest Expense (GAAP), Net Income (Loss) (GAAP),
Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP)
to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income
(Loss) (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization
(Non-GAAP), respectively, as used in the Return on Capital Employed
(ROCE) and Return on Equity (ROE) calculations. EOG believes
this presentation may be useful to investors who follow the
practice of some industry analysts who utilize After-Tax Net
Interest Expense, Adjusted Net Income (Loss), Net Debt and Total
Capitalization (Non-GAAP) in their ROCE and ROE calculations.
EOG management uses this information for purposes of comparing its
financial performance with the financial performance of other
companies in the industry.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
2013
|
Return on Capital
Employed (ROCE) (Non-GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Interest Expense
(GAAP)
|
$
|
274
|
|
$
|
282
|
|
$
|
237
|
|
$
|
201
|
|
|
|
Tax Benefit Imputed
(based on 35%)
|
|
(96)
|
|
|
(99)
|
|
|
(83)
|
|
|
(70)
|
|
|
|
After-Tax Net
Interest Expense (Non-GAAP) - (a)
|
$
|
178
|
|
$
|
183
|
|
$
|
154
|
|
$
|
131
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
(GAAP) -
(b)
|
$
|
2,583
|
|
$
|
(1,097)
|
|
$
|
(4,525)
|
|
$
|
2,915
|
|
|
|
Adjustments to Net
Income (Loss), Net of Tax (See Accompanying Schedules)
|
(1,934)
|
(a)
|
|
204
|
(b)
|
|
4,559
|
(c)
|
|
(199)
|
(d)
|
|
|
Adjusted Net Income
(Loss) (Non-GAAP) - (c)
|
$
|
649
|
|
$
|
(893)
|
|
$
|
34
|
|
$
|
2,716
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Stockholders'
Equity Before Retained Earnings Adjustment (GAAP) -
(d)
|
$
|
16,283
|
|
$
|
13,982
|
|
$
|
12,943
|
|
$
|
17,713
|
|
$
|
15,418
|
Less: Tax Reform
Impact
|
|
(2,169)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
Total Stockholders'
Equity (Non-GAAP) - (e)
|
$
|
14,114
|
|
$
|
13,982
|
|
$
|
12,943
|
|
$
|
17,713
|
|
$
|
15,418
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Total
Stockholders' Equity (GAAP) * - (f)
|
$
|
15,133
|
|
$
|
13,463
|
|
$
|
15,328
|
|
$
|
16,566
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Total
Stockholders' Equity (Non-GAAP) * -
(g)
|
$
|
14,048
|
|
$
|
13,463
|
|
$
|
15,328
|
|
$
|
16,566
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current and Long-Term
Debt (GAAP) - (h)
|
$
|
6,387
|
|
$
|
6,986
|
|
$
|
6,655
|
|
$
|
5,906
|
|
$
|
5,909
|
Less: Cash
|
|
(834)
|
|
|
(1,600)
|
|
|
(719)
|
|
|
(2,087)
|
|
|
(1,318)
|
Net Debt (Non-GAAP) -
(i)
|
$
|
5,553
|
|
$
|
5,386
|
|
$
|
5,936
|
|
$
|
3,819
|
|
$
|
4,591
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
(GAAP) - (d) + (h)
|
$
|
22,670
|
|
$
|
20,968
|
|
$
|
19,598
|
|
$
|
23,619
|
|
$
|
21,327
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
(Non-GAAP) - (e) + (i)
|
$
|
19,667
|
|
$
|
19,368
|
|
$
|
18,879
|
|
$
|
21,532
|
|
$
|
20,009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Total
