HOUSTON, May 3, 2018 /PRNewswire/ --
- Reports Strong Operating Results
-
- Achieves Record Returns on First Quarter Capital
Investments
- U.S. Oil Production Near High End of Target Range
- U.S. Realized Crude Oil Price Exceeds WTI NYMEX Average
- Per-Unit Transportation and DD&A Expenses Below
Targets
- Maintains Full-Year $5.4-$5.8 Billion
Exploration and Development Expenditure Target
-
- On Track to Reduce Well Costs 5 Percent in 2018
- Reiterates Full-Year 2018 Oil Production Growth Target of 16-20
Percent
- Targets $3 Billion Debt Reduction
and Higher Dividend Growth Rate
EOG Resources, Inc. (NYSE: EOG) (EOG) today reported first
quarter 2018 net income of $638.6
million, or $1.10 per share.
This compares to first quarter 2017 net income of $28.5 million, or $0.05 per share.
Adjusted non-GAAP net income for the first quarter 2018 was
$689.5 million, or $1.19 per share, compared to adjusted non-GAAP
net income of $89.4 million, or
$0.15 per share, for the same prior
year period. Higher commodity prices, increased production
volumes and overall per-unit cost reductions resulted in increases
to adjusted non-GAAP net income, discretionary cash flow and
EBITDAX during the first quarter 2018 compared to the first quarter
2017. Adjusted non-GAAP net income is calculated by matching
hedge realizations to settlement months and making certain other
adjustments in order to exclude one-time items. Please refer
to the attached tables for the reconciliation of non-GAAP measures
to GAAP measures.
Operational Highlights
EOG achieved record returns on new capital investments in the first
quarter 2018. The company increased first quarter 2018 crude oil
production by 15 percent compared to the first quarter
2017. EOG maintained its forecast for 16 to 20 percent
crude oil growth for full year 2018. Strong production growth
reflects the company's premium drilling strategy and technical
advances across its diverse inventory of high-return plays.
EOG defines premium drilling as prospective well locations that
will earn a minimum 30 percent direct after-tax rate of return at
$40 crude oil and $2.50 natural gas prices. EOG's prolific
Delaware Basin, Eagle Ford and
Powder River Basin assets all contributed to growth this
quarter. The company realized an average price for U.S. crude
oil sales in the first quarter 2018 of $64.24 per barrel. This is $1.35 per barrel above the average WTI NYMEX
price during the same period.
Overall per-unit operating expenses decreased during the first
quarter 2018. This performance was led by a 21 percent
reduction in per-unit depreciation, depletion and amortization
(DD&A) expenses compared to the same prior year period.
Per-unit transportation and general and administrative costs also
declined during the first quarter 2018.
EOG maintained its forecast for 2018 capital expenditures of
$5.4 to $5.8
billion, excluding acquisitions and non-cash
transactions. The company remains on track to reduce average
well costs by five percent in 2018.
"EOG delivered another sterling performance in the first quarter
despite a challenging operating environment," said William R.
"Bill" Thomas, Chairman and Chief Executive Officer. "New
capital investments produced record-level rates of return. Our
innovative employees executed our game plan with high efficiency to
deliver results that met or exceeded expectations while remaining
on track to lower costs. EOG is well positioned to accomplish
its full-year plan and generate high-return, disciplined growth in
2018."
Capital Structure and Financial Strategy
At March 31, 2018, EOG's total debt
outstanding was $6.4 billion for a
debt-to-total capitalization ratio of 28 percent. Considering
cash on the balance sheet at the end of the first quarter, EOG's
net debt was $5.6 billion for 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.
EOG intends to repay bonds as they mature over the next four
years, with a goal to reduce total debt outstanding by $3 billion. In addition, the company is
targeting an increase in its historical rate of dividend
growth. Sustainable dividend growth is a distinguishing
attribute of EOG. The company increased its dividend at a 19
percent compound annual rate from 1999 to 2017 without any
reductions. The shift to premium drilling and the recovery in
oil prices have increased EOG's after-tax rate of return on new
investments to record levels. With an improving financial
condition, EOG now aims to grow its dividend at a higher rate than
its historical average.
"EOG is uniquely positioned to generate strong organic growth,
increase return on capital employed, further strengthen the balance
sheet and step up cash returns to shareholders," noted
Thomas. "Our objectives to reduce debt outstanding and
increase the dividend growth rate reflect the strength of our
business model. The company is capable of withstanding price
volatility and well positioned to create significant shareholder
value through commodity cycles."
Delaware Basin
In the first quarter 2018, EOG shifted to larger-scale development
activity in the Delaware Basin
utilizing 19 rigs compared to 13 rigs in 2017. Seventy new
wells began production across multiple targets, although only 14 of
these were brought on-line in January. Activity was focused
on further delineating additional targets and testing development
patterns in different areas of the basin.
In the Delaware Basin Wolfcamp,
EOG completed several notable wells, including the State Magellan 7
22H-28H. This seven-well package, drilled on 500-foot
spacing, was completed with an average treated lateral length of
4,700 feet per well and average 30-day initial production rates per
well of 2,200 barrels of oil equivalent per day (Boed), or 1,455
barrels of oil per day (Bopd), 310 barrels per day (Bpd) of natural
gas liquids (NGLs) and 2.6 million cubic feet per day (MMcfd) of
natural gas.
In the Delaware Basin First
Bone Spring, EOG completed the Beowulf 33 State Com 301H in
Lea County, NM with a treated
lateral length of 6,900 feet and a 30-day initial production rate
of 1,735 Boed, or 1,275 Bopd, 200 Bpd of NGLs and 1.6 MMcfd of
natural gas.
In the Delaware Basin Leonard,
EOG completed the Gem 36 State Com 05H and 06H with an average
treated lateral length per well of 4,200 feet and average 30-day
initial production rates per well of 2,555 Boed, or 1,605 Bopd, 395
Bpd of NGLs and 3.3 MMcfd of natural gas.
South Texas Eagle Ford and Austin Chalk
EOG's South Texas Eagle Ford continued to generate strong results
across the entire extent of its 520,000 net acre position in the
crude oil window of the play. EOG continues to optimize its
wells with staggered patterns and enhanced targeting, which is
producing premium-level returns even in heavily developed parts of
the field. Wells completed in the first quarter were drilled
with an average distance between wells of approximately 300 feet
per well. Lateral lengths are also being extended, primarily
in the western half of the field, where lateral lengths averaged
9,200 feet per well in the first quarter.
