HOUSTON, Nov. 2, 2017 /PRNewswire/ --
- Introduces 50,000 Net Acre Woodford Oil Window Play with 210
MMBoe Estimated Net Resource Potential and 260 Net Premium Well
Locations
- Adds First Bone Spring Play in Delaware Basin with 540 MMBoe Estimated Net
Resource Potential and 540 Remaining Net Premium Well
Locations
- Exceeds Revised Post-Harvey Crude Oil, NGL and Natural Gas
Production Targets
- Delivers Per-Unit Lease and Well, Transportation and DD&A
Expense Rates Below Targets
- Expects to Grow 2017 U.S. Oil Production 20 Percent Within
Discretionary Cash Flow Including Dividends
EOG Resources, Inc. (NYSE: EOG) (EOG) today reported third
quarter 2017 net income of $100.5
million, or $0.17 per share.
This compares to a third quarter 2016 net loss of $190.0 million, or $0.35 per share.
Adjusted non-GAAP net income for the third quarter 2017 was
$111.3 million, or $0.19 per share, compared to an adjusted non-GAAP
net loss of $220.8 million, or
$0.40 per share, for the same prior
year period. Adjusted non-GAAP net income (loss) is
calculated by matching commodity derivative contract realizations
to settlement months and making certain other adjustments in order
to exclude non-recurring items. (Please refer to the attached
tables for the reconciliation of non-GAAP measures to GAAP
measures.)
Increased crude oil volumes, higher crude oil, natural gas
liquids (NGLs) and natural gas prices and lower transportation
expense resulted in increases to discretionary cash flow and
EBITDAX during the third quarter 2017 compared to the third quarter
2016. In addition to the items listed above, lower impairment
and depreciation, depletion and amortization expenses resulted in
increased adjusted non-GAAP net income during the quarter.
(Please refer to the attached tables for the reconciliation of
non-GAAP measures to GAAP measures.)
Operational Highlights
In the third quarter 2017, EOG
expanded its premium inventory to approximately 8,000 net drilling
locations from 7,200. As a result, EOG's total premium net
resource potential increased 12 percent to 7.3 billion barrels of
oil equivalent. The additional net premium locations include
540 in the Delaware Basin First
Bone Spring and 260 in the Woodford Oil Window. Premium
inventory is defined by well locations that generate a minimum 30
percent direct after-tax rate of return assuming a $40 crude oil price.
EOG grew third quarter total crude oil volumes 16 percent to
327,900 barrels of oil per day (Bopd). Production
curtailments and completion delays due to Hurricane Harvey reduced
crude oil volumes approximately 15,000 Bopd during the
quarter. Natural gas and NGL production exceeded target
midpoints, contributing to 8 percent total company production
growth compared to the third quarter 2016.
During the third quarter 2017, lease and well expenses on a
per-unit basis increased 4 percent compared to the same prior-year
period, primarily because of higher per-unit operating costs from
properties acquired in the Yates transaction and increased
operating and maintenance expenses in the United Kingdom. Per-unit transportation
costs decreased 15 percent year-over-year, due to the expiration of
legacy transportation agreements and increased infrastructure to
handle higher production volumes. Per-unit depreciation,
depletion and amortization expenses decreased 13 percent compared
to the same prior-year period due to the addition of reserves from
premium wells with lower finding and development costs.
EOG now expects to complete approximately 505 net wells in 2017,
an increase from its original outlook of 480 net wells. The
company achieved lower completed well costs across its operations
in 2017, as continued efficiencies and legacy service contract
expirations offset service price increases. EOG is targeting
20 percent U.S. crude oil growth and expects to fund capital
expenditures and the dividend using discretionary cash flow.
"Since the start of the year, EOG has added 2,000 net premium
locations to its inventory. This is four times the number of
wells we expect to complete for all of 2017," said William R.
"Bill" Thomas, Chairman and Chief Executive Officer. "EOG is
an organic, exploration-driven machine. We have amassed an
enormous, high-quality portfolio of assets by capturing sweet-spot
acreage in the best oil plays in the U.S. Combined with our
consistent operational proficiency and innovative technology, this
gives us great confidence in the long-term sustainability of our
unique premium growth and high-return model."
Woodford Oil Window
EOG added to its growing roster of
premium plays with the introduction of a 50,000 net acre position
in the Woodford oil window of the
Eastern Anadarko Basin. Located primarily in McClain County, Oklahoma, EOG is targeting the
black-oil window of the Woodford
formation. The contiguous acreage position was amassed
through an organic leasing program conducted over the past four
years at an average cost of $750 per
acre. EOG has completed three horizontal exploration wells in
the play since June 2016. The most recent well, the Curry 21X
#1VH, was brought to sales in the third quarter with a treated
lateral length of 10,500 feet and 30-day initial production rate of
1,730 barrels of oil equivalent per day (Boed), or 1,460 Bopd, 165
barrels per day (Bpd) of NGLs and 0.6 million cubic feet per day
(MMcfd) of natural gas. Completed well costs are targeted at
$7.8 million for a 9,500 foot
lateral. Benefiting from a shallow initial decline rate, EOG
estimates reserves per well are 800 thousand barrels of oil
equivalent (MBoe), net after royalty, with a 70 percent oil
mix. The company has identified 260 net drilling locations
with estimated net resource potential of 210 million barrels of oil
equivalent (MMBoe). EOG estimates all 260 of these locations
are premium, and plans to ramp activity in the play in 2018.
Delaware Basin
EOG
added to its inventory of prolific plays in the Delaware Basin with the introduction of the
First Bone Spring. Approximately 100,000 net acres in EOG's
Northern Delaware Basin footprint
are prospective for this high rate-of-return oil play. The
company identified an initial 555 net locations, with estimated net
resource potential of 540 MMBoe. EOG completed 15 net First
Bone Spring wells in the past three years, with strong results and
premium returns across a large portion of its acreage
position. All 540 net remaining drilling locations have
premium rate of return potential. Reserves per well are
estimated to be 975 MBoe, net after royalty, with a 55 percent oil
mix. Targeted well cost is $7.3
million for a 7,000 foot lateral well.