Capitalization (Non-GAAP) * - (j)
|
$
|
19,518
|
|
$
|
19,124
|
|
$
|
20,206
|
|
$
|
20,771
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROCE (GAAP Net
Income) - [(a) + (b)] /
(j)
|
|
14.1%
|
|
|
-4.8%
|
|
|
-21.6%
|
|
|
14.7%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROCE (Non-GAAP
Adjusted Net Income) - [(a) + (c)] /
(j)
|
|
4.2%
|
|
|
-3.7%
|
|
|
0.9%
|
|
|
13.7%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Return on Equity
(ROE)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROE (GAAP) (GAAP
Net Income) - (b) / (f)
|
|
17.1%
|
|
|
-8.1%
|
|
|
-29.5%
|
|
|
17.6%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROE (Non-GAAP)
(Non-GAAP Adjusted Net Income) - (c) / (g)
|
|
4.6%
|
|
|
-6.6%
|
|
|
0.2%
|
|
|
16.4%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* Average for the
current and immediately preceding year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments to Net
Income (Loss) (GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) See below
schedule for detail of adjustments to Net Income (Loss) (GAAP) in
2017:
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31, 2017
|
|
|
|
|
|
|
|
|
Before
|
|
|
Income
Tax
|
|
|
After
|
|
|
|
|
|
|
|
|
Tax
|
|
|
Impact
|
|
|
Tax
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Add: Mark-to-Market Commodity Derivative Contracts
Impact
|
$
|
(12)
|
|
$
|
4
|
|
$
|
(8)
|
|
|
|
|
|
|
Add: Impairments of Certain Assets
|
|
261
|
|
|
(93)
|
|
|
168
|
|
|
|
|
|
|
Add: Net Losses on Asset Dispositions
|
|
99
|
|
|
(35)
|
|
|
64
|
|
|
|
|
|
|
Add: Legal Settlement - Early Lease
Termination
|
|
10
|
|
|
(4)
|
|
|
6
|
|
|
|
|
|
|
Add: Joint Venture Transaction Costs
|
|
3
|
|
|
(1)
|
|
|
2
|
|
|
|
|
|
|
Add: Joint Interest Billings Deemed
Uncollectible
|
|
5
|
|
|
(2)
|
|
|
3
|
|
|
|
|
|
|
Less: Tax Reform Impact
|
|
-
|
|
|
(2,169)
|
|
|
(2,169)
|
|
|
|
|
|
|
Total
|
$
|
366
|
|
$
|
(2,300)
|
|
$
|
(1,934)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(b) See below
schedule for detail of adjustments to Net Income (Loss) (GAAP) in
2016:
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31, 2016
|
|
|
|
|
|
|
|
|
Before
|
|
|
Income
Tax
|
|
|
After
|
|
|
|
|
|
|
|
|
Tax
|
|
|
Impact
|
|
|
Tax
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Add: Mark-to-Market Commodity Derivative Contracts
Impact
|
$
|
77
|
|
$
|
(28)
|
|
$
|
49
|
|
|
|
|
|
|
Add: Impairments of Certain Assets
|
|
321
|
|
|
(113)
|
|
|
208
|
|
|
|
|
|
|
Less: Net Gains on Asset Dispositions
|
|
(206)
|
|
|
62
|
|
|
(144)
|
|
|
|
|
|
|
Add: Trinidad Tax Settlement
|
|
-
|
|
|
43
|
|
|
43
|
|
|
|
|
|
|
Add: Voluntary Retirement Expense
|
|
42
|
|
|
(15)
|
|
|
27
|
|
|
|
|
|
|
Add: Acquisition - State Apportionment
Change
|
|
-
|
|
|
16
|
|
|
16
|
|
|
|
|
|
|
Add: Acquisition Costs
|
|
5
|
|
|
-
|
|
|
5
|
|
|
|
|
|
|
Total
|
$
|
239
|
|
$
|
(35)
|
|
$
|
204
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(c) See below