Notable wells in the first quarter included the Presley Unit
12H-14H, a three-well package in Karnes
County, TX with an average treated lateral length of 6,800
feet per well and average 30-day initial production rates per well
of 3,360 Boed, or 2,670 Bopd, 350 Bpd of NGLs and 2.0 MMcfd of
natural gas. On the western side of the Eagle Ford in
Atascosa County, TX, EOG completed
the Watermelon Unit 2H and 3H with an average treated lateral
length of 12,400 feet per well and average 30-day initial
production rates per well of 1,680 Boed, or 1,490 Bopd, 100 Bpd of
NGLs and 0.6 MMcfd of natural gas.
Development continued in the Austin Chalk, with the first
quarter drilling program highlighted by the Elbrus 101H and 102H,
with an average treated lateral length of 4,600 feet per well and
average 30-day initial production rates per well of 4,305 Boed, or
2,980 Bopd, 670 Bpd of NGLs and 3.9 MMcfd of natural gas.
Rockies and the Bakken
During the first quarter, EOG continued to develop its premium
Powder River Basin and DJ Basin positions and began its 2018
drilling program in the Bakken. The company continued to
lower well costs in its Rockies plays by improving drilling and
completion times along with other efficiency
improvements.
EOG brought 12 wells on line in the Powder River Basin during
the first quarter 2018, including nine targeting the Turner
formation. Notably, the Flatbow 16-36H–18-36H, a three-well
package in the Powder River Turner, was completed with an average
treated lateral length of 3,900 feet per well and average 30-day
initial production rates per well of 1,325 Boed, or 775 Bopd, 190
Bpd of NGLs and 2.2 MMcfd of natural gas. These short-lateral
wells had an average cost of $2.9
million per well.
In the DJ Basin, EOG began production in the first quarter from
12 wells. In particular, a four-well package of DJ Basin
Codell wells, the Big Sandy 529,
552, 553 and 554-1423H, was completed with an average treated
lateral length of 9,500 feet per well and average 30-day initial
production rates per well of 1,340 Boed, or 1,120 Bopd, 135 Bpd of
NGLs and 0.5 MMcfd of natural gas. These wells were drilled
in an average of 4.2 days per well with an average cost of
$3.5 million per well.
In the North Dakota Bakken, EOG drilled 4 wells in the first
quarter and deferred completions until later in 2018.
Woodford Oil Window
EOG continued development of its new oil play in the Woodford
formation of the Eastern Anadarko Basin. In the first
quarter, EOG increased drilling operations to three rigs and added
a fourth rig in April. Production began from one well during
the quarter. The Terri 1621 #1H was completed with a treated
lateral length of 10,200 feet and a 30-day initial production rate
of 1,395 Boed, or 1,140 Bopd, 165 Bpd of NGLs and 0.5 MMcfd of
natural gas.
Hedging Activity
During the first quarter ended March 31,
2018, EOG entered into crude oil financial price swap
contracts. A comprehensive summary of crude oil and natural
gas derivative contracts is provided in the attached
tables.
Conference Call May 4,
2018
EOG's first quarter 2018 results conference call will be available
via live audio webcast at 9 a.m. Central
time (10 a.m. Eastern time) on
Friday, May 4, 2018. To listen,
log on to the Investors Overview page on the EOG website at
http://investors.eogresources.com/overview. The webcast will
be archived on EOG's website for one year.
EOG Resources, Inc. is one of the largest independent
(non-integrated) crude oil and natural gas companies in
the United States with proved
reserves in the United States,
Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on
the New York Stock Exchange and is traded under the ticker symbol
"EOG."
This press release includes forward-looking statements within
the meaning of Section 27A of the Securities Act of 1933, as
amended, and Section 21E of the Securities Exchange Act of 1934, as
amended. All statements, other than statements of historical
facts, including, among others, statements and projections
regarding EOG's future financial position, operations, performance,
business strategy, returns, budgets, reserves, levels of
production, costs and asset sales, statements regarding future
commodity prices and statements regarding the plans and objectives
of EOG's management for future operations, are forward-looking
statements. EOG typically uses words such as "expect,"
"anticipate," "estimate," "project," "strategy," "intend," "plan,"
"target," "aims," "goal," "may," "will," "should" and "believe" or
the negative of those terms or other variations or comparable
terminology to identify its forward-looking statements. In
particular, statements, express or implied, concerning EOG's future
operating results and returns or EOG's ability to replace or
increase reserves, increase production, reduce or otherwise control
operating and capital costs, generate income or cash flows, pay
down indebtedness or pay and/or increase dividends are
forward-looking statements. Forward-looking statements are
not guarantees of performance. Although EOG believes the
expectations reflected in its forward-looking statements are
reasonable and are based on reasonable assumptions, no assurance
can be given that these assumptions are accurate or that any of
these expectations will be achieved (in full or at all) or will
prove to have been correct. Moreover, EOG's forward-looking
statements may be affected by known, unknown or currently
unforeseen risks, events or circumstances that may be outside EOG's
control. Furthermore, EOG has presented or referenced herein
or in its accompanying disclosures certain forward-looking,
non-GAAP financial measures, such as free cash flow and
discretionary cash flow, and certain related estimates regarding
future performance, results and financial position. These
forward-looking measures and estimates are intended to be
illustrative only and are not intended to reflect the results that
EOG will necessarily achieve for the period(s) presented.
