HOUSTON, Feb. 26, 2019 /PRNewswire/ --
- Earns Record Net Income in 2018 and Generates Significant Net
Cash from Operating Activities and Free Cash Flow
- Exceeds Fourth Quarter Crude Oil and NGL Production Target
Midpoints
- Increases Proved Reserves by 16% and Replaces 238% of 2018
Production at Sub-$10 Finding
Cost
- Targets Improved Capital Efficiency, Significant Investment in
High-Quality New Drilling Potential and 12-16% U.S. Crude Oil
Volume Growth in 2019, Funded with Net Cash from Operating
Activities at $50 Oil
EOG Resources, Inc. (EOG) today reported fourth quarter
2018 net income of $893 million, or
$1.54 per share. This compares to
fourth quarter 2017 net income of $2.4
billion, or $4.20 per share.
For the full year 2018, EOG reported a company record net income of
$3.4 billion, or $5.89 per share, compared to $2.6 billion, or $4.46 per share, for the full year 2017. Net cash
from operating activities for the fourth quarter and full year 2018
was $2.1 billion and $7.8 billion, respectively.
Adjusted non-GAAP net income for the fourth quarter 2018 was
$718 million, or $1.24 per share, compared to adjusted non-GAAP
net income of $401 million, or
$0.69 per share, for the same prior
year period. Adjusted non-GAAP net income for the full year 2018
was $3.2 billion, or $5.54 per share, compared to adjusted non-GAAP
net income of $648 million, or
$1.12 per share, for the full year
2017. Please refer to the attached tables for the reconciliation of
non-GAAP measures to GAAP measures.
Fourth Quarter and Full Year 2018 Review
EOG delivered
exceptional financial and operating performance in 2018. The
company generated record net income and free cash flow, while
ending the year with strong improvements in well productivity and
additional cost reductions. Total company crude oil volumes grew 19
percent to 399,900 barrels of oil per day (Bopd). Natural gas
liquids production increased 31 percent, while natural gas volumes
grew 11 percent, contributing to total company production growth of
18 percent.
In the fourth quarter 2018, EOG exceeded the high end of its
target range for U.S. crude oil volumes by producing 430,300 Bopd,
an increase of 17 percent compared to the same prior year period.
Per-unit operating expenses declined during the fourth quarter 2018
compared to the same prior year period. Lower general and
administrative expenses, transportation costs and depreciation,
depletion and amortization expenses each contributed to the overall
cost reduction.
EOG generated $2.1 billion of
discretionary cash flow and incurred total expenditures of
$1.5 billion in the fourth quarter
2018. After considering cash exploration and development
expenditures, excluding acquisitions, of $1.3 billion and dividend payments of
$127 million, the company generated
free cash flow during the fourth quarter of $637 million. For the full year 2018 EOG
generated a company record $1.7
billion of free cash flow. Please refer to the attached
tables for the reconciliation of non-GAAP measures to GAAP
measures.
"Our goal at EOG is to be one of the best companies in the
S&P 500. Our stellar 2018 performance delivered a premium
combination of high returns and double-digit production growth
while generating record free cash flow," said William R. "Bill"
Thomas, Chairman and Chief Executive Officer. "Our 2018 results
show that we can be competitive with the best companies across all
sectors, and we remain relentlessly focused on further improving
our cost structure and operating performance."
2019 Capital Plan
EOG's capital plan is
custom-designed each year to increase returns and capital
efficiencies. In 2019, EOG is allocating more capital to
opportunistic, high quality new drilling potential and somewhat
less capital to drilling in established areas. The company's
disciplined growth strategy emphasizes generating free cash flow
while lowering well costs and per-unit operating expenses and
driving improvement in well productivity. Retaining high-quality
equipment and crews during the fourth quarter of 2018 positioned
the company to further improve efficiencies and returns in
2019.
EOG expects to grow U.S. crude oil production by 12 to 16
percent, fund capital investment and pay the dividend with net cash
from operating activities in 2019 at $50 oil. Exploration and development expenditures
for 2019 are expected to range from $6.1 to $6.5
billion, including facilities and gathering, processing and
other expenditures, excluding acquisitions and non-cash
exchanges.
EOG expects to complete approximately 740 net wells in 2019
compared to 763 net wells in 2018. Activity will remain focused in
EOG's highest rate-of-return oil assets in the Delaware Basin, Eagle Ford, Rockies, Woodford
and Bakken. The company's investment in new potential areas in
the United States includes
spending for leasing and related infrastructure to drill wells in a
number of new prospects in 2019.
"EOG's disciplined 2019 capital plan delivers improved capital
efficiency and strong high-return growth while making investments
in new organic high-quality drilling potential to improve the
future performance of the company," Thomas said. "Our focus on
innovation and operational execution, as well as our investment in
new drilling potential, will continue to increase the quality of
EOG's premium portfolio. EOG is poised to further improve its
position as one of the lowest cost oil producers in the global
market, able to create shareholder value through commodity price
cycles."
Operating Highlights
EOG completed 262 net wells in
the Delaware Basin and increased
crude oil production 47% to 126,800 Bopd in 2018. The company made
significant progress during 2018 in improving well productivity and
reducing well costs. EOG refined spacing and development patterns,
reduced drilling days and applied new completion technology
designed to lower costs and improve well productivity.