schedule for detail of adjustments to Net Income (Loss) (GAAP) in
2015:
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31, 2015
|
|
|
|
|
|
|
|
|
Before
|
|
|
Income
Tax
|
|
|
After
|
|
|
|
|
|
|
|
|
Tax
|
|
|
Impact
|
|
|
Tax
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Add: Mark-to-Market Commodity Derivative Contracts
Impact
|
$
|
668
|
|
$
|
(238)
|
|
$
|
430
|
|
|
|
|
|
|
Add: Impairments of Certain Assets
|
|
6,308
|
|
|
(2,183)
|
|
|
4,125
|
|
|
|
|
|
|
Less: Texas Margin Tax Rate Reduction
|
|
-
|
|
|
(20)
|
|
|
(20)
|
|
|
|
|
|
|
Add: Legal Settlement - Early Leasehold
Termination
|
|
19
|
|
|
(6)
|
|
|
13
|
|
|
|
|
|
|
Add: Severance Costs
|
|
9
|
|
|
(3)
|
|
|
6
|
|
|
|
|
|
|
Add: Net Losses on Asset Dispositions
|
|
9
|
|
|
(4)
|
|
|
5
|
|
|
|
|
|
|
Total
|
$
|
7,013
|
|
$
|
(2,454)
|
|
$
|
4,559
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(d) See below
schedule for detail of adjustments to Net Income (Loss) (GAAP) in
2014:
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31, 2014
|
|
|
|
|
|
|
|
|
Before
|
|
|
Income
Tax
|
|
|
After
|
|
|
|
|
|
|
|
|
Tax
|
|
|
Impact
|
|
|
Tax
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less: Mark-to-Market Commodity Derivative Contracts
Impact
|
$
|
(800)
|
|
$
|
285
|
|
$
|
(515)
|
|
|
|
|
|
|
Add: Impairments of Certain Assets
|
|
824
|
|
|
(271)
|
|
|
553
|
|
|
|
|
|
|
Less: Net Gains on Asset Dispositions
|
|
(508)
|
|
|
21
|
|
|
(487)
|
|
|
|
|
|
|
Add: Tax Expense Related to the Repatriation of
Accumulated Foreign Earnings in Future Years
|
|
-
|
|
|
250
|
|
|
250
|
|
|
|
|
|
|
Total
|
$
|
(484)
|
|
$
|
285
|
|
$
|
(199)
|
|
|
|
|
|
|
|
|
EOG RESOURCES,
INC.
|
First Quarter and
Full Year 2018 Forecast and Benchmark Commodity
Pricing
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) First Quarter and
Full Year 2018 Forecast
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The forecast items
for the first quarter and full year 2018 set forth below for EOG
Resources, Inc. (EOG) are based on current available information
and expectations as of the date of the accompanying press
release. EOG undertakes no obligation, other than as required
by applicable law, to update or revise this forecast, whether as a
result of new information, subsequent events, anticipated or
unanticipated circumstances or otherwise. This forecast,
which should be read in conjunction with the accompanying press
release and EOG's related Current Report on Form 8-K filing,
replaces and supersedes any previously issued guidance or
forecast.
|
|
|
|
|
|
|
|
|
|
|
|
|
(b) Benchmark
Commodity Pricing
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EOG bases United
States and Trinidad crude oil and condensate price differentials
upon the West Texas Intermediate crude oil price at Cushing,
Oklahoma, using the simple average of the NYMEX settlement prices
for each trading day within the applicable calendar
month.