EOG's actual results may differ materially from the measure and
estimates presented or referenced herein. Important factors
that could cause EOG's actual results to differ materially from the
expectations reflected in EOG's forward-looking statements include,
among others:
- the timing, extent and duration of changes in prices for,
supplies of, and demand for, crude oil and condensate, natural gas
liquids, natural gas and related commodities;
- the extent to which EOG is successful in its efforts to acquire
or discover additional reserves;
- the extent to which EOG is successful in its efforts to
economically develop its acreage in, produce reserves and achieve
anticipated production levels from, and maximize reserve recovery
from, its existing and future crude oil and natural gas exploration
and development projects;
- the extent to which EOG is successful in its efforts to market
its crude oil and condensate, natural gas liquids, natural gas and
related commodity production;
- the availability, proximity and capacity of, and costs
associated with, appropriate gathering, processing, compression,
transportation and refining facilities;
- the availability, cost, terms and timing of issuance or
execution of, and competition for, mineral licenses and leases and
governmental and other permits and rights-of-way, and EOG's ability
to retain mineral licenses and leases;
- the impact of, and changes in, government policies, laws and
regulations, including tax laws and regulations; environmental,
health and safety laws and regulations relating to air emissions,
disposal of produced water, drilling fluids and other wastes,
hydraulic fracturing and access to and use of water; laws and
regulations imposing conditions or restrictions on drilling and
completion operations and on the transportation of crude oil and
natural gas; laws and regulations with respect to derivatives and
hedging activities; and laws and regulations with respect to the
import and export of crude oil, natural gas and related
commodities;
- EOG's ability to effectively integrate acquired crude oil and
natural gas properties into its operations, fully identify existing
and potential problems with respect to such properties and
accurately estimate reserves, production and costs with respect to
such properties;
- the extent to which EOG's third-party-operated crude oil and
natural gas properties are operated successfully and
economically;
- competition in the oil and gas exploration and production
industry for the acquisition of licenses, leases and properties,
employees and other personnel, facilities, equipment, materials and
services;
- the availability and cost of employees and other personnel,
facilities, equipment, materials (such as water) and services;
- the accuracy of reserve estimates, which by their nature
involve the exercise of professional judgment and may therefore be
imprecise;
- weather, including its impact on crude oil and natural gas
demand, and weather-related delays in drilling and in the
installation and operation (by EOG or third parties) of production,
gathering, processing, refining, compression and transportation
facilities;
- the ability of EOG's customers and other contractual
counterparties to satisfy their obligations to EOG and, related
thereto, to access the credit and capital markets to obtain
financing needed to satisfy their obligations to EOG;
- EOG's ability to access the commercial paper market and other
credit and capital markets to obtain financing on terms it deems
acceptable, if at all, and to otherwise satisfy its capital
expenditure requirements;
- the extent to which EOG is successful in its completion of
planned asset dispositions;
- the extent and effect of any hedging activities engaged in by
EOG;
- the timing and extent of changes in foreign currency exchange
rates, interest rates, inflation rates, global and domestic
financial market conditions and global and domestic general
economic conditions;
- political conditions and developments around the world (such as
political instability and armed conflict), including in the areas
in which EOG operates;
- the use of competing energy sources and the development of
alternative energy sources;
- the extent to which EOG incurs uninsured losses and liabilities
or losses and liabilities in excess of its insurance coverage;
- acts of war and terrorism and responses to these acts;
- physical, electronic and cyber security breaches; and
- the other factors described under ITEM 1A, Risk Factors, on
pages 14 through 23 of EOG's Annual Report on Form 10-K for the
fiscal year ended December 31, 2017,
and any updates to those factors set forth in EOG's subsequent
Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.
In light of these risks, uncertainties and assumptions, the
events anticipated by EOG's forward-looking statements may not
occur, and, if any of such events do, we may not have anticipated
the timing of their occurrence or the duration and extent of their
impact on our actual results. Accordingly, you should not
place any undue reliance on any of EOG's forward-looking
statements. EOG's forward-looking statements speak only as of the
date made, and EOG undertakes no obligation, other than as required
by applicable law, to update or revise its forward-looking
statements, whether as a result of new information, subsequent
events, anticipated or unanticipated circumstances or
otherwise.
The United States Securities and Exchange Commission (SEC)
permits oil and gas companies, in their filings with the SEC, to
disclose not only "proved" reserves (i.e., quantities of oil and
gas that are estimated to be recoverable with a high degree of
confidence), but also "probable" reserves (i.e., quantities of oil
and gas that are as likely as not to be recovered) as well as
"possible" reserves (i.e., additional quantities of oil and gas
that might be recovered, but with a lower probability than probable
reserves). Statements of reserves are only estimates and may
not correspond to the ultimate quantities of oil and gas recovered.
Any reserve estimates provided in this press release that are not
specifically designated as being estimates of proved reserves may
include "potential" reserves and/or other estimated reserves not
necessarily calculated in accordance with, or contemplated by, the
SEC's latest reserve reporting guidelines. Investors are
urged to consider closely the disclosure in EOG's Annual Report on
Form 10-K for the fiscal year ended December
31, 2017, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor
Relations). You can also obtain this report from the SEC by calling
1-800-SEC-0330 or from the SEC's website at www.sec.gov. In
addition, reconciliation and calculation schedules for non-GAAP
financial measures can be found on the EOG website at
www.eogresources.com.
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
|
|
March
31,
|
|
2018
|
|
2017
|
|
|
|
|
|
|
Operating Revenues
and Other
|
$
|
3,681.2
|
|
$
|
2,610.6
|
Net
Income
|
$
|
638.6
|
|
$
|
28.5
|
Net Income Per
Share
|
|
|
|
|
|
Basic
|
$
|
1.11
|
|
$
|
0.05
|
Diluted
|
$
|
1.10
|
|
$
|
0.05
|
Average Number of
Common Shares
|
|
|
|
|
|
Basic
|
|
575.8
|
|
|
573.9
|
Diluted
|
|
579.7
|
|
|
578.6
|
|
|
|
|
|
|
|
|
|
|
|
|
Summary Income
Statements
|
(Unaudited; in
thousands, except per share data)
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
March
31,
|
|
2018
|
|
2017
|
Operating Revenues
and Other
|
|
|
|
Crude Oil
and Condensate
|
$
|
2,101,308
|
|
$
|
1,430,061
|
Natural
Gas Liquids
|
|
221,415
|
|
|
153,444
|
Natural
Gas
|
|
299,766
|
|
|
230,602
|
Gains
(Losses) on Mark-to-Market Commodity Derivative
Contracts
|
|
(59,771)
|
|
|
62,020
|
Gathering,
Processing and Marketing
|
|
1,101,822
|
|
|
726,537
|
Losses on
Asset Dispositions, Net
|
|
(14,969)
|
|
|
(16,758)
|
Other,
Net
|
|
31,591
|
|
|
24,659
|
Total
|
|
3,681,162
|
|
|
2,610,565
|
Operating
Expenses
|
|
|
|
|
|
Lease and
Well
|
|
300,064
|
|
|
255,777
|
Transportation Costs
|
|
176,957
|
|
|
178,714
|
Gathering
and Processing Costs
|
|
101,345
|
|
|
38,144
|
Exploration Costs
|
|
34,836
|
|
|
56,894
|
Impairments
|
|
64,609
|
|
|
193,187
|
Marketing
Costs
|
|
1,106,390
|
|
|
736,536
|
Depreciation, Depletion and Amortization
|
|
748,591
|
|
|
816,036
|
General
and Administrative
|
|
94,698
|
|
|
97,238
|
Taxes
Other Than Income
|
|
179,084
|
|
|
130,293
|
Total
|
|
2,806,574
|
|
|
2,502,819
|
|
|
|
|
|
|
Operating
Income
|
|
874,588
|
|
|
107,746
|
|
|
|
|
|
|
Other Income,
Net
|
|
727
|
|
|
3,151
|
|
|
|
|
|
|
Income Before
Interest Expense and Income Taxes
|
|
875,315
|
|
|
110,897
|
|
|
|
|
|
|
Interest Expense,
Net
|
|
61,956
|
|
|
71,515
|
|
|
|
|
|
|
Income Before Income
Taxes
|
|
813,359
|
|
|
39,382
|
|
|
|
|
|
|
Income Tax
Provision
|
|
174,770
|
|
|
10,865
|
|
|
|
|
|
|
Net
Income
|
$
|
638,589
|
|
$
|
28,517
|
|
|
|
|
|
|
Dividends Declared
per Common Share
|
$
|
0.1850
|
|
$
|
0.1675
|
EOG RESOURCES,
INC.