EOG continues to drive growth and operating efficiencies in its
premier South Texas Eagle Ford asset. In 2018, the company grew
crude oil production 9% to 171,000 Bopd. Of the 304 net wells
completed in 2018, EOG drilled a total of 65 wells with lateral
lengths greater than 10,000 feet. These wells included the
Slytherin C#3H, which, at 13,500 feet, was a company record in the
Eagle Ford.
EOG's Powder River Basin and Wyoming DJ Basin activity both
contributed to the company's 2018 crude oil production growth. In
the Powder River Basin, the company brought eight wells on line
during the fourth quarter targeting the Turner, Mowry and Parkman
formations. The company plans to add infrastructure and further
delineate the field and test additional targets in 2019 to be
positioned to execute a more robust development program in the
Niobrara and Mowry in 2020 and beyond. In the Wyoming DJ Basin, EOG
generated further cost reductions during 2018 through efficiency
improvements in drilling, completion and production operations. The
company brought 20 wells to sales in the fourth quarter, all
targeting the Codell formation. EOG expects further crude oil
production growth from its high rate of return drilling in the DJ
Basin in 2019.
EOG continued development of its premium play in the Eastern
Anadarko Basin Woodford Oil Window, where it brought five wells on
line in the fourth quarter. The company made significant progress
in reducing well costs during 2018, and, as a result, has lowered
its 2019 well cost target to $7.6
million.
In the Williston Basin, EOG realized significant operational
improvements in 2018. The company drilled 20 net wells with an
average treated lateral length of 9,500 feet per well. Efficient
drilling performance delivered, on average, an additional 1,000
feet of lateral length per well in 2018 for the same cost as 2017.
EOG's Austin 45-1113H well set a
company record in the basin with a spud-to-total depth time of 8.4
days.
Reserves
At year-end 2018, total company net proved
reserves were 2,928 million barrels of oil equivalent (MMBoe), an
increase of 16 percent compared to year-end 2017. Net proved
reserve additions from all sources, excluding revisions due to
price, replaced 238 percent of EOG's 2018 production at a finding
and development cost of $9.33 per
barrel of oil equivalent. Revisions due to price increased net
proved reserves by 35 MMBoe and asset divestitures decreased net
proved reserves by 11 MMBoe. For more reserves detail and a
reconciliation of non-GAAP measures to GAAP measures, please refer
to the attached tables.
For the 31st consecutive year, internal reserves estimates were
within five percent of estimates independently prepared by DeGolyer
and MacNaughton.
Financial Review
At December
31, 2018, EOG's total debt outstanding was $6.1 billion for a debt-to-total capitalization
ratio of 24 percent. Considering cash on the balance sheet at the
end of the fourth quarter, EOG's net debt was $4.5 billion for a net debt-to-total
capitalization ratio of 19 percent. For a reconciliation of
non-GAAP measures to GAAP measures, please refer to the attached
tables.
EOG completed its previously announced agreement to divest all
of its U.K. operations in the fourth quarter 2018. Proceeds from
the U.K. divestment and other asset sales in 2018 totaled
$227 million.
Fourth Quarter 2018 Results Webcast
Wednesday, February 27, 2019, 9:00 a.m. Central time (10:00 a.m. Eastern time)
Webcast will be available on EOG website for one year.
http://investors.eogresources.com/Investors
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of
the largest crude oil and natural gas exploration and production
companies in the United States
with proved reserves in the United
States, Trinidad, and
China. To learn more visit
www.eogresources.com.
Investor Contacts
David
Streit 713-571-4902
Neel Panchal 713-571-4884
John Wagner 713-571-4404
Media and Investor Contact
Kimberly Ehmer 713-571-4676
This press release may include 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, capital expenditures, 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,
generate returns, replace or increase drilling locations, reduce or
otherwise control operating costs and capital expenditures,
generate cash flows, pay down or refinance 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,
this press release and any accompanying disclosures may include or
reference certain forward-looking, non-GAAP financial measures,
such as free cash flow or discretionary cash flow, and certain
related estimates regarding future performance, results and
financial position. Any such 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 such measures and estimates. 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,
storage, 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; climate change and
other 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 tubulars) 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, storage 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;
- geopolitical factors and political conditions and
developments around the world (such as the imposition of tariffs or
trade or other economic sanctions, 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 cybersecurity 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, 2018
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 or 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 or resource estimates provided in this press release
that are not specifically designated as being estimates of proved
reserves may include "potential" reserves, "resource potential"
and/or other estimated reserves or estimated resources 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, 2018, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor
Relations). You can also obtain this report from the SEC by calling
1-800-SEC-0330 or from the SEC's website at www.sec.gov. In
addition, reconciliation and calculation schedules for non-GAAP
financial measures can be found on the EOG website at
www.eogresources.com.