EOG continues to deepen its technical knowledge of the
Delaware Basin. Drilling
during the third quarter was aimed at further understanding
development criteria for the large stacked-pay resource in the
basin. EOG conducted a number of spacing tests to optimize
development, and continued to test additional zones for future
premium potential. EOG now expects to complete an additional
15 net wells in the Delaware Basin
during 2017 for a total of 155 net wells, including 10 net wells in
the First Bone Spring.
EOG completed 22 gross (20 net) wells in the Delaware Basin Wolfcamp in the third quarter
with an average treated lateral length of 6,500 feet per well and
average 30-day initial production rates per well of 2,470 Boed, or
1,620 Bopd, 380 Bpd of NGLs and 2.8 MMcfd of natural gas. In
Lea County, NM, EOG completed a
three-well pattern, the Antietam 9 Fed Com 701-703H, with an
average treated lateral length of 7,000 feet per well and average
30-day initial production rates per well of 4,145 Boed, or 2,725
Bopd, 640 Bpd of NGLs and 4.7 MMcfd of natural gas.
In the Delaware Basin Bone
Spring plays, EOG completed nine gross (six net) wells in the third
quarter with an average treated lateral length of 6,800 feet per
well and average 30-day initial production rates per well of 1,125
Boed, or 840 Bopd, 125 Bpd of NGLs and 0.9 MMcfd of natural
gas. In Lea County, NM, EOG
completed the Righteous 6 State Com 601Y, with a treated lateral
length of 7,100 feet and a 30-day initial production rate of 2,160
Boed, or 1,740 Bopd, 190 Bpd of NGLs and 1.4 MMcfd of natural
gas.
In the Delaware Basin Leonard,
EOG completed nine gross (nine net) wells in the third quarter with
an average treated lateral length of 4,800 feet per well and
average 30-day initial production rates per well of 1,725 Boed, or
800 Bopd, 415 Bpd of NGLs and 3.0 MMcfd of natural gas.
Bakken and Rockies
EOG completed 20 gross (19 net)
wells in the Powder River Basin Turner during the third quarter,
with an average treated lateral length of 7,600 feet per well and
average 30-day initial production rates per well of 1,630 Boed, or
1,040 Bopd, 185 Bpd of NGLs and 2.4 MMcfd of natural gas.
Encouraging tests of new targets and ongoing delineation of its
400,000 net acre position have prompted EOG to increase its
activity, with five additional wells planned during 2017 for a
total of 35 net wells. The combination of low completed well
costs, robust well productivity and moderate initial decline rates
make the Powder River Basin competitive with the best performing
assets at EOG.
In the DJ Basin, EOG completed seven gross (two net) wells
targeting the Codell formation in the third quarter with an average
treated lateral length of 9,400 feet per well and average 30-day
initial production rates per well of 790 Boed, or 665 Bopd, 75 Bpd
of NGLs and 0.3 MMcfd of natural gas.
EOG completed its planned 35 net well program in the North
Dakota Bakken in the first half of 2017, and limited drilling
activity is scheduled for the remainder of 2017.
South Texas Eagle Ford
EOG's South Texas Eagle Ford
remained resilient during the third quarter, as robust
infrastructure and comprehensive technology and communication
assets enabled EOG to manage operations in a safe and efficient
manner during Hurricane Harvey. Ongoing efficiency improvements
have enabled EOG to add five net wells to its planned 2017
completions, for a total of 200 net wells.
In the third quarter, EOG completed 44 gross (39 net) wells in
the Eagle Ford with an average treated lateral length of 6,500 feet
per well and average 30-day initial production rates per well of
1,685 Boed, or 1,340 Bopd, 175 Bpd of NGLs and 1.0 MMcfd of natural
gas. In Gonzales County, EOG completed a four-well pattern,
the Angus Unit 6H-9H, with an average treated lateral length of
5,700 feet per well and average 30-day initial production rates per
well of 3,945 Boed, or 2,995 Bopd, 480 Bpd of NGLs and 2.8 MMcfd of
natural gas.
South Texas Austin Chalk
In the third quarter, EOG
continued to delineate the South Texas Austin Chalk. EOG
completed eight gross (eight net) wells in Karnes County with an average treated lateral
length of 6,000 feet per well and average 30-day initial production
rates per well of 4,440 Boed, or 3,195 Bopd, 630 Bpd of NGLs and
3.7 MMcfd of natural gas. Notably, EOG completed the Elbrus
Unit 103H with a lateral length of 3,700 feet and 30-day initial
production rate of 7,760 Boed, or 5,425 Bopd, 1,185 Bpd of NGLs and
6.9 MMcfd of natural gas.
Hedging Activity
During the third quarter ended
September 30, 2017, EOG did not enter
into any additional crude oil or natural gas derivative
contracts.
A comprehensive summary of EOG's crude oil and natural gas
derivative contracts is provided in the attached
tables.
Capital Structure and Asset Sales
At September 30, 2017, EOG's total debt outstanding
was $6.4 billion for a debt-to-total
capitalization ratio of 31 percent. Considering cash on the
balance sheet at the end of the third quarter, EOG's net debt was
$5.5 billion for a net debt-to-total
capitalization ratio of 28 percent. For a reconciliation of
non-GAAP measures to GAAP measures, please refer to the attached
tables.
Proceeds from asset sales in the first nine months of 2017
totaled $192 million.