|
Operating
Highlights
|
(Unaudited)
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
March
31,
|
|
2018
|
|
2017
|
Wellhead Volumes
and Prices
|
|
Crude Oil and
Condensate Volumes (MBbld) (A)
|
|
United
States
|
|
359.7
|
|
|
312.5
|
Trinidad
|
|
0.9
|
|
|
0.8
|
Other International
(B)
|
|
2.7
|
|
|
2.4
|
Total
|
|
363.3
|
|
|
315.7
|
|
|
|
|
|
|
Average Crude Oil and
Condensate Prices ($/Bbl) (C)
|
|
|
|
|
|
United
States
|
$
|
64.24
|
|
$
|
50.38
|
Trinidad
|
|
54.86
|
|
|
41.56
|
Other International
(B)
|
|
71.61
|
|
|
47.77
|
Composite
|
|
64.27
|
|
|
50.34
|
|
|
|
|
|
|
Natural Gas Liquids
Volumes (MBbld) (A)
|
|
|
|
|
|
United
States
|
|
100.6
|
|
|
78.8
|
Other International
(B)
|
|
-
|
|
|
-
|
Total
|
|
100.6
|
|
|
78.8
|
|
|
|
|
|
|
Average Natural Gas
Liquids Prices ($/Bbl) (C)
|
|
|
|
|
|
United
States
|
$
|
24.46
|
|
$
|
21.63
|
Other International
(B)
|
|
-
|
|
|
-
|
Composite
|
|
24.46
|
|
|
21.63
|
|
|
|
|
|
|
Natural Gas Volumes
(MMcfd) (A)
|
|
|
|
|
|
United
States
|
|
853
|
|
|
728
|
Trinidad
|
|
293
|
|
|
308
|
Other International
(B)
|
|
30
|
|
|
22
|
Total
|
|
1,176
|
|
|
1,058
|
|
|
|
|
|
|
Average Natural Gas
Prices ($/Mcf) (C)
|
|
|
|
|
|
United
States
|
$
|
2.76
|
|
$
|
2.32
|
Trinidad
|
|
2.88
|
|
|
2.57
|
Other International
(B)
|
|
4.36
|
|
|
3.76
|
Composite
|
|
2.83
|
(D)
|
|
2.42
|
|
|
|
|
|
|
Crude Oil Equivalent
Volumes (MBoed) (E)
|
|
|
|
|
|
United
States
|
|
602.5
|
|
|
512.6
|
Trinidad
|
|
49.8
|
|
|
52.2
|
Other International
(B)
|
|
7.6
|
|
|
5.9
|
Total
|
|
659.9
|
|
|
570.7
|
|
|
|
|
|
|
Total MMBoe
(E)
|
|
59.4
|
|
|
51.4
|
|
(A) Thousand barrels
per day or million cubic feet per day, as applicable.
|
(B) Other
International includes EOG's United Kingdom, China and Canada
operations.
|
(C) Dollars per
barrel or per thousand cubic feet, as applicable. Excludes
the impact of financial commodity derivative instruments (see Note
12 to the Condensed Consolidated Financial Statements on EOG's
Quarterly Report on Form 10-Q for the fiscal quarter ended March
31, 2018).
|
(D) Includes a
positive revenue adjustment of $0.41 per Mcf related to the
adoption of ASU 2014-09, "Revenue From Contracts with Customers"
(ASU 2014-09) (see Note 1 to the Condensed Consolidated Financial
Statements on EOG's Quarterly Report on Form 10-Q for the fiscal
quarter ended March 31, 2018). In connection with the adoption of
ASU 2014-09, EOG presents natural gas processing fees for certain
processing and marketing agreements as Gathering and Processing
Costs, instead of a deduction to Natural Gas Revenues.
|
(E) Thousand barrels
of oil equivalent per day or million barrels of oil equivalent, as
applicable; includes crude oil and condensate, NGLs and natural
gas. Crude oil equivalent volumes are determined using a
ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0
thousand cubic feet of natural gas. MMBoe is calculated by
multiplying the MBoed amount by the number of days in the period
and then dividing that amount by one thousand.
|
EOG RESOURCES,
INC.