EOG RESOURCES,
INC.
|
Financial
Report
|
(Unaudited; in
millions, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Twelve Months
Ended
|
|
December
31,
|
|
December
31,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues
and Other
|
$
|
4,574.5
|
|
$
|
3,340.4
|
|
$
|
17,275.4
|
|
$
|
11,208.3
|
Net
Income
|
$
|
892.8
|
|
$
|
2,430.5
|
|
$
|
3,419.0
|
|
$
|
2,582.6
|
Net Income Per
Share
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
$
|
1.55
|
|
$
|
4.22
|
|
$
|
5.93
|
|
$
|
4.49
|
Diluted
|
$
|
1.54
|
|
$
|
4.20
|
|
$
|
5.89
|
|
$
|
4.46
|
Average Number of
Common Shares
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
577.0
|
|
|
575.4
|
|
|
576.6
|
|
|
574.6
|
Diluted
|
|
580.3
|
|
|
579.2
|
|
|
580.4
|
|
|
578.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Summary Income
Statements
|
(Unaudited; in
thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Twelve Months
Ended
|
|
December
31,
|
|
December
31,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Operating Revenues
and Other
|
|
|
|
|
|
|
|
Crude Oil
and Condensate
|
$
|
2,383,326
|
|
$
|
1,929,471
|
|
$
|
9,517,440
|
|
$
|
6,256,396
|
Natural
Gas Liquids
|
|
266,037
|
|
|
249,172
|
|
|
1,127,510
|
|
|
729,561
|
Natural
Gas
|
|
389,213
|
|
|
246,922
|
|
|
1,301,537
|
|
|
921,934
|
Gains
(Losses) on Mark-to-Market Commodity
Derivative Contracts
|
|
132,095
|
|
|
(45,032)
|
|
|
(165,640)
|
|
|
19,828
|
Gathering,
Processing and Marketing
|
|
1,331,105
|
|
|
1,008,385
|
|
|
5,230,355
|
|
|
3,298,087
|
Gains
(Losses) on Asset Dispositions, Net
|
|
79,904
|
|
|
(65,220)
|
|
|
174,562
|
|
|
(99,096)
|
Other,
Net
|
|
(7,144)
|
|
|
16,741
|
|
|
89,635
|
|
|
81,610
|
Total
|
|
4,574,536
|
|
|
3,340,439
|
|
|
17,275,399
|
|
|
11,208,320
|
Operating
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
Lease and
Well
|
|
346,442
|
|
|
281,941
|
|
|
1,282,678
|
|
|
1,044,847
|
Transportation Costs
|
|
196,095
|
|
|
191,717
|
|
|
746,876
|
|
|
740,352
|
Gathering
and Processing Costs
|
|
112,396
|
|
|
43,295
|
|
|
436,973
|
|
|
148,775
|
Exploration Costs
|
|
33,862
|
|
|
22,941
|
|
|
148,999
|
|
|
145,342
|
Dry Hole
Costs
|
|
145
|
|
|
4,532
|
|
|
5,405
|
|
|
4,609
|
Impairments
|
|
186,087
|
|
|
153,442
|
|
|
347,021
|
|
|
479,240
|
Marketing
Costs
|
|
1,349,416
|
|
|
1,009,566
|
|
|
5,203,243
|
|
|
3,330,237
|
Depreciation, Depletion and Amortization
|
|
919,963
|
|
|
881,745
|
|
|
3,435,408
|
|
|
3,409,387
|
General
and Administrative
|
|
116,904
|
|
|
117,005
|
|
|
426,969
|
|
|
434,467
|
Taxes
Other Than Income
|
|
190,086
|
|
|
158,343
|
|
|
772,481
|
|
|
544,662
|
Total
|
|
3,451,396
|
|
|
2,864,527
|
|
|
12,806,053
|
|
|
10,281,918
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
1,123,140
|
|
|
475,912
|
|
|
4,469,346
|
|
|
926,402
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income,
Net
|
|
21,220
|
|
|
803
|
|
|
16,704
|
|
|
9,152
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before
Interest Expense and Income Taxes
|
|
1,144,360
|
|
|
476,715
|
|
|
4,486,050
|
|
|
935,554
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense,
Net
|
|
56,020
|
|
|
63,362
|
|
|
245,052
|
|
|
274,372
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before Income
Taxes
|
|
1,088,340
|
|
|
413,353
|
|
|
4,240,998
|
|
|
661,182
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax Provision
(Benefit)
|
|
195,572
|
|
|
(2,017,115)
|
|
|
821,958
|
|
|
(1,921,397)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income
|
$
|
892,768
|
|
$
|
2,430,468
|
|
$
|
3,419,040
|
|
$
|
2,582,579
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends Declared
per Common Share
|
$
|
0.2200
|
|
$
|
0.1675
|
|
$
|
0.8100
|
|
$
|
0.6700
|
|
|
EOG RESOURCES,
INC.