Conference Call November 3,
2017
EOG's third quarter 2017 results conference call
will be available via live audio webcast at 9 a.m. Central time (10
a.m. Eastern time) on Friday,
November 3, 2017. 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
and costs, 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. 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 13 through 22 of EOG's Annual Report on Form 10-K for the
fiscal year ended December 31, 2016,
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, 2016, 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
|
|
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
|
|
Nine Months
Ended
|
|
September
30,
|
|
September
30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Operating
Revenues and Other
|
$
|
2,644.8
|
|
$
|
2,118.5
|
|
$
|
7,867.9
|
|
$
|
5,248.6
|
Net Income
(Loss)
|
$
|
100.5
|
|
$
|
(190.0)
|
|
$
|
152.1
|
|
$
|
(954.3)
|
Net Income (Loss) Per
Share
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
$
|
0.17
|
|
$
|
(0.35)
|
|
$
|
0.26
|
|
$
|
(1.74)
|
Diluted
|
$
|
0.17
|
|
$
|
(0.35)
|
|
$
|
0.26
|
|
$
|
(1.74)
|
Average Number of
Common Shares
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
574.8
|
|
|
547.8
|
|
|
574.4
|
|
|
547.3
|
Diluted
|
|
578.7
|
|
|
547.8
|
|
|
578.5
|
|
|
547.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Summary Income
Statements
|
(Unaudited; in
thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Nine Months
Ended
|
|
September
30,
|
|
September
30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Net Operating
Revenues and Other
|
|
|
|
|
|
|
|
Crude Oil
and Condensate
|
$
|
1,451,410
|
|
$
|
1,137,717
|
|
$
|
4,326,925
|
|
$
|
2,951,118
|
Natural
Gas Liquids
|
|
180,038
|
|
|
112,439
|
|
|
480,389
|
|
|
299,401
|
Natural
Gas
|
|
220,402
|
|
|
205,293
|
|
|
675,012
|
|
|
526,779
|
Gains
(Losses) on Mark-to-Market Commodity Derivative
Contracts
|
|
(6,606)
|
|
|
5,117
|
|
|
64,860
|
|
|
(33,821)
|
Gathering,
Processing and Marketing
|
|
784,368
|
|
|
532,456
|
|
|
2,289,702
|
|
|
1,351,665
|
Gains
(Losses) on Asset Dispositions, Net
|
|
(8,202)
|
|
|
108,204
|
|
|
(33,876)
|
|
|
101,801
|
Other,
Net
|
|
23,434
|
|
|
17,278
|
|
|
64,869
|
|
|
51,650
|
Total
|
|
2,644,844
|
|
|
2,118,504
|
|
|
7,867,881
|
|
|
5,248,593
|
Operating
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
Lease and
Well
|
|
251,943
|
|
|
226,348
|
|
|
762,906
|
|
|
685,606
|
Transportation Costs
|
|
183,565
|
|
|
200,862
|
|
|
548,635
|
|
|
570,787
|
Gathering
and Processing Costs
|
|
32,590
|
|
|
32,635
|
|
|
105,480
|
|
|
90,385
|
Exploration Costs
|
|
30,796
|
|
|
25,455
|
|
|
122,401
|
|
|
85,843
|
Dry Hole
Costs
|
|
50
|
|
|
10,390
|
|
|
77
|
|
|
10,464
|
Impairments
|
|
53,677
|
|
|
177,990
|
|
|
325,798
|
|
|
322,321
|
Marketing
Costs
|
|
793,536
|
|
|
552,487
|
|
|
2,320,671
|
|
|
1,373,387
|
Depreciation, Depletion and Amortization
|
|
846,222
|
|
|
899,511
|
|
|
2,527,642
|
|
|
2,690,893
|
General
and Administrative
|
|
111,717
|
|
|
94,397
|
|
|
317,462
|
|
|
292,633
|
Taxes
Other Than Income
|
|
125,912
|
|
|
91,909
|
|
|
386,319
|
|
|
246,068
|
Total
|
|
2,430,008
|
|
|
2,311,984
|
|
|
7,417,391
|
|
|
6,368,387
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
(Loss)
|
|
214,836
|
|
|
(193,480)
|
|
|
450,490
|
|
|
(1,119,794)
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income
(Expense), Net
|
|
226
|
|
|
(7,912)
|
|
|
8,349
|
|
|
(33,345)
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) Before
Interest Expense and Income Taxes
|
|
215,062
|
|
|
(201,392)
|
|
|
458,839
|
|
|
(1,153,139)
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense,
Net
|
|
69,082
|
|
|
70,858
|
|
|
211,010
|
|
|
210,356
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) Before
Income Taxes
|
|
145,980
|
|
|
(272,250)
|
|
|
247,829
|
|
|
(1,363,495)
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax Provision
(Benefit)
|
|
45,439
|
|
|
(82,250)
|
|
|
95,718
|
|
|
(409,161)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
(Loss)
|
$
|
100,541
|
|
$
|
(190,000)
|
|
$
|
152,111
|
|
$
|
(954,334)
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends Declared
per Common Share
|
$
|
0.1675
|
|
$
|
0.1675
|
|
$
|
0.5025
|
|
$
|
0.5025
|
|
|
|
EOG RESOURCES,
INC.
|
Operating
Highlights
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Nine Months
Ended
|
|
September
30,
|
|
September
30,
|
|
|
2017
|
|
|
2016
|
|
|
2017
|
|
|
2016
|
Wellhead Volumes
and Prices
|
|
|
|
Crude Oil and
Condensate Volumes (MBbld) (A)
|
|
|
|
United
States
|
|
327.1
|
|
|
275.7
|
|
|
324.3
|
|
|
269.0
|
Trinidad
|
|
0.8
|
|
|
0.7
|
|
|
0.8
|
|
|
0.8
|
Other International
(B)
|
|
-
|
|
|
6.2
|
|
|
1.0
|
|
|
3.0
|
Total
|
|
327.9
|
|
|
282.6
|
|
|