|
Summary Balance
Sheets
|
(Unaudited; in
thousands, except share data)
|
|
|
|
|
|
|
|
March
31,
|
|
December
31,
|
|
2018
|
|
2017
|
ASSETS
|
Current
Assets
|
|
|
|
|
|
Cash and Cash
Equivalents
|
$
|
816,094
|
|
$
|
834,228
|
Accounts Receivable,
Net
|
|
1,702,100
|
|
|
1,597,494
|
Inventories
|
|
584,729
|
|
|
483,865
|
Assets from Price Risk
Management Activities
|
|
761
|
|
|
7,699
|
Income Taxes
Receivable
|
|
262,789
|
|
|
113,357
|
Other
|
|
218,624
|
|
|
242,465
|
Total
|
|
3,585,097
|
|
|
3,279,108
|
|
|
|
|
|
|
Property, Plant
and Equipment
|
|
|
|
|
|
Oil and Gas Properties
(Successful Efforts Method)
|
|
53,854,438
|
|
|
52,555,741
|
Other Property, Plant and
Equipment
|
|
4,082,781
|
|
|
3,960,759
|
Total Property, Plant and Equipment
|
|
57,937,219
|
|
|
56,516,500
|
Less: Accumulated
Depreciation, Depletion and Amortization
|
|
(31,561,571)
|
|
|
(30,851,463)
|
Total Property, Plant and Equipment, Net
|
|
26,375,648
|
|
|
25,665,037
|
Deferred Income
Taxes
|
|
18,182
|
|
|
17,506
|
Other
Assets
|
|
761,590
|
|
|
871,427
|
Total
Assets
|
$
|
30,740,517
|
|
$
|
29,833,078
|
|
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS' EQUITY
|
Current
Liabilities
|
|
|
|
|
|
Accounts Payable
|
$
|
1,915,651
|
|
$
|
1,847,131
|
Accrued Taxes
Payable
|
|
179,646
|
|
|
148,874
|
Dividends Payable
|
|
106,521
|
|
|
96,410
|
Liabilities from Price Risk
Management Activities
|
|
84,128
|
|
|
50,429
|
Current Portion of Long-Term
Debt
|
|
363,155
|
|
|
356,235
|
Other
|
|
187,657
|
|
|
226,463
|
Total
|
|
2,836,758
|
|
|
2,725,542
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term
Debt
|
|
6,071,604
|
|
|
6,030,836
|
Other
Liabilities
|
|
1,301,938
|
|
|
1,275,213
|
Deferred Income
Taxes
|
|
3,689,578
|
|
|
3,518,214
|
Commitments and
Contingencies
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders'
Equity
|
|
|
|
|
|
Common Stock, $0.01 Par,
1,280,000,000 Shares Authorized and
579,272,616 Shares
Issued at March 31, 2018 and 578,827,768
Shares Issued at
December 31, 2017
|
|
205,793
|
|
|
205,788
|
Additional Paid in
Capital
|
|
5,569,194
|
|
|
5,536,547
|
Accumulated Other
Comprehensive Loss
|
|
(14,289)
|
|
|
(19,297)
|
Retained Earnings
|
|
11,125,051
|
|
|
10,593,533
|
Common Stock Held in
Treasury, 459,990 Shares at March 31, 2018 and 350,961 Shares at
December 31, 2017
|
|
(45,110)
|
|
|
(33,298)
|
Total Stockholders' Equity
|
|
16,840,639
|
|
|
16,283,273
|
Total Liabilities
and Stockholders' Equity
|
$
|
30,740,517
|
|
$
|
29,833,078
|
EOG RESOURCES,
INC.
|
Summary Statements
of Cash Flows
|
(Unaudited; in
thousands)
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
March
31,
|
|
2018
|
|
2017
|
Cash Flows from
Operating Activities
|
|
|
|
|
|
Reconciliation of Net
Income to Net Cash Provided by Operating Activities:
|
|
|
|
|
|
Net Income
|
$
|
638,589
|
|
$
|
28,517
|
Items Not Requiring
(Providing) Cash
|
|
|
|
|
|
Depreciation, Depletion and Amortization
|
|
748,591
|
|
|
816,036
|
Impairments
|
|
64,609
|
|
|
193,187
|
Stock-Based Compensation Expenses
|
|
35,486
|
|
|
30,460
|
Deferred Income Taxes
|
|
171,362
|
|
|
694
|
Losses on Asset Dispositions, Net
|
|
14,969
|
|
|
16,758
|
Other, Net
|
|
2,013
|
|
|
(3,052)
|
Mark-to-Market Commodity
Derivative Contracts
|
|
|
|
|
|
Total (Gains) Losses
|
|
59,771
|
|
|
(62,020)
|
Net Cash Received from (Payments for) Settlements of Commodity
Derivative Contracts
|
|
(21,965)
|
|
|
1,912
|
Other, Net
|
|
(478)
|
|
|
(428)
|
Changes in Components of
Working Capital and Other Assets and Liabilities
|
|
|
|
|
|
Accounts Receivable
|
|
(109,654)
|
|
|
28,688
|
Inventories
|
|
(106,799)
|
|
|
24,736
|
Accounts Payable
|
|
53,652
|
|
|
20,426
|
Accrued Taxes Payable
|
|
21,950
|
|
|
(38,613)
|
Other Assets
|
|
(8,863)
|
|
|
(44,677)
|
Other Liabilities
|
|
(29,055)
|
|
|
(51,251)
|
Changes in Components of
Working Capital Associated with Investing and Financing
Activities
|
|
17,988
|
|
|
(63,324)
|
Net Cash Provided
by Operating Activities
|
|
1,552,166
|
|
|
898,049
|
|
|
|
|
|
|
Investing Cash
Flows
|
|
|
|
|
|
Additions to Oil and Gas
Properties
|
|
(1,365,111)
|
|
|
(912,227)
|
Additions to Other Property,
Plant and Equipment
|
|
(76,100)
|
|
|
(34,336)
|
Proceeds from Sales of
Assets
|
|
2,829
|
|
|
46,812
|
Changes in Components of
Working Capital Associated with Investing Activities
|
|
(18,045)
|
|
|
63,324
|
Net Cash Used in
Investing Activities
|
|
(1,456,427)
|
|
|
(836,427)
|
|
|
|
|
|
|
Financing Cash
Flows
|
|
|
|
|
|
Dividends Paid
|
|
(97,026)
|
|
|
(96,707)
|
Treasury Stock
Purchased
|
|
(16,776)
|
|
|
(18,628)
|
Proceeds from Stock Options
Exercised and Employee Stock Purchase Plan
|
|
1,453
|
|
|
2,356
|
Repayment of Capital Lease
Obligation
|
|
(1,671)
|
|
|
(1,619)
|
Changes in Working Capital
Associated with Financing Activities
|
|
57
|
|
|
-
|
Net Cash Used in
Financing Activities
|
|
(113,963)
|
|
|
(114,598)
|
|
|
|
|
|
|
Effect of Exchange
Rate Changes on Cash
|
|
90
|
|
|
(353)
|
|
|
|
|
|
|
Decrease in Cash
and Cash Equivalents
|
|
(18,134)
|
|
|
(53,329)
|
Cash and Cash
Equivalents at Beginning of Period
|
|
834,228
|
|
|
1,599,895
|
Cash and Cash
Equivalents at End of Period
|
$
|
816,094
|
|
$
|
1,546,566
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Adjusted Net Income (Non-GAAP)
|
To Net Income
(GAAP)
|
(Unaudited; in
thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following chart
adjusts the three-month periods ended March 31, 2018 and 2017
reported Net Income (GAAP) to reflect actual net cash received from
(payments for) settlements of commodity derivative contracts by
eliminating the unrealized mark-to-market (gains) losses from these
transactions, to eliminate the net losses on asset dispositions in
2018 and 2017, to add back impairment charges related to certain of
EOG's assets in 2018 and 2017 and to eliminate certain adjustments
in 2018 related to the 2017 U.S. tax reform. EOG believes
this presentation may be useful to investors who follow the
practice of some industry analysts who adjust reported company
earnings to match hedge realizations to production settlement