|
Operating
Highlights
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Twelve Months
Ended
|
|
December
31,
|
|
December
31,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Wellhead Volumes
and Prices
|
|
|
|
Crude Oil and
Condensate Volumes (MBbld) (A)
|
|
|
|
United
States
|
|
430.3
|
|
|
366.9
|
|
|
394.8
|
|
|
335.0
|
Trinidad
|
|
0.8
|
|
|
1.1
|
|
|
0.8
|
|
|
0.9
|
Other International
(B)
|
|
4.5
|
|
|
0.1
|
|
|
4.3
|
|
|
0.8
|
Total
|
|
435.6
|
|
|
368.1
|
|
|
399.9
|
|
|
336.7
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Crude Oil and
Condensate Prices ($/Bbl) (C)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$
|
59.37
|
|
$
|
56.95
|
|
$
|
65.16
|
|
$
|
50.91
|
Trinidad
|
|
51.80
|
|
|
46.56
|
|
|
57.26
|
|
|
42.30
|
Other International
(B)
|
|
70.44
|
|
|
45.72
|
|
|
71.45
|
|
|
57.20
|
Composite
|
|
59.47
|
|
|
56.97
|
|
|
65.21
|
|
|
50.91
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids
Volumes (MBbld) (A)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
|
122.8
|
|
|
100.6
|
|
|
116.1
|
|
|
88.4
|
Other International
(B)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
Total
|
|
122.8
|
|
|
100.6
|
|
|
116.1
|
|
|
88.4
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Natural Gas
Liquids Prices ($/Bbl) (C)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$
|
23.54
|
|
$
|
26.92
|
|
$
|
26.60
|
|
$
|
22.61
|
Other International
(B)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
Composite
|
|
23.54
|
|
|
26.92
|
|
|
26.60
|
|
|
22.61
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Volumes
(MMcfd) (A)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
|
974
|
|
|
829
|
|
|
923
|
|
|
765
|
Trinidad
|
|
230
|
|
|
299
|
|
|
266
|
|
|
313
|
Other International
(B)
|
|
32
|
|
|
32
|
|
|
30
|
|
|
25
|
Total
|
|
1,236
|
|
|
1,160
|
|
|
1,219
|
|
|
1,103
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Natural Gas
Prices ($/Mcf) (C)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$
|
3.50
|
|
$
|
2.17
|
|
$
|
2.88
|
|
$
|
2.20
|
Trinidad
|
|
3.03
|
|
|
2.52
|
|
|
2.94
|
|
|
2.38
|
Other International
(B)
|
|
4.02
|
|
|
4.23
|
|
|
4.08
|
|
|
3.89
|
Composite
|
|
3.42
|
(D)
|
|
2.31
|
|
|
2.92
|
(D)
|
|
2.29
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Equivalent
Volumes (MBoed) (E)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
|
715.5
|
|
|
605.6
|
|
|
664.7
|
|
|
551.0
|
Trinidad
|
|
39.0
|
|
|
51.0
|
|
|
45.1
|
|
|
53.0
|
Other International
(B)
|
|
10.0
|
|
|
5.4
|
|
|
9.4
|
|
|
4.9
|
Total
|
|
764.5
|
|
|
662.0
|
|
|
719.2
|
|
|
608.9
|
|
|
|
|
|
|
|
|
|
|
|
|
Total MMBoe
(E)
|
|
70.3
|
|
|
60.9
|
|
|
262.5
|
|
|
222.3
|
|
(A) Thousand barrels
per day or million cubic feet per day, as applicable.
|
(B) Other
International includes EOG's United Kingdom, China and Canada
operations. The United Kingdom operations were sold in the
fourth quarter of 2018.
|
(C) Dollars per
barrel or per thousand cubic feet, as applicable. Excludes
the impact of financial commodity derivative instruments (see Note
12 to the Consolidated Financial Statements in EOG's Annual Report
on Form 10-K for the year ended December 31, 2018).
|
(D) Includes positive
revenue adjustments of $0.49 per Mcf and $0.44 per Mcf for the
three and twelve months ended December 31, 2018, respectively,
related to the adoption of ASU 2014-09, "Revenue From Contracts
with Customers" (ASU 2014-09). (see Note 1 to the
Consolidated Financial Statements in EOG's Annual Report on Form
10-K for the year ended December 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 as 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)
|
|
|
|
|
|
|
|
December
31,
|
|
December
31,
|
|
2018
|
|
2017
|
ASSETS
|
Current
Assets
|
|
|
|
|
|
Cash and Cash
Equivalents
|
$
|
1,555,634
|
|
$
|
834,228
|
Accounts Receivable,
Net
|
|
1,915,215
|
|
|
1,597,494
|
Inventories
|
|
859,359
|
|
|
483,865
|
Assets from Price Risk
Management Activities
|
|
23,806
|
|
|
7,699
|
Income Taxes
Receivable
|
|
427,909
|
|
|
113,357
|
Other
|
|
275,467
|
|
|
242,465
|
Total
|
|
5,057,390
|
|
|
3,279,108
|
|
|
|
|
|
|
Property, Plant
and Equipment
|
|
|
|
|
|
Oil and Gas Properties
(Successful Efforts Method)
|
|
57,330,016
|
|
|
52,555,741
|
Other Property, Plant and
Equipment
|
|
4,220,665
|
|
|
3,960,759
|
Total Property, Plant and Equipment
|
|
61,550,681
|
|
|
56,516,500
|
Less: Accumulated
Depreciation, Depletion and Amortization
|
|
(33,475,162)
|
|
|
(30,851,463)
|
Total Property, Plant and Equipment, Net
|
|
28,075,519
|
|
|
25,665,037
|
Deferred Income
Taxes
|
|
777
|
|
|
17,506
|
Other
Assets
|
|
800,788
|
|
|
871,427
|
Total
Assets
|
$
|
33,934,474
|
|
$
|
29,833,078
|
|
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS' EQUITY
|
Current
Liabilities
|
|
|
|
|
|
Accounts Payable
|
$
|
2,239,850
|
|
$
|
1,847,131
|
Accrued Taxes
Payable
|
|
214,726
|
|
|
148,874
|
Dividends Payable
|
|
126,971
|
|
|
96,410
|
Liabilities from Price Risk
Management Activities
|
|
-
|
|
|
50,429
|
Current Portion of Long-Term
Debt
|
|
913,093
|
|
|
356,235
|
Other
|
|
233,724
|
|
|
226,463
|
Total
|
|
3,728,364
|
|
|
2,725,542
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term
Debt
|
|
5,170,169
|
|
|
6,030,836
|
Other
Liabilities
|
|
1,258,355
|
|
|
1,275,213
|
Deferred Income
Taxes
|
|
4,413,398
|
|
|
3,518,214
|
Commitments and
Contingencies
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders'
Equity
|
|
|
|
|
|
Common Stock, $0.01 Par,
1,280,000,000 Shares Authorized and
580,408,117 Shares and
578,827,768 Shares Issued at December 31, 2018
and 2017,
respectively.