326.1
|
|
|
272.8
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Crude Oil and
Condensate Prices ($/Bbl) (C)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$
|
48.06
|
|
$
|
43.66
|
|
$
|
48.61
|
|
$
|
39.53
|
Trinidad
|
|
39.42
|
|
|
34.81
|
|
|
40.24
|
|
|
31.36
|
Other International
(B)
|
|
-
|
|
|
43.53
|
|
|
51.55
|
|
|
35.30
|
Composite
|
|
48.11
|
|
|
43.63
|
|
|
48.60
|
|
|
39.46
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids
Volumes (MBbld) (A)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
|
87.4
|
|
|
81.9
|
|
|
84.3
|
|
|
81.9
|
Other International
(B)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
Total
|
|
87.4
|
|
|
81.9
|
|
|
84.3
|
|
|
81.9
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Natural Gas
Liquids Prices ($/Bbl) (C)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$
|
22.38
|
|
$
|
14.92
|
|
$
|
20.87
|
|
$
|
13.34
|
Other International
(B)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
Composite
|
|
22.38
|
|
|
14.92
|
|
|
20.87
|
|
|
13.34
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Volumes
(MMcfd) (A)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
|
748
|
|
|
791
|
|
|
744
|
|
|
813
|
Trinidad
|
|
323
|
|
|
329
|
|
|
317
|
|
|
346
|
Other International
(B)
|
|
25
|
|
|
24
|
|
|
22
|
|
|
25
|
Total
|
|
1,096
|
|
|
1,144
|
|
|
1,083
|
|
|
1,184
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Natural Gas
Prices ($/Mcf) (C)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$
|
2.20
|
|
$
|
1.94
|
|
$
|
2.22
|
|
$
|
1.46
|
Trinidad
|
|
2.04
|
|
|
1.86
|
|
|
2.33
|
|
|
1.88
|
Other International
(B)
|
|
3.74
|
|
|
3.74
|
|
|
3.72
|
|
|
3.57
|
Composite
|
|
2.19
|
|
|
1.95
|
|
|
2.28
|
|
|
1.62
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Equivalent
Volumes (MBoed) (D)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
|
539.2
|
|
|
489.4
|
|
|
532.6
|
|
|
486.4
|
Trinidad
|
|
54.6
|
|
|
55.6
|
|
|
53.6
|
|
|
58.5
|
Other International
(B)
|
|
4.3
|
|
|
10.2
|
|
|
4.8
|
|
|
7.2
|
Total
|
|
598.1
|
|
|
555.2
|
|
|
591.0
|
|
|
552.1
|
|
|
|
|
|
|
|
|
|
|
|
|
Total MMBoe
(D)
|
|
55.0
|
|
|
51.1
|
|
|
161.3
|
|
|
151.3
|
(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)
|
|
|
|
|
|
|
|
September
30,
|
|
December
31,
|
|
2017
|
|
2016
|
ASSETS
|
Current
Assets
|
|
|
|
|
|
Cash and Cash
Equivalents
|
$
|
846,138
|
|
$
|
1,599,895
|
Accounts Receivable,
Net
|
|
1,243,535
|
|
|
1,216,320
|
Inventories
|
|
344,016
|
|
|
350,017
|
Assets from Price Risk
Management Activities
|
|
3,297
|
|
|
-
|
Income Taxes
Receivable
|
|
126,881
|
|
|
12,305
|
Other
|
|
200,096
|
|
|
206,679
|
Total
|
|
2,763,963
|
|
|
3,385,216
|
|
|
|
|
|
|
Property, Plant
and Equipment
|
|
|
|
|
|
Oil and Gas Properties
(Successful Efforts Method)
|
|
51,716,999
|
|
|
49,592,091
|
Other Property, Plant and
Equipment
|
|
3,934,137
|
|
|
4,008,564
|
Total Property, Plant and Equipment
|
|
55,651,136
|
|
|
53,600,655
|
Less: Accumulated
Depreciation, Depletion and Amortization
|
|
(29,926,547)
|
|
|
(27,893,577)
|
Total Property, Plant and Equipment, Net
|
|
25,724,589
|
|
|
25,707,078
|
Deferred Income
Taxes
|
|
17,406
|
|
|
16,140
|
Other
Assets
|
|
299,347
|
|
|
190,767
|
Total
Assets
|
$
|
28,805,305
|
|
$
|
29,299,201
|
|
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS' EQUITY
|
Current
Liabilities
|
|
|
|
|
|
Accounts Payable
|
$
|
1,635,711
|
|
$
|
1,511,826
|
Accrued Taxes
Payable
|
|
180,277
|
|
|
118,411
|
Dividends Payable
|
|
96,349
|
|
|
96,120
|
Liabilities from Price Risk
Management Activities
|
|
2,827
|
|
|
61,817
|
Current Portion of Long-Term
Debt
|
|
6,579
|
|
|
6,579
|
Other
|
|
258,281
|
|
|
232,538
|
Total
|
|
2,180,024
|
|
|
2,027,291
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term
Debt
|
|
6,380,427
|
|
|
6,979,779
|
Other
Liabilities
|
|
1,215,113
|
|
|
1,282,142
|
Deferred Income
Taxes
|
|
5,107,477
|
|
|
5,028,408
|
Commitments and
Contingencies
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders'
Equity
|
|
|
|
|
|
Common Stock, $0.01 Par,
1,280,000,000 Shares Authorized at September 30, 2017,
640,000,000 Shares Authorized at December 31, 2016, 578,570,621
Shares Issued at September 30, 2017 and 576,950,272 Shares Issued
at December 31, 2016
|
|
205,786
|
|
|
205,770
|
Additional Paid in
Capital
|
|
5,513,631
|
|
|
5,420,385
|
Accumulated Other
Comprehensive Loss
|
|
(17,160)
|
|
|
(19,010)
|
Retained Earnings
|
|
8,259,971
|
|
|
8,398,118
|
Common Stock Held in
Treasury, 429,424 Shares at September 30, 2017 and 250,155 Shares
at December 31, 2016
|
|
(39,964)
|
|
|
(23,682)
|
Total Stockholders' Equity
|
|
13,922,264
|
|
|
13,981,581
|
Total Liabilities
and Stockholders' Equity
|
$
|
28,805,305
|
|
$
|
29,299,201
|
|
|
|
EOG RESOURCES,
INC.