months and make certain other adjustments to exclude non-recurring
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
|
|
March 31,
2018
|
|
March 31,
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 (GAAP)
|
$813,359
|
|
$(174,770)
|
|
$638,589
|
|
$
1.10
|
|
$
39,382
|
|
$(10,865)
|
|
$28,517
|
|
$
0.05
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Gains) Losses on
Mark-to-Market Commodity
Derivative Contracts
|
59,771
|
|
(13,166)
|
|
46,605
|
|
0.08
|
|
(62,020)
|
|
22,191
|
|
(39,829)
|
|
(0.07)
|
Net Cash Received
from (Payments for)
Settlements of Commodity Derivative
Contracts
|
(21,965)
|
|
4,838
|
|
(17,127)
|
|
(0.03)
|
|
1,912
|
|
(684)
|
|
1,228
|
|
-
|
Add: Net Losses
on Asset Dispositions
|
14,969
|
|
(3,324)
|
|
11,645
|
|
0.02
|
|
16,758
|
|
(5,736)
|
|
11,022
|
|
0.02
|
Add:
Impairments
|
20,876
|
|
(4,598)
|
|
16,278
|
|
0.03
|
|
137,751
|
|
(49,287)
|
|
88,464
|
|
0.15
|
Less: Tax
Reform Impact
|
-
|
|
(6,524)
|
|
(6,524)
|
|
(0.01)
|
|
-
|
|
-
|
|
-
|
|
-
|
Adjustments to Net
Income
|
73,651
|
|
(22,774)
|
|
50,877
|
|
0.09
|
|
94,401
|
|
(33,516)
|
|
60,885
|
|
0.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Net
Income (Non-GAAP)
|
$887,010
|
|
$(197,544)
|
|
$689,466
|
|
$
1.19
|
|
$133,783
|
|
$(44,381)
|
|
$89,402
|
|
$
0.15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Number of
Common Shares (GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
575,775
|
|
|
|
|
|
|
|
573,935
|
Diluted
|
|
|
|
|
|
|
579,726
|
|
|
|
|
|
|
|
578,593
|
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 periods ended March 31, 2018 and 2017
Net Cash Provided by Operating Activities (GAAP) to Discretionary
Cash Flow (Non-GAAP). EOG believes this presentation may be
useful to investors who follow the practice of some industry
analysts who adjust Net Cash Provided by Operating Activities for
Exploration Costs (excluding Stock-Based Compensation Expenses),
Other Non-Current Income Taxes - Net Receivable,Changes in
Components of Working Capital and Other Assets and Liabilities, and
Changes in Components of Working Capital Associated with Investing
and Financing Activities. EOG defines Free Cash Flow
(Non-GAAP) for a given period as Discretionary Cash Flow (Non-GAAP)
(see below reconciliation) for such period less the total cash
capital expenditures excluding acquisitions incurred (Non-GAAP)
during such period and dividends paid (GAAP) during such period, as
is illustrated below for the three months ended March 31,
2018. EOG management uses this information for comparative
purposes within the industry.
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
|
March
31,
|
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
Net Cash Provided by
Operating Activities (GAAP)
|
$
|
1,552,166
|
|
$
|
898,049
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
Exploration Costs
(excluding Stock-Based Compensation Expenses)
|
|
|
27,936
|
|
|
50,734
|
Other Non-Current
Income Taxes - Net Receivable
|
|
|
118,921
|
|
|
-
|
Changes in Components
of Working Capital and Other Assets and Liabilities
|
|
|
|
|
|
|
Accounts
Receivable
|
|
|
109,654
|
|
|
(28,688)
|
Inventories
|
|
|
106,799
|
|
|
(24,736)
|
Accounts
Payable
|
|
|
(53,652)
|
|
|
(20,426)
|
Accrued Taxes
Payable
|
|
|
(21,950)
|
|
|
38,613
|
Other
Assets
|
|
|
8,863
|
|
|
44,677
|
Other
Liabilities
|
|
|
29,055
|
|
|
51,251
|
Changes in Components
of Working Capital Associated with
|
|
|
|
|
|
|
Investing and
Financing Activities
|
|
|
(17,988)
|
|
|
63,324
|
|
Discretionary Cash
Flow (Non-GAAP)
|
|
$
|
1,859,804
|
|
$
|
1,072,798
|
|
|
|
|
|
|
|
Discretionary Cash
Flow (Non-GAAP) - Percentage Increase
|
|
|
73%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discretionary Cash
Flow (Non-GAAP)
|
|
$
|
1,859,804
|
|
|
|
Less:
|
|
|
|
|
|
|
Total Cash
Expenditures Excluding Acquisitions
(Non-GAAP)(a)
|
|
|
(1,477,830)
|
|
|
|
Dividends Paid
(GAAP)
|
|
|
(97,026)
|
|
|
|
Free Cash Flow
(Non-GAAP)
|
|
$
|
284,948
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) See below
reconciliation of Total Expenditures (GAAP) to Total Cash
Expenditures Excluding Acquisitions (Non-GAAP) for the three months
ended March 31, 2018:
|
|
|
|
|
|
|
|
Total Expenditures
(GAAP)
|
|
$
|
1,546,641
|
|
|
|
Less:
|
|
|
|
|
|
|
Asset Retirement Costs
|
|
|
(12,100)
|
|
|
|
Non-Cash Acquisition Costs of Other Property, Plant and
Equipment
|
|
|
(47,635)
|
|
|
|
Non-Cash Acquisition Costs of Unproved Properties
|
|
|
(8,809)
|
|
|
|
Acquisition Costs of Proved Properties
|
|
|
(267)
|
|
|
|
Total Cash
Expenditures Excluding Acquisitions (Non-GAAP)
|
|
$
|
1,477,830
|
|
|
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Adjusted Earnings Before Interest Expense,
Net,
|
Income Taxes,
Depreciation, Depletion and Amortization, Exploration
Costs,
|
Dry Hole Costs,
Impairments and Additional Items (Adjusted EBITDAX)
|
(Non-GAAP)
to Net Income (GAAP)
|
(Unaudited; in
thousands)
|
|
|
|
|
|
|
The following chart
adjusts the three-month periods ended March 31, 2018 and 2017
reported Net Income (GAAP) to Earnings Before Interest Expense
(Net), Income Taxes (Income Tax Provision), Depreciation, Depletion
and Amortization, Exploration Costs, Dry Hole Costs and Impairments
(EBITDAX) (Non-GAAP) and further adjusts such amount to reflect
actual net cash received from (payments for) settlements of
commodity derivative contracts by eliminating the unrealized
mark-to-market (MTM) (gains) losses from these transactions and to
eliminate the net losses on asset dispositions (Net). EOG
believes this presentation may be useful to investors who follow
the practice of some industry analysts who adjust reported Net
Income (GAAP) to add back Interest Expense (Net), Income Taxes
(Income Tax Provision), Depreciation, Depletion and Amortization,
Exploration Costs, Dry Hole Costs and Impairments and further
adjust such amount to match realizations to production settlement
months and make certain other adjustments to exclude non-recurring
and certain other items. EOG management uses this information
for purposes of comparing its financial performance with the
financial performance of other companies in the
industry.