|
|
205,804
|
|
|
205,788
|
Additional Paid in
Capital
|
|
5,658,794
|
|
|
5,536,547
|
Accumulated Other
Comprehensive Loss
|
|
(1,358)
|
|
|
(19,297)
|
Retained Earnings
|
|
13,543,130
|
|
|
10,593,533
|
Common Stock Held in
Treasury, 385,042 Shares and 350,961 Shares at
December 31, 2018 and
2017, respectively.
|
|
(42,182)
|
|
|
(33,298)
|
Total Stockholders' Equity
|
|
19,364,188
|
|
|
16,283,273
|
Total Liabilities
and Stockholders' Equity
|
$
|
33,934,474
|
|
$
|
29,833,078
|
EOG RESOURCES,
INC.
|
Summary Statements
of Cash Flows
|
(Unaudited; in
thousands)
|
|
|
|
|
|
|
|
Twelve Months
Ended
|
|
December
31,
|
|
2018
|
|
2017
|
Cash Flows from
Operating Activities
|
|
|
|
|
|
Reconciliation of Net
Income to Net Cash Provided by Operating Activities:
|
|
|
|
|
|
Net Income
|
$
|
3,419,040
|
|
$
|
2,582,579
|
Items Not Requiring
(Providing) Cash
|
|
|
|
|
|
Depreciation, Depletion and Amortization
|
|
3,435,408
|
|
|
3,409,387
|
Impairments
|
|
347,021
|
|
|
479,240
|
Stock-Based Compensation Expenses
|
|
155,337
|
|
|
133,849
|
Deferred Income Taxes
|
|
894,156
|
|
|
(1,473,872)
|
(Gains) Losses on Asset Dispositions, Net
|
|
(174,562)
|
|
|
99,096
|
Other, Net
|
|
7,066
|
|
|
6,546
|
Dry Hole Costs
|
|
5,405
|
|
|
4,609
|
Mark-to-Market Commodity
Derivative Contracts
|
|
|
|
|
|
Total (Gains) Losses
|
|
165,640
|
|
|
(19,828)
|
Net Cash Received from (Payments for) Settlements of Commodity
Derivative Contracts
|
|
(258,906)
|
|
|
7,438
|
Other, Net
|
|
3,108
|
|
|
1,204
|
Changes in Components of
Working Capital and Other Assets and Liabilities
|
|
|
|
|
|
Accounts Receivable
|
|
(368,180)
|
|
|
(392,131)
|
Inventories
|
|
(395,408)
|
|
|
(174,548)
|
Accounts Payable
|
|
439,347
|
|
|
324,192
|
Accrued Taxes Payable
|
|
(92,461)
|
|
|
(63,937)
|
Other Assets
|
|
(125,435)
|
|
|
(658,609)
|
Other Liabilities
|
|
10,949
|
|
|
(89,871)
|
Changes in Components of
Working Capital Associated with Investing and Financing
Activities
|
|
301,083
|
|
|
89,992
|
Net Cash Provided
by Operating Activities
|
|
7,768,608
|
|
|
4,265,336
|
|
|
|
|
|
|
Investing Cash
Flows
|
|
|
|
|
|
Additions to Oil and Gas
Properties
|
|
(5,839,294)
|
|
|
(3,950,918)
|
Additions to Other Property,
Plant and Equipment
|
|
(237,181)
|
|
|
(173,324)
|
Proceeds from Sales of
Assets
|
|
227,446
|
|
|
226,768
|
Other Investing
Activities
|
|
(19,993)
|
|
|
-
|
Changes in Components of
Working Capital Associated with Investing Activities
|
|
(301,140)
|
|
|
(89,935)
|
Net Cash Used in
Investing Activities
|
|
(6,170,162)
|
|
|
(3,987,409)
|
|
|
|
|
|
|
Financing Cash
Flows
|
|
|
|
|
|
Long-Term Debt
Repayments
|
|
(350,000)
|
|
|
(600,000)
|
Dividends Paid
|
|
(438,045)
|
|
|
(386,531)
|
Treasury Stock
Purchased
|
|
(63,456)
|
|
|
(63,408)
|
Proceeds from Stock Options
Exercised and Employee Stock Purchase Plan
|
|
20,560
|
|
|
20,840
|
Repayment of Capital Lease
Obligation
|
|
(8,219)
|
|
|
(6,555)
|
Changes in Components of
Working Capital Associated with Financing Activities
|
|
57
|
|
|
(57)
|
Net Cash Used in
Financing Activities
|
|
(839,103)
|
|
|
(1,035,711)
|
|
|
|
|
|
|
Effect of Exchange
Rate Changes on Cash
|
|
(37,937)
|
|
|
(7,883)
|
|
|
|
|
|
|
Increase
(Decrease) in Cash and Cash Equivalents
|
|
721,406
|
|
|
(765,667)
|
Cash and Cash
Equivalents at Beginning of Period
|
|
834,228
|
|
|
1,599,895
|
Cash and Cash
Equivalents at End of Period
|
$
|
1,555,634
|
|
$
|
834,228
|
EOG RESOURCES,
INC.