|
Summary Statements
of Cash Flows
|
(Unaudited; in
thousands)
|
|
|
|
|
|
|
|
Nine Months
Ended
|
|
September
30,
|
|
2017
|
|
2016
|
Cash Flows from
Operating Activities
|
|
|
|
|
|
Reconciliation of Net
Income (Loss) to Net Cash Provided by Operating
Activities:
|
|
|
|
|
|
Net Income (Loss)
|
$
|
152,111
|
|
$
|
(954,334)
|
Items Not Requiring
(Providing) Cash
|
|
|
|
|
|
Depreciation, Depletion and Amortization
|
|
2,527,642
|
|
|
2,690,893
|
Impairments
|
|
325,798
|
|
|
322,321
|
Stock-Based Compensation Expenses
|
|
101,537
|
|
|
97,072
|
Deferred Income Taxes
|
|
114,850
|
|
|
(492,489)
|
(Gains) Losses on Asset Dispositions, Net
|
|
33,876
|
|
|
(101,801)
|
Other, Net
|
|
(4,514)
|
|
|
42,149
|
Dry Hole Costs
|
|
77
|
|
|
10,464
|
Mark-to-Market Commodity
Derivative Contracts
|
|
|
|
|
|
Total (Gains) Losses
|
|
(64,860)
|
|
|
33,821
|
Net Cash Received from (Payments for) Settlements of Commodity
Derivative Contracts
|
|
4,730
|
|
|
(22,219)
|
Excess Tax Benefits from
Stock-Based Compensation
|
|
-
|
|
|
(22,071)
|
Other, Net
|
|
270
|
|
|
7,513
|
Changes in Components of
Working Capital and Other Assets and Liabilities
|
|
|
|
|
|
Accounts Receivable
|
|
(25,445)
|
|
|
(11,860)
|
Inventories
|
|
(17,674)
|
|
|
137,563
|
Accounts Payable
|
|
112,894
|
|
|
(201,213)
|
Accrued Taxes Payable
|
|
(49,967)
|
|
|
113,996
|
Other Assets
|
|
(83,940)
|
|
|
(12,526)
|
Other Liabilities
|
|
(69,224)
|
|
|
36,799
|
Changes in Components of
Working Capital Associated with Investing and Financing
Activities
|
|
(120,373)
|
|
|
(119,760)
|
Net Cash Provided
by Operating Activities
|
|
2,937,788
|
|
|
1,554,318
|
|
|
|
|
|
|
Investing Cash
Flows
|
|
|
|
|
|
Additions to Oil and Gas
Properties
|
|
(2,927,988)
|
|
|
(1,781,547)
|
Additions to Other Property,
Plant and Equipment
|
|
(139,558)
|
|
|
(60,343)
|
Proceeds from Sales of
Assets
|
|
191,593
|
|
|
457,665
|
Changes in Components of
Working Capital Associated with Investing Activities
|
|
120,469
|
|
|
120,614
|
Net Cash Used in
Investing Activities
|
|
(2,755,484)
|
|
|
(1,263,611)
|
|
|
|
|
|
|
Financing Cash
Flows
|
|
|
|
|
|
Net Commercial Paper
Repayments
|
|
-
|
|
|
(259,718)
|
Long-Term Debt
Borrowings
|
|
-
|
|
|
991,097
|
Long-Term Debt
Repayments
|
|
(600,000)
|
|
|
(400,000)
|
Dividends Paid
|
|
(289,261)
|
|
|
(276,726)
|
Excess Tax Benefits from
Stock-Based Compensation
|
|
-
|
|
|
22,071
|
Treasury Stock
Purchased
|
|
(50,374)
|
|
|
(55,641)
|
Proceeds from Stock Options
Exercised and Employee Stock Purchase Plan
|
|
11,174
|
|
|
14,283
|
Debt Issuance
Costs
|
|
-
|
|
|
(1,602)
|
Repayment of Capital Lease
Obligation
|
|
(4,897)
|
|
|
(4,746)
|
Other, Net
|
|
(96)
|
|
|
(854)
|
Net Cash (Used in)
Provided by Financing Activities
|
|
(933,454)
|
|
|
28,164
|
|
|
|
|
|
|
Effect of Exchange
Rate Changes on Cash
|
|
(2,607)
|
|
|
11,350
|
|
|
|
|
|
|
Increase
(Decrease) in Cash and Cash Equivalents
|
|
(753,757)
|
|
|
330,221
|
Cash and Cash
Equivalents at Beginning of Period
|
|
1,599,895
|
|
|
718,506
|
Cash and Cash
Equivalents at End of Period
|
$
|
846,138
|
|
$
|
1,048,727
|
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 nine-month periods ended September 30,
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 related to the Yates Transaction in
2016, to add back an early lease termination payment as the result
of a legal settlement in 2017 and to add back the transaction costs
for the formation of a joint venture 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
|
|
September 30,
2017
|
|
September 30,
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)
|
$145,980
|
|
$
(45,439)
|
|
$100,541
|
|
$
0.17
|
|
$
(272,250)
|
|
$
82,250
|
|
$(190,000)
|
|
$
(0.35)
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Gains) Losses on
Mark-to-Market Commodity Derivative Contracts
|
6,606
|
|
(2,368)
|
|
4,238
|
|
0.01
|
|
(5,117)
|
|
1,824
|
|
(3,293)
|
|
(0.01)
|
Net Cash Received
from (Payments for) Settlements of Commodity Derivative
Contracts
|
2,139
|
|
(767)
|
|
1,372
|
|
-
|
|
(25,071)
|
|
8,938
|
|
(16,133)
|
|
(0.03)
|
Add: Net
(Gains) Losses on Asset Dispositions
|
8,202
|
|
(3,068)
|
|
5,134
|
|
0.01
|
|
(108,204)
|
|
28,802
|
|
(79,402)
|
|
(0.13)
|
Add:
Impairments
|
-
|
|
-
|
|
-
|
|
-
|
|
102,778
|
|
(36,640)
|
|
66,138
|
|
0.12
|
Add:
Acquisition Costs
|
-
|
|
-
|
|
-
|
|
-
|
|
2,927
|
|
(1,043)
|
|
1,884
|
|
-
|
Adjustments to Net
Income (Loss)
|
16,947
|
|
(6,203)
|
|
10,744
|
|
0.02
|
|
(32,687)
|
|
1,881
|
|
(30,806)
|
|
(0.05)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Net
Income (Loss) (Non-GAAP)
|
$162,927
|
|
$
(51,642)
|
|
$111,285
|
|
$
0.19
|
|
$
(304,937)
|
|
$
84,131
|
|
$(220,806)
|
|
$
(0.40)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Number of
Common Shares (GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
574,783
|
|
|
|
|
|
|
|
547,838
|
Diluted
|
|
|
|
|
|
|
578,736
|
|
|
|
|
|
|
|
547,838
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Number of
Common Shares (Non-GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
574,783
|
|
|
|
|
|
|
|
547,838
|
Diluted
|
|
|
|
|
|
|
578,736
|
|
|
|
|
|