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
March
31,
|
|
2018
|
|
2017
|
|
|
|
|
|
|
Net Income
(GAAP)
|
$
|
638,589
|
|
$
|
28,517
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
Interest Expense,
Net
|
|
61,956
|
|
|
71,515
|
Income Tax
Provision
|
|
174,770
|
|
|
10,865
|
Depreciation, Depletion and
Amortization
|
|
748,591
|
|
|
816,036
|
Exploration Costs
|
|
34,836
|
|
|
56,894
|
Impairments
|
|
64,609
|
|
|
193,187
|
EBITDAX (Non-GAAP)
|
|
1,723,351
|
|
|
1,177,014
|
Total (Gains) Losses on MTM
Commodity Derivative Contracts
|
|
59,771
|
|
|
(62,020)
|
Net Cash Received from
(Payments for) Settlements of Commodity Derivative
Contracts
|
|
(21,965)
|
|
|
1,912
|
Losses on Asset
Dispositions, Net
|
|
14,969
|
|
|
16,758
|
|
|
|
|
|
|
Adjusted EBITDAX
(Non-GAAP)
|
$
|
1,776,126
|
|
$
|
1,133,664
|
|
|
|
|
|
|
Adjusted EBITDAX
(Non-GAAP) - Percentage Increase
|
|
57%
|
|
|
|
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
|
|
March
31,
|
|
December
31,
|
|
2018
|
|
2017
|
|
|
|
|
|
|
Total Stockholders'
Equity - (a)
|
$
|
16,841
|
|
$
|
16,283
|
|
|
|
|
|
|
Current and Long-Term
Debt (GAAP) - (b)
|
|
6,435
|
|
|
6,387
|
Less:
Cash
|
|
(816)
|
|
|
(834)
|
Net Debt (Non-GAAP) -
(c)
|
|
5,619
|
|
|
5,553
|
|
|
|
|
|
|
Total Capitalization
(GAAP) - (a) + (b)
|
$
|
23,276
|
|
$
|
22,670
|
|
|
|
|
|
|
Total Capitalization
(Non-GAAP) - (a) + (c)
|
$
|
22,460
|
|
$
|
21,836
|
|
|
|
|
|
|
Debt-to-Total
Capitalization (GAAP) - (b) / [(a) + (b)]
|
|
28%
|
|
|
28%
|
|
|
|
|
|
|
Net Debt-to-Total
Capitalization (Non-GAAP) - (c) / [(a) + (c)]
|
|
25%
|
|
|
25%
|
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 April 26, 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 May 31, 2018 (closed)
|
|
15,000
|
|
$
1.063
|
June 1, 2018 through
December 31, 2018
|
|
15,000
|
|
1.063
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
|
|
|
|
|
|
|
|
|
January 1, 2019
through December 31, 2019
|
|
20,000
|
|
$
1.075
|
|
|
|
|
|
|
|
|
|
|
|
|
EOG has also entered
into crude oil basis swap contracts in order to fix the
differential between pricing in the U.S. Gulf Coast and Cushing,
Oklahoma (Gulf Coast Differential). Presented below is a
comprehensive summary of EOG's Gulf Coast Differential basis swap
contracts through April 26, 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 May 31, 2018 (closed)
|
|
37,000
|
|
$
3.818
|
June 1, 2018 through
December 31, 2018
|
|
37,000
|
|
3.818
|
|
|
|
|
|
|
|
|
|
|
|
|
Presented below is a
comprehensive summary of EOG's crude oil price swap contracts
through April 26, 2018, with notional volumes expressed in Bbld and
prices expressed in $/Bbl.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Price
Swap Contracts
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Volume
|
|
Average
Price
|
|
|
|
|
|
|
|
|
|
(Bbld)
|
|
($/Bbl)
|
2018
|
|
|
|
|
|
|
|
|
|
|
January 1, 2018
through March 31, 2018 (closed)
|
|
134,000
|
|
$
60.04
|
April 1, 2018 through
December 31, 2018
|
|
134,000
|
|
60.04
|
|
|
|
|
|
|
|
|
|
|
|
|
Presented below is a
comprehensive summary of EOG's natural gas price swap contracts
through April 26, 2018, with notional volumes expressed in MMBtud
and prices expressed in $/MMBtu.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Price
Swap Contracts
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Volume
|
|
Average
Price
|
|
|
|
|
|
|
|
|
|
(MMBtud)
|
|
($/MMBtu)
|
2018
|
|
|
|
|
|
|
|
|
|
|
March 1, 2018 through
May 31, 2018 (closed)
|
|
35,000
|
|
$
3.00
|
June 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
April 26, 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)
|
2018
|
|
|
|
|
|
|
|
|
|
|
March 1, 2018 through
May 31, 2018 (closed)
|
|
|
120,000
|
|
$
3.38
|
|
96,000
|
|
$
2.94
|
June 1, 2018 through
November 30, 2018
|
|
|
120,000
|
|
3.38
|
|
96,000
|
|
2.94
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
|
Second Quarter and
Full Year 2018 Forecast and Benchmark Commodity
Pricing
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Second Quarter and
Full Year 2018 Forecast
|
|
|
|
|
|
|
|
|
|
|
|
|
The forecast items
for the second 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)
|
|
|
|
|
|
|
|
2Q 2018
|
|
|
Full Year
2018
|
Daily Sales
Volumes
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil and Condensate
Volumes (MBbld)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
374.0
|
-
|
|
382.0
|
|
|
387.0
|
-
|
|
401.0
|
Trinidad
|
|
0.4
|
-
|
|
0.6
|
|
|
0.4