|
Fourth 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
|
42
|
|
37
|
|
7,000
|
|
1,950
|
|
600
|
|
3.7
|
|
3,150
|
Bone
Spring
|
13
|
|
11
|
|
5,300
|
|
1,550
|
|
300
|
|
1.9
|
|
2,150
|
Leonard
|
2
|
|
1
|
|
4,600
|
|
1,200
|
|
550
|
|
3.7
|
|
2,350
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South Texas Eagle
Ford
|
82
|
|
78
|
|
7,300
|
|
1,300
|
|
150
|
|
0.8
|
|
1,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South Texas Austin
Chalk
|
6
|
|
5
|
|
5,500
|
|
2,650
|
|
550
|
|
2.6
|
|
3,650
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Powder River
Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Turner
|
4
|
|
3
|
|
9,700
|
|
800
|
|
200
|
|
2.4
|
|
1,400
|
Mowry
|
2
|
|
2
|
|
9,200
|
|
700
|
|
450
|
|
5.5
|
|
2,050
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DJ Basin
Codell
|
20
|
|
10
|
|
9,600
|
|
700
|
|
50
|
|
0.3
|
|
800
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williston Basin
Bakken/Three Forks
|
7
|
|
5
|
|
10,100
|
|
550
|
|
25
|
|
0.1
|
|
600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Anadarko Basin
Woodford Oil Window
|
5
|
|
4
|
|
9,200
|
|
600
|
|
75
|
|
0.4
|
|
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.
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Adjusted Net Income (Non-GAAP)
|
To Net Income
(GAAP)
|
(Unaudited; in
thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following chart
adjusts the three-month and twelve-month periods ended December 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 (gains) losses
on asset dispositions in 2018 and 2017, to add back impairment
charges related to certain of EOG's assets in 2018 and 2017, to add
back an early lease termination payment as the result of a legal
settlement in 2017, to add back the transaction costs for the
formation of a joint venture in 2017, to add back certain joint
interest billings deemed uncollectible in 2017 and to eliminate
certain adjustments in 2018 and 2017 related to the 2017 U.S. tax
reform. EOG believes this presentation may be useful to
investors who follow the practice of some industry analysts who
adjust reported company earnings to match hedge realizations to
production settlement months and make certain other adjustments to
exclude non-recurring and certain other items. EOG management
uses this information for purposes of comparing its financial
performance with the financial performance of other companies in
the industry.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Three Months
Ended
|
|
December 31,
2018
|
|
December 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)
|
$
1,088,340
|
|
$
(195,572)
|
|
$
892,768
|
|
$
1.54
|
|
$
413,353
|
|
$
2,017,115
|
|
$
2,430,468
|
|
$
4.20
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Gains) Losses on
Mark-to-Market Commodity
Derivative Contracts
|
(132,095)
|
|
29,096
|
|
(102,999)
|
|
(0.18)
|
|
45,032
|
|
(16,142)
|
|
28,890
|
|
0.05
|
Net Cash Received
from (Payments for)
Settlements of Commodity Derivative
Contracts
|
(78,678)
|
|
17,330
|
|
(61,348)
|
|
(0.11)
|
|
2,708
|
|
(971)
|
|
1,737
|
|
-
|
Add: Net
(Gains) Losses on Asset Dispositions
|
(79,904)
|
|
13,625
|
|
(66,279)
|
|
(0.11)
|
|
65,220
|
|
(23,315)
|
|
41,905
|
|
0.07
|
Add:
Impairments
|
131,795
|
|
(29,031)
|
|
102,764
|
|
0.18
|
|
100,304
|
|
(35,954)
|
|
64,350
|
|
0.11
|
Add: Joint
Interest Billings Deemed Uncollectible
|
-
|
|
-
|
|
-
|
|
-
|
|
4,528
|
|
(1,623)
|
|
2,905
|
|
0.01
|
Less: Tax
Reform Impact
|
-
|
|
(46,684)
|
|
(46,684)
|
|
(0.08)
|
|
-
|
|
(2,169,376)
|
|
(2,169,376)
|
|
(3.75)
|
Adjustments to Net
Income
|
(158,882)
|
|
(15,664)
|
|
(174,546)
|
|
(0.30)
|
|
217,792
|
|
(2,247,381)
|
|
(2,029,589)
|
|
(3.51)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Net
Income (Non-GAAP)
|
$
929,458
|
|
$
(211,236)
|
|
$
718,222
|
|
$
1.24
|
|
$
631,145
|
|
$
(230,266)
|
|
$
400,879
|
|
$
0.69
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Number of
Common Shares (GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
577,035
|
|
|
|
|
|
|
|
575,394
|
Diluted
|
|
|
|
|
|
|
580,288
|
|
|
|
|
|
|
|
579,203
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve Months
Ended
|
|
Twelve Months
Ended
|
|
December 31,
2018
|
|
December 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)
|
$
4,240,998
|
|
$