|
|
547,838
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months
Ended
|
|
Nine Months
Ended
|
|
September 30,
2017
|
|
September 30,
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)
|
$247,829
|
|
$
(95,718)
|
|
$152,111
|
|
$
0.26
|
|
$(1,363,495)
|
|
$409,161
|
|
$(954,334)
|
|
$
(1.74)
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Gains) Losses on
Mark-to-Market Commodity Derivative Contracts
|
(64,860)
|
|
23,249
|
|
(41,611)
|
|
(0.07)
|
|
33,821
|
|
(12,057)
|
|
21,764
|
|
0.04
|
Net Cash Received
from (Payments for) Settlements of Commodity Derivative
Contracts
|
4,730
|
|
(1,695)
|
|
3,035
|
|
0.01
|
|
(22,219)
|
|
7,921
|
|
(14,298)
|
|
(0.03)
|
Add: Net
(Gains) Losses on Asset Dispositions
|
33,876
|
|
(11,955)
|
|
21,921
|
|
0.04
|
|
(101,801)
|
|
24,635
|
|
(77,166)
|
|
(0.14)
|
Add:
Impairments
|
161,148
|
|
(57,764)
|
|
103,384
|
|
0.18
|
|
102,778
|
|
(36,640)
|
|
66,138
|
|
0.12
|
Add: Trinidad
Tax Settlement
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
43,000
|
|
43,000
|
|
0.08
|
Add: Voluntary
Retirement Expense
|
-
|
|
-
|
|
-
|
|
-
|
|
42,054
|
|
(14,992)
|
|
27,062
|
|
0.05
|
Add:
Acquisition Costs
|
-
|
|
-
|
|
-
|
|
-
|
|
2,927
|
|
(1,043)
|
|
1,884
|
|
-
|
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 (Loss)
|
148,152
|
|
(52,917)
|
|
95,235
|
|
0.17
|
|
57,560
|
|
10,824
|
|
68,384
|
|
0.12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Net
Income (Loss) (Non-GAAP)
|
$395,981
|
|
$(148,635)
|
|
$247,346
|
|
$
0.43
|
|
$(1,305,935)
|
|
$419,985
|
|
$(885,950)
|
|
$
(1.62)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Number of
Common Shares (GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
574,370
|
|
|
|
|
|
|
|
547,295
|
Diluted
|
|
|
|
|
|
|
578,453
|
|
|
|
|
|
|
|
547,295
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Number of
Common Shares (Non-GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
574,370
|
|
|
|
|
|
|
|
547,295
|
Diluted
|
|
|
|
|
|
|
578,453
|
|
|
|
|
|
|
|
547,295
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Discretionary Cash Flow (Non-GAAP)
|
To Net Cash
Provided By Operating Activities (GAAP)
|
(Unaudited; in
thousands)
|
|
The following chart
reconciles the three-month and nine-month periods ended September
30, 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, 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 management uses this information for comparative purposes
within the industry.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Nine Months
Ended
|
|
September
30,
|
|
September
30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by
Operating Activities (GAAP)
|
$
|
961,363
|
|
$
|
759,581
|
|
$
|
2,937,788
|
|
$
|
1,554,318
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
Exploration Costs
(excluding Stock-Based Compensation Expenses)
|
|
26,132
|
|
|
21,384
|
|
|
106,268
|
|
|
70,268
|
Excess Tax Benefits
from Stock-Based Compensation
|
|
-
|
|
|
10,260
|
|
|
-
|
|
|
22,071
|
Changes in Components
of Working Capital and Other Assets and Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
Receivable
|
|
129,231
|
|
|
(10,712)
|
|
|
25,445
|
|
|
11,860
|
Inventories
|
|
11,545
|
|
|
(41,750)
|
|
|
17,674
|
|
|
(137,563)
|
Accounts
Payable
|
|
(36,190)
|
|
|
(2,145)
|
|
|
(112,894)
|
|
|
201,213
|
Accrued Taxes
Payable
|
|
10,843
|
|
|
(20,676)
|
|
|
49,967
|
|
|
(113,996)
|
Other
Assets
|
|
22,851
|
|
|
(21,063)
|
|
|
83,940
|
|
|
12,526
|
Other
Liabilities
|
|
2,355
|
|
|
(35,234)
|
|
|
69,224
|
|
|
(36,799)
|
Changes in Components
of Working Capital Associated with Investing and Financing Activities
|
|
41,235
|
|
|
65,307
|
|
|
120,373
|
|
|
119,760
|
|
Discretionary Cash
Flow (Non-GAAP)
|
$
|
1,169,365
|
|
$
|
724,952
|
|
$
|
3,297,785
|
|
$
|
1,703,658
|
|
|
|
|
|
|
|
|
|
|
|
|
Discretionary Cash
Flow (Non-GAAP) - Percentage Increase
|
|
61%
|
|
|
|
|
|
94%
|
|
|
|
|
|
|
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 nine-month periods ended September 30,
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
|
|
Nine Months
Ended
|
|
September
30,
|
|
September
30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
(GAAP)
|
$
|
100,541
|
|
$
|
(190,000)
|
|
$
|
152,111
|
|
$
|
(954,334)
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense,
Net
|
|
69,082
|
|
|
70,858
|
|
|
211,010
|
|
|
210,356
|
Income Tax Provision
(Benefit)
|
|
45,439
|
|
|
(82,250)
|
|
|
95,718
|
|
|
(409,161)
|
Depreciation, Depletion and
Amortization
|
|
846,222
|
|
|
899,511
|
|
|
2,527,642
|
|
|
2,690,893
|
Exploration Costs
|
|
30,796
|
|
|
25,455
|
|
|
122,401
|
|
|
85,843
|
Dry Hole Costs
|
|
50
|
|
|
10,390
|
|
|
77
|
|
|
10,464
|
Impairments
|
|
53,677
|
|
|
177,990
|
|
|
325,798
|
|
|
322,321
|
EBITDAX (Non-GAAP)
|
|
1,145,807
|
|
|
911,954
|
|
|
3,434,757
|
|
|
1,956,382
|
Total (Gains) Losses on MTM
Commodity Derivative Contracts
|
|
6,606
|
|
|
(5,117)
|
|
|
(64,860)
|
|
|
33,821
|
Net Cash Received from
(Payments for) Settlements of Commodity Derivative
Contracts
|
|
2,139
|
|
|
(25,071)
|
|
|
4,730
|
|
|
(22,219)
|
(Gains) Losses on Asset
Dispositions, Net
|
|
8,202
|
|
|
(108,204)