|
-
|
|
0.6
|
Other International
|
|
0.0
|
-
|
|
6.0
|
|
|
2.0
|
-
|
|
4.0
|
Total
|
|
374.4
|
-
|
|
388.6
|
|
|
389.4
|
-
|
|
405.6
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids Volumes
(MBbld)
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
100.0
|
-
|
|
110.0
|
|
|
100.0
|
-
|
|
110.0
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Volumes
(MMcfd)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
870
|
-
|
|
910
|
|
|
900
|
-
|
|
950
|
Trinidad
|
|
280
|
-
|
|
300
|
|
|
250
|
-
|
|
290
|
Other International
|
|
25
|
-
|
|
35
|
|
|
28
|
-
|
|
38
|
Total
|
|
1,175
|
-
|
|
1,245
|
|
|
1,178
|
-
|
|
1,278
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Equivalent Volumes
(MBoed)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
619.0
|
-
|
|
643.7
|
|
|
637.0
|
-
|
|
669.3
|
Trinidad
|
|
47.1
|
-
|
|
50.6
|
|
|
42.1
|
-
|
|
48.9
|
Other International
|
|
4.2
|
-
|
|
11.9
|
|
|
6.7
|
-
|
|
10.3
|
Total
|
|
670.3
|
-
|
|
706.2
|
|
|
685.8
|
-
|
|
728.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
Ranges
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
2Q 2018
|
|
|
Full Year
2018
|
Operating
Costs
|
|
|
|
|
|
|
|
|
|
|
|
Unit Costs
($/Boe)
|
|
|
|
|
|
|
|
|
|
|
|
Lease and Well
|
$
|
4.50
|
-
|
$
|
4.90
|
|
$
|
4.20
|
-
|
$
|
4.80
|
Transportation Costs
|
$
|
2.90
|
-
|
$
|
3.40
|
|
$
|
2.75
|
-
|
$
|
3.25
|
Depreciation, Depletion and Amortization
|
$
|
13.15
|
-
|
$
|
13.55
|
|
$
|
13.00
|
-
|
$
|
13.40
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses
($MM)
|
|
|
|
|
|
|
|
|
|
|
|
Exploration, Dry Hole and
Impairment
|
$
|
100
|
-
|
$
|
120
|
|
$
|
375
|
-
|
$
|
425
|
General and
Administrative
|
$
|
100
|
-
|
$
|
110
|
|
$
|
415
|
-
|
$
|
445
|
Gathering and
Processing
|
$
|
110
|
-
|
$
|
120
|
|
$
|
430
|
-
|
$
|
470
|
Capitalized
Interest
|
$
|
5
|
-
|
$
|
6
|
|
$
|
19
|
-
|
$
|
23
|
Net Interest
|
$
|
62
|
-
|
$
|
65
|
|
$
|
244
|
-
|
$
|
248
|
|
|
|
|
|
|
|
|
|
|
|
|
Taxes Other Than
Income (% of Wellhead Revenue)
|
|
6.5%
|
-
|
|
6.9%
|
|
|
6.5%
|
-
|
|
6.9%
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Taxes
|
|
|
|
|
|
|
|
|
|
|
|
Effective
Rate
|
|
20%
|
-
|
|
25%
|
|
|
20%
|
-
|
|
25%
|
Current Tax (Benefit) /
Expense ($MM)
|
$
|
(90)
|
-
|
$
|
(55)
|
|
$
|
(350)
|
-
|
$
|
(310)
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
$
|
(1.50)
|
-
|
$
|
0.50
|
|
$
|
(1.25)
|
-
|
$
|
0.75
|
Trinidad - above (below) WTI
|
$
|
(11.00)
|
-
|
$
|
(9.00)
|
|
$
|
(11.00)
|
-
|
$
|
(9.00)
|
Other International - above (below) WTI
|
$
|
2.00
|
-
|
$
|
4.00
|
|
$
|
0.00
|
-
|
$
|
6.00
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
Liquids
|
|
|
|
|
|
|
|
|
|
|
|
Realizations as % of WTI
|
|
32%
|
-
|
|
38%
|
|
|
32%
|
-
|
|
38%
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
($/Mcf)
|
|
|
|
|
|
|
|
|
|
|
|
Differentials
|
|
|
|
|
|
|
|
|
|
|
|
United States - above (below) NYMEX Henry Hub
|
$
|
(0.70)
|
-
|
$
|
(0.30)
|
|
$
|
(0.60)
|
-
|
$
|
0.00
|
|
|
|
|
|
|
|
|
|
|
|
|
Realizations
|
|
|
|
|
|
|
|
|
|
|
|
Trinidad
|
$
|
2.30
|
-
|
$
|
2.70
|
|
$
|
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.
|
First Quarter 2018
Well Results by Play
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wells
Online
|
|
|
|
Initial Gross
30-Day Average Production Rate
|
|
|
Gross
|
|
Net
|
|
Lateral
Length
(ft)
|
|
Crude Oil and
Condensate
(Bbld) (A)
|
|
Natural Gas
Liquids
(Bbld) (A)
|
|
Natural Gas
(MMcfd) (A)
|
|
Crude Oil
Equivalent
(Boed) (B)
|
Delaware
Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wolfcamp
|
|
58
|
|
53
|
|
5,900
|
|
1,335
|
|
250
|
|
2.1
|
|
1,925
|
Bone
Spring
|
|
9
|
|
8
|
|
5,900
|
|
1,195
|
|
190
|
|
1.6
|
|
1,645
|
Leonard
|
|
3
|
|
3
|
|
4,300
|
|
1,640
|
|
335
|
|
2.8
|
|
2,430
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Powder River Basin
Turner
|
|
9
|
|
8
|
|
6,100
|
|
675
|
|
180
|
|
2.1
|
|
1,210
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DJ Basin
Codell
|
|
12
|
|
9
|
|
9,200
|
|
895
|
|
95
|
|
0.4
|
|
1,055
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South Texas Eagle
Ford
|
|
72
|
|
65
|
|
6,900
|
|
1,325
|
|
150
|
|
0.9
|
|
1,620
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South Texas Austin
Chalk
|
|
10
|
|
8
|
|
4,600
|
|
1,960
|
|
400
|
|
2.3
|
|
2,750
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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-announces-first-quarter-2018-results-300642509.html
SOURCE EOG Resources, Inc.