(821,958)
|
|
$
3,419,040
|
|
$
5.89
|
|
$
661,182
|
|
$
1,921,397
|
|
$
2,582,579
|
|
$
4.46
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Gains) Losses on
Mark-to-Market Commodity
Derivative Contracts
|
165,640
|
|
(36,486)
|
|
129,154
|
|
0.22
|
|
(19,828)
|
|
7,107
|
|
(12,721)
|
|
(0.02)
|
Net Cash Received
from (Payments for)
Settlements of Commodity Derivative
Contracts
|
(258,906)
|
|
57,029
|
|
(201,877)
|
|
(0.35)
|
|
7,438
|
|
(2,666)
|
|
4,772
|
|
0.01
|
Add: Net
(Gains) Losses on Asset Dispositions
|
(174,562)
|
|
37,860
|
|
(136,702)
|
|
(0.24)
|
|
99,096
|
|
(35,270)
|
|
63,826
|
|
0.11
|
Add:
Impairments
|
152,671
|
|
(33,629)
|
|
119,042
|
|
0.21
|
|
261,452
|
|
(93,718)
|
|
167,734
|
|
0.29
|
Add: Legal
Settlement - Early Lease Termination
|
-
|
|
-
|
|
-
|
|
-
|
|
10,202
|
|
(3,657)
|
|
6,545
|
|
0.01
|
Add: Joint
Venture Transaction Costs
|
-
|
|
-
|
|
-
|
|
-
|
|
3,056
|
|
(1,095)
|
|
1,961
|
|
-
|
Add: Joint
Interest Billings Deemed Uncollectible
|
-
|
|
-
|
|
-
|
|
-
|
|
4,528
|
|
(1,623)
|
|
2,905
|
|
0.01
|
Less: Tax
Reform Impact
|
-
|
|
(110,335)
|
|
(110,335)
|
|
(0.19)
|
|
-
|
|
(2,169,376)
|
|
(2,169,376)
|
|
(3.75)
|
Adjustments to Net
Income
|
(115,157)
|
|
(85,561)
|
|
(200,718)
|
|
(0.35)
|
|
365,944
|
|
(2,300,298)
|
|
(1,934,354)
|
|
(3.34)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Net
Income (Non-GAAP)
|
$
4,125,841
|
|
$
(907,519)
|
|
$
3,218,322
|
|
$
5.54
|
|
$
1,027,126
|
|
$
(378,901)
|
|
$
648,225
|
|
$
1.12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Number of
Common Shares (GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
576,578
|
|
|
|
|
|
|
|
574,620
|
Diluted
|
|
|
|
|
|
|
580,441
|
|
|
|
|
|
|
|
578,693
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Discretionary Cash Flow (Non-GAAP)
|
To Net Cash
Provided by Operating Activities (GAAP)
|
(Unaudited; in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Calculation of
Free Cash Flow (Non-GAAP)
|
(Unaudited; in
thousands)
|
|
|
|
|
|
|
|
The following chart
reconciles the three-month and twelve-month periods ended December
31, 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 (Payable), 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 and twelve months ended December 31, 2018. EOG
management uses this information for comparative purposes within
the industry.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Twelve Months
Ended
|
|
December
31,
|
|
December
31,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by
Operating Activities (GAAP)
|
$
|
2,085,228
|
|
$
|
1,327,548
|
|
$
|
7,768,608
|
|
$
|
4,265,336
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
Exploration Costs
(excluding Stock-Based Compensation Expenses)
|
|
27,270
|
|
|
16,420
|
|
|
123,986
|
|
|
122,688
|
Other Non-Current
Income Taxes - Net Receivable (Payable)
|
|
86,572
|
|
|
(513,404)
|
|
|
148,993
|
|
|
(513,404)
|
Changes in Components
of Working Capital and Other Assets
|
|
|
|
|
|
|
|
|
|
|
|
and
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
Receivable
|
|
(185,349)
|
|
|
366,686
|
|
|
368,180
|
|
|
392,131
|
Inventories
|
|
108,591
|
|
|
156,874
|
|
|
395,408
|
|
|
174,548
|
Accounts
Payable
|
|
98,178
|
|
|
(211,298)
|
|
|
(439,347)
|
|
|
(324,192)
|
Accrued Taxes
Payable
|
|
55,570
|
|
|
13,970
|
|
|
92,461
|
|
|
63,937
|
Other
Assets
|
|
22,101
|
|
|
574,669
|
|
|
125,435
|
|
|
658,609
|
Other
Liabilities
|
|
(25,725)
|
|
|
20,647
|
|
|
(10,949)
|
|
|
89,871
|
Changes in Components
of Working Capital Associated with
|
|
|
|
|
|
|
|
|
|
|
|
Investing and
Financing Activities
|
|
(205,599)
|
|
|
(210,365)
|
|
|
(301,083)
|
|
|
(89,992)
|
|
|
|
|
|
|
|
Discretionary Cash
Flow (Non-GAAP)
|
$
|
2,066,837
|
|
$
|
1,541,747
|
|
$
|
8,271,692
|
|
$
|
4,839,532
|
|
|
|
|
|
|
|
|
|
|
|
|
Discretionary Cash
Flow (Non-GAAP) - Percentage Increase
|
|
34%
|
|
|
|
|
|
71%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discretionary Cash
Flow (Non-GAAP)
|
$
|
2,066,837
|
|
|
|
|
$
|
8,271,692
|
|
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
Total Cash
Expenditures Excluding Acquisitions
(Non-GAAP)(a)
|
|
(1,302,999)
|
|
|
|
|
|
(6,172,950)
|
|
|
|
Dividends Paid
(GAAP)
|
|
(126,970)
|
|
|
|
|
|
(438,045)
|
|
|
|
Free Cash Flow
(Non-GAAP)
|
$
|
636,868
|
|
|
|
|
$
|
1,660,697