|
|
|
|
|
|
|
|
|
|
|
|
|
EOG bases United
States natural gas price differentials upon the natural gas price
at Henry Hub, Louisiana, using the simple average of the NYMEX
settlement prices for the last three trading days of the applicable
month.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
Ranges
|
|
(Unaudited)
|
|
|
1Q 2018
|
|
|
Full Year
2018
|
Daily Sales
Volumes
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil and Condensate
Volumes (MBbld)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
350.0
|
-
|
|
360.0
|
|
|
387.0
|
-
|
|
401.0
|
Trinidad
|
|
0.5
|
-
|
|
0.7
|
|
|
0.4
|
-
|
|
0.6
|
Other International
|
|
0.0
|
-
|
|
5.0
|
|
|
2.0
|
-
|
|
4.0
|
Total
|
|
350.5
|
-
|
|
365.7
|
|
|
389.4
|
-
|
|
405.6
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids Volumes
(MBbld)
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
93.0
|
-
|
|
103.0
|
|
|
100.0
|
-
|
|
110.0
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Volumes
(MMcfd)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
825
|
-
|
|
865
|
|
|
900
|
-
|
|
950
|
Trinidad
|
|
280
|
-
|
|
310
|
|
|
250
|
-
|
|
290
|
Other International
|
|
25
|
-
|
|
35
|
|
|
28
|
-
|
|
38
|
Total
|
|
1,130
|
-
|
|
1,210
|
|
|
1,178
|
-
|
|
1,278
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Equivalent Volumes
(MBoed)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
580.5
|
-
|
|
607.2
|
|
|
637.0
|
-
|
|
669.3
|
Trinidad
|
|
47.2
|
-
|
|
52.4
|
|
|
42.1
|
-
|
|
48.9
|
Other International
|
|
4.2
|
-
|
|
10.8
|
|
|
6.7
|
-
|
|
10.3
|
Total
|
|
631.9
|
-
|
|
670.4
|
|
|
685.8
|
-
|
|
728.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
Ranges
|
|
(Unaudited)
|
|
1Q 2018
|
|
|
Full Year
2018
|
Operating
Costs
|
|
|
|
|
|
|
|
|
|
|
|
Unit Costs
($/Boe)
|
|
|
|
|
|
|
|
|
|
|
|
Lease and Well
|
$
|
4.70
|
-
|
$
|
5.10
|
|
$
|
4.20
|
-
|
$
|
4.80
|
Transportation Costs
|
$
|
3.00
|
-
|
$
|
3.50
|
|
$
|
2.75
|
-
|
$
|
3.25
|
Depreciation, Depletion and Amortization
|
$
|
13.00
|
-
|
$
|
13.40
|
|
$
|
13.10
|
-
|
$
|
13.50
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses
($MM)
|
|
|
|
|
|
|
|
|
|
|
|
Exploration, Dry Hole and
Impairment
|
$
|
90
|
-
|
$
|
120
|
|
$
|
375
|
-
|
$
|
425
|
General and
Administrative
|
$
|
100
|
-
|
$
|
110
|
|
$
|
415
|
-
|
$
|
445
|
Gathering and
Processing
|
$
|
95
|
-
|
$
|
105
|
|
$
|
430
|
-
|
$
|
470
|
Capitalized
Interest
|
$
|
6
|
-
|
$
|
8
|
|
$
|
27
|
-
|
$
|
32
|
Net Interest
|
$
|
60
|
-
|
$
|
62
|
|
$
|
234
|
-
|
$
|
242
|
|
|
|
|
|
|
|
|
|
|
|
|
Taxes Other Than
Income (% of Wellhead Revenue)
|
|
6.6%
|
-
|
|
7.0%
|
|
|
6.5%
|
-
|
|
6.9%
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Taxes
|
|
|
|
|
|
|
|
|
|
|
|
Effective
Rate
|
|
20%
|
-
|
|
25%
|
|
|
20%
|
-
|
|
25%
|
Current Tax (Benefit) /
Expense ($MM)
|
$
|
(90)
|
-
|
$
|
(55)
|
|
$
|
(310)
|
-
|
$
|
(270)
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures
(Excluding Acquisitions, $MM)
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and Development,
Excluding Facilities
|
|
|
|