|
|
|
33,876
|
|
|
(101,801)
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX
(Non-GAAP)
|
$
|
1,162,754
|
|
$
|
773,562
|
|
$
|
3,408,503
|
|
$
|
1,866,183
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX
(Non-GAAP) - Percentage Increase
|
|
50%
|
|
|
|
|
|
83%
|
|
|
|
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
|
|
September
30,
|
|
December
31,
|
|
2017
|
|
2016
|
|
|
|
|
|
|
Total Stockholders'
Equity - (a)
|
$
|
13,922
|
|
$
|
13,982
|
|
|
|
|
|
|
Current and Long-Term
Debt (GAAP) - (b)
|
|
6,387
|
|
|
6,986
|
Less:
Cash
|
|
(846)
|
|
|
(1,600)
|
Net Debt (Non-GAAP) -
(c)
|
|
5,541
|
|
|
5,386
|
|
|
|
|
|
|
Total Capitalization
(GAAP) - (a) + (b)
|
$
|
20,309
|
|
$
|
20,968
|
|
|
|
|
|
|
Total Capitalization
(Non-GAAP) - (a) + (c)
|
$
|
19,463
|
|
$
|
19,368
|
|
|
|
|
|
|
Debt-to-Total
Capitalization (GAAP) - (b) / [(a) + (b)]
|
|
31%
|
|
|
33%
|
|
|
|
|
|
|
Net Debt-to-Total
Capitalization (Non-GAAP) - (c) / [(a) + (c)]
|
|
28%
|
|
|
28%
|
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 entered into crude oil basis swap contracts in
order to fix the differential between pricing in Midland, Texas,
and Cushing, Oklahoma. Presented below is a comprehensive
summary of EOG's crude oil basis swap contracts through November 2,
2017. The weighted average price differential expressed in
$/Bbl represents the amount of reduction to Cushing, Oklahoma,
prices for the notional volumes expressed in Bbld covered by the
basis swap contracts.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Basis
Swap Contracts
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
Average
Price
|
|
|
|
|
|
|
|
|
|
Volume
|
|
Differential
|
|
|
|
|
|
|
|
|
|
(Bbld)
|
|
($/Bbl)
|
2018
|
|
|
|
|
|
|
|
|
|
|
January 1, 2018
through December 31, 2018
|
|
|
|
|
|
15,000
|
|
$
1.063
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
|
|
|
|
|
|
|
|
|
January 1, 2019
through December 31, 2019
|
|
|
|
|
|
20,000
|
|
$
1.075
|
|
|
|
|
|
|
|
|
|
|
|
|
On March 14, 2017,
EOG executed the optional early termination provision granting EOG
the right to terminate certain 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 below table. Presented
below is a comprehensive summary of EOG's crude oil price swap
contracts through November 2, 2017, 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
|
|
|
|
|
|
|
|
|
|
|
|
|
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 offsets the
remaining 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 November 2, 2017, 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 November 2, 2017, 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 November 2, 2017, 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
2013
|
Return on Capital
Employed (ROCE) (Non-GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Interest Expense
(GAAP)
|
$
|
282
|
|
$
|
237
|
|
$
|
201
|
|
|
|
Tax Benefit Imputed
(based on 35%)
|
|
(99)
|
|
|
(83)
|
|
|
(70)
|
|
|
|
After-Tax Net
Interest Expense (Non-GAAP) - (a)
|
$
|
183
|
|
$
|
154
|
|
$
|
131
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
(GAAP) -
(b)
|
$
|
(1,097)
|
|
$
|
(4,525)
|
|
$
|
2,915
|
|
|
|
Adjustments to Net
Income (Loss), Net of Tax (See Accompanying Schedules)
|
|
204
|
(a)
|
|
4,559
|
(b)
|
|
(199)
|
(c)
|
|
|
Adjusted Net Income
(Loss) (Non-GAAP) - (c)
|
$
|
(893)
|
|
$
|
34
|
|
$
|
2,716
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Stockholders'
Equity - (d)
|
$
|
13,982
|
|
$
|
12,943
|
|
$
|
17,713
|
|
$
|
15,418
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Total
Stockholders' Equity * - (e)
|
$
|
13,463
|
|
$
|
15,328
|
|
$
|
16,566
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current and Long-Term
Debt (GAAP) - (f)
|
$
|
6,986
|
|
$
|
6,655
|
|
$
|
5,906
|
|
$
|
5,909
|
Less:
Cash
|
|
(1,600)
|
|
|
(719)
|
|
|
(2,087)
|
|
|
(1,318)
|
Net Debt (Non-GAAP) -
(g)
|
$
|
5,386
|
|
$
|
5,936
|
|
$
|
3,819
|
|
$
|
4,591
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
(GAAP) - (d) + (f)
|
$
|
20,968
|
|
$
|
19,598
|
|
$
|
23,619
|
|
$
|
21,327
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
(Non-GAAP) - (d) + (g)
|
$
|
19,368
|
|
$
|
18,879
|
|
$
|
21,532
|
|
$
|
20,009
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Total
Capitalization (Non-GAAP) * - (h)
|
$
|
19,124
|
|
$
|
20,206
|
|
$
|
20,771
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROCE (GAAP Net
Income) - [(a) + (b)] /
(h)
|
|
-4.8%
|
|
|
-21.6%
|
|
|
14.7%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROCE (Non-GAAP
Adjusted Net Income) - [(a) + (c)] /
(h)
|
|
-3.7%
|
|
|
0.9%
|
|
|
13.7%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Return on Equity
(ROE)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROE (GAAP) (GAAP
Net Income) - (b) / (e)
|
|
-8.1%
|
|
|
-29.5%
|
|
|
17.6%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROE (Non-GAAP)
(Non-GAAP Adjusted Net Income) - (c) / (e)
|
|
-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
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(b) 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(c) 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.