|
|
|
$
|
4,500
|
-
|
$
|
4,800
|
Exploration and Development
Facilities
|
|
|
|
|
|
|
$
|
600
|
-
|
$
|
650
|
Gathering, Processing and
Other
|
|
|
|
|
|
|
$
|
300
|
-
|
$
|
350
|
|
|
|
|
|
|
|
|
|
|
|
|
Pricing - (Refer to
Benchmark Commodity Pricing in text)
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil and Condensate
($/Bbl)
|
|
|
|
|
|
|
|
|
|
|
|
Differentials
|
|
|
|
|
|
|
|
|
|
|
|
United States - above (below) WTI
|
$
|
0.00
|
-
|
$
|
1.50
|
|
$
|
(1.00)
|
-
|
$
|
1.00
|
Trinidad - above (below) WTI
|
$
|
(11.00)
|
-
|
$
|
(9.00)
|
|
$
|
(11.00)
|
-
|
$
|
(9.00)
|
Other International - above (below) WTI
|
$
|
0.00
|
-
|
$
|
2.00
|
|
$
|
0.00
|
-
|
$
|
2.00
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
Liquids
|
|
|
|
|
|
|
|
|
|
|
|
Realizations as % of WTI
|
|
39%
|
-
|
|
45%
|
|
|
40%
|
-
|
|
46%
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
($/Mcf)
|
|
|
|
|
|
|
|
|
|
|
|
Differentials
|
|
|
|
|
|
|
|
|
|
|
|
United States - above (below) NYMEX Henry Hub
|
$
|
(0.40)
|
-
|
$
|
0.00
|
|
$
|
(0.60)
|
-
|
$
|
0.00
|
|
|
|
|
|
|
|
|
|
|
|
|
Realizations
|
|
|
|
|
|
|
|
|
|
|
|
Trinidad
|
$
|
2.50
|
-
|
$
|
2.90
|
|
$
|
2.15
|
-
|
$
|
2.75
|
Other International
|
$
|
4.15
|
-
|
$
|
4.65
|
|
$
|
4.00
|
-
|
$
|
5.00
|
|
|
|
|
|
|
|
|
|
|
|
|
Definitions
|
|
|
|
|
|
|
|
|
|
|
|
$/Bbl
|
U.S. Dollars per
barrel
|
|
|
|
|
|
|
|
$/Boe
|
U.S. Dollars per
barrel of oil equivalent
|
|
|
|
|
|
$/Mcf
|
U.S. Dollars per
thousand cubic feet
|
|
|
|
|
|
$MM
|
U.S. Dollars in
millions
|
|
|
|
|
|
|
MBbld
|
Thousand barrels per
day
|
|
|
|
|
|
|
MBoed
|
Thousand barrels of
oil equivalent per day
|
|
|
|
|
MMcfd
|
Million cubic feet
per day
|
|
|
|
|
|
|
NYMEX
|
U.S. New York
Mercantile Exchange
|
|
|
|
|
|
WTI
|
West Texas
Intermediate
|
|
|
|
|
|
|
|
|
EOG RESOURCES,
INC.
|
Fourth Quarter
2017 Well Results by Play
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wells
Completed
|
|
|
|
Initial 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
|
|
51
|
|
45
|
|
6,000
|
|
1,410
|
|
310
|
|
2.5
|
|
2,145
|
Bone
Spring
|
|
9
|
|
9
|
|
6,700
|
|
1,085
|
|
160
|
|
1.3
|
|
1,470
|
Leonard
|
|
5
|
|
5
|
|
8,700
|
|
1,230
|
|
265
|
|
2.2
|
|
1,865
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Powder River Basin
Turner
|
|
9
|
|
7
|
|
7,700
|
|
990
|
|
375
|
|
4.7
|
|
2,150
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DJ Basin
Codell
|
|
3
|
|
2
|
|
9,100
|
|
950
|
|
105
|
|
0.4
|
|
1,120
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South Texas Eagle
Ford
|
|
74
|
|
70
|
|
7,400
|
|
1,525
|
|
195
|
|
1.1
|
|
1,915
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South Texas Austin
Chalk
|
|
4
|
|
4
|
|
5,300
|
|
2,280
|
|
430
|
|
2.5
|
|
3,130
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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.
|
View original
content:http://www.prnewswire.com/news-releases/eog-resources-reports-fourth-quarter-and-full-year-2017-results-and-announces-2018-capital-program-300605294.html
SOURCE EOG Resources, Inc.