|
Fourth Quarter and
Full Year 2017 Forecast and Benchmark Commodity
Pricing
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Fourth Quarter and
Full Year 2017 Forecast
|
|
|
|
|
|
|
|
|
|
|
|
|
The forecast items
for the fourth quarter and full year 2017 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)
|
|
|
|
|
|
4Q 2017
|
|
|
Full Year
2017
|
Daily Sales
Volumes
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil and Condensate
Volumes (MBbld)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
362.0
|
-
|
|
370.0
|
|
|
334.0
|
-
|
|
336.0
|
Trinidad
|
|
0.5
|
-
|
|
0.7
|
|
|
0.7
|
-
|
|
0.8
|
Other International
|
|
0.0
|
-
|
|
0.0
|
|
|
0.8
|
-
|
|
0.8
|
Total
|
|
362.5
|
-
|
|
370.7
|
|
|
335.5
|
-
|
|
337.6
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids Volumes
(MBbld)
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
84.0
|
-
|
|
94.0
|
|
|
84.2
|
-
|
|
86.8
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Volumes
(MMcfd)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
780
|
-
|
|
820
|
|
|
753
|
-
|
|
763
|
Trinidad
|
|
290
|
-
|
|
330
|
|
|
310
|
-
|
|
320
|
Other International
|
|
20
|
-
|
|
35
|
|
|
22
|
-
|
|
26
|
Total
|
|
1,090
|
-
|
|
1,185
|
|
|
1,085
|
-
|
|
1,109
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Equivalent Volumes
(MBoed)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
576.0
|
-
|
|
600.7
|
|
|
543.7
|
-
|
|
550.0
|
Trinidad
|
|
48.8
|
-
|
|
55.7
|
|
|
52.4
|
-
|
|
54.2
|
Other International
|
|
3.3
|
-
|
|
5.8
|
|
|
4.4
|
-
|
|
5.0
|
Total
|
|
628.1
|
-
|
|
662.2
|
|
|
600.5
|
-
|
|
609.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
Ranges
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
|
4Q 2017
|
|
|
Full Year
2017
|
Operating
Costs
|
|
|
|
|
|
|
|
|
|
|
|
Unit Costs
($/Boe)
|
|
|
|
|
|
|
|
|
|
|
|
Lease and Well
|
$
|
4.10
|
-
|
$
|
4.50
|
|
$
|
4.56
|
-
|
$
|
4.70
|
Transportation Costs
|
$
|
3.15
|
-
|
$
|
3.65
|
|
$
|
3.33
|
-
|
$
|
3.47
|
Depreciation, Depletion and Amortization
|
$
|
15.15
|
-
|
$
|
15.70
|
|
$
|
15.52
|
-
|
$
|
15.67
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses
($MM)
|
|
|
|
|
|
|
|
|
|
|
|
Exploration, Dry Hole and
Impairment
|
$
|
90
|
-
|
$
|
120
|
|
$
|
377
|
-
|
$
|
407
|
General and
Administrative
|
$
|
100
|
-
|
$
|
110
|
|
$
|
404
|
-
|
$
|
414
|
Gathering and
Processing
|
$
|
35
|
-
|
$
|
38
|
|
$
|
140
|
-
|
$
|
143
|
Capitalized
Interest
|
$
|
5
|
-
|
$
|
7
|
|
$
|
26
|
-
|
$
|
28
|
Net Interest
|
$
|
62
|
-
|
$
|
64
|
|
$
|
273
|
-
|
$
|
275
|
|
|
|
|
|
|
|
|
|
|
|
|
Taxes Other Than
Income (% of Wellhead Revenue)
|
|
6.1%
|
-
|
|
6.5%
|
|
|
6.7%
|
-
|
|
6.9%
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Taxes
|
|
|
|
|
|
|
|
|
|
|
|
Effective
Rate
|
|
36%
|
-
|
|
41%
|
|
|
36%
|
-
|
|
41%
|
Current Taxes
($MM)
|
$
|
(10)
|
-
|
$
|
25
|
|
$
|
(30)
|
-
|
$
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures
(Excluding Acquisitions, $MM)
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and Development,
Excluding Facilities
|
|
|
|
|
|
|
$
|
3,000
|
-
|
$
|
3,350
|
Exploration and Development
Facilities
|
|
|
|
|
|
|
$
|
475
|
-
|
$
|
510
|
Gathering, Processing and
Other
|
|
|
|
|
|
|
$
|
225
|
-
|
$
|
240
|
|
|
|
|
|
|
|
|
|
|
|
|
Pricing - (Refer
toBenchmark Commodity Pricingin text)
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil and Condensate
($/Bbl)
|
|
|
|
|
|
|
|
|
|
|
|
Differentials
|
|
|
|
|
|
|
|
|
|
|
|
United States - above (below) WTI
|
$
|
0.25
|
-
|
$
|
2.25
|
|
$
|
(0.55)
|
-
|
$
|
0.00
|
Trinidad - above (below) WTI
|
$
|
(10.50)
|
-
|
$
|
(9.50)
|
|
$
|
(9.47)
|
-
|
$
|
(9.27)
|
Other International - above (below) WTI
|
$
|
(5.00)
|
-
|
$
|
(3.00)
|
|
$
|
(5.00)
|
-
|
$
|
(4.50)
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
Liquids
|
|
|
|
|
|
|
|
|
|
|
|
Realizations as % of WTI
|
|
36%
|
-
|
|
42%
|
|
|
41%
|
-
|
|
42%
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
($/Mcf)
|
|
|
|
|
|
|
|
|
|
|
|
Differentials
|
|
|
|
|
|
|
|
|
|
|
|
United States - above (below) NYMEX Henry Hub
|
$
|
(1.15)
|
-
|
$
|
(0.75)
|
|
$
|
(0.97)
|
-
|
$
|
(0.86)
|
|
|
|
|
|
|
|
|
|
|
|
|
Realizations
|
|
|
|
|
|
|
|
|
|
|
|
Trinidad
|
$
|
1.90
|
-
|
$
|
2.30
|
|
$
|
2.22
|
-
|
$
|
2.32
|
Other International
|
$
|
3.95
|
-
|
$
|
4.45
|
|
$
|
3.79
|
-
|
$
|
3.94
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
View original
content:http://www.prnewswire.com/news-releases/eog-resources-announces-third-quarter-2017-results-announces-two-new-premium-oil-plays-adding-800-net-premium-well-locations-and-750-mmboe-estimated-net-resource-potential-300548853.html
SOURCE EOG Resources, Inc.