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) See below
reconciliation of Total Expenditures (GAAP) to Total Cash
Expenditures Excluding Acquisitions (Non-GAAP) for the three months
and twelve months ended December 31, 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Expenditures
(GAAP)
|
$
|
1,504,438
|
|
|
|
|
$
|
6,706,359
|
|
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
Asset Retirement Costs
|
|
(27,910)
|
|
|
|
|
|
(69,699)
|
|
|
|
Non-Cash Expenditures of Other Property, Plant and
Equipment
|
|
(547)
|
|
|
|
|
|
(49,484)
|
|
|
|
Non-Cash Acquisition Costs of Unproved Properties
|
|
(128,719)
|
|
|
|
|
|
(290,542)
|
|
|
|
Acquisition Costs of Proved Properties
|
|
(44,263)
|
|
|
|
|
|
(123,684)
|
|
|
|
Total Cash
Expenditures Excluding Acquisitions (Non-GAAP)
|
$
|
1,302,999
|
|
|
|
|
$
|
6,172,950
|
|
|
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Adjusted Earnings Before Interest Expense,
Net,
|
Income Taxes,
Depreciation, Depletion and Amortization, Exploration
Costs,
|
Dry Hole Costs,
Impairments and Additional Items (Adjusted EBITDAX)
|
(Non-GAAP)
to Net Income (GAAP)
|
(Unaudited; in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
The following chart
adjusts the three-month and twelve-month periods ended December 31,
2018 and 2017 reported Net Income (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 (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 (GAAP) to add back Interest
Expense (Net), Income Taxes (Income Tax Provision (Benefit)),
Depreciation, Depletion and Amortization, Exploration Costs, Dry
Hole Costs and Impairments and further adjust such amount to match
realizations to production settlement months and make certain other
adjustments to exclude non-recurring and certain other items.
EOG management uses this information for purposes of comparing its
financial performance with the financial performance of other
companies in the industry.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Twelve Months
Ended
|
|
December
31,
|
|
December
31,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
(GAAP)
|
$
|
892,768
|
|
$
|
2,430,468
|
|
$
|
3,419,040
|
|
$
|
2,582,579
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense,
Net
|
|
56,020
|
|
|
63,362
|
|
|
245,052
|
|
|
274,372
|
Income Tax Provision
(Benefit)
|
|
195,572
|
|
|
(2,017,115)
|
|
|
821,958
|
|
|
(1,921,397)
|
Depreciation, Depletion and
Amortization
|
|
919,963
|
|
|
881,745
|
|
|
3,435,408
|
|
|
3,409,387
|
Exploration Costs
|
|
33,862
|
|
|
22,941
|
|
|
148,999
|
|
|
145,342
|
Dry Hole Costs
|
|
145
|
|
|
4,532
|
|
|
5,405
|
|
|
4,609
|
Impairments
|
|
186,087
|
|
|
153,442
|
|
|
347,021
|
|
|
479,240
|
EBITDAX (Non-GAAP)
|
|
2,284,417
|
|
|
1,539,375
|
|
|
8,422,883
|
|
|
4,974,132
|
Total (Gains) Losses on MTM
Commodity Derivative Contracts
|
|
(132,095)
|
|
|
45,032
|
|
|
165,640
|
|
|
(19,828)
|
Net Cash Received from
(Payments for) Settlements of Commodity
Derivative
Contracts
|
|
(78,678)
|
|
|
2,708
|
|
|
(258,906)
|
|
|
7,438
|
(Gains) Losses on Asset
Dispositions, Net
|
|
(79,904)
|
|
|
65,220
|
|
|
(174,562)
|
|
|
99,096
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX
(Non-GAAP)
|
$
|
1,993,740
|
|
$
|
1,652,335
|
|
$
|
8,155,055
|
|
$
|
5,060,838
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX
(Non-GAAP) - Percentage Increase
|
|
21%
|
|
|
|
|
|
61%
|
|
|
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Net Debt (Non-GAAP) and Total
|
Capitalization
(Non-GAAP) as Used in the Calculation of
|
The Net
Debt-to-Total Capitalization Ratio (Non-GAAP) to
|
Current and
Long-Term Debt (GAAP) and Total Capitalization
(GAAP)
|
(Unaudited; in
millions, except ratio data)
|
|
|
|
|
|
|
The following chart
reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP)
and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP),
as used in the Net Debt-to-Total Capitalization ratio
calculation. A portion of the cash is associated with
international subsidiaries; tax considerations may impact debt
paydown. EOG believes this presentation may be useful to
investors who follow the practice of some industry analysts who
utilize Net Debt and Total Capitalization (Non-GAAP) in their Net
Debt-to-Total Capitalization ratio calculation. EOG
management uses this information for comparative purposes within
the industry.
|
|
|
|
|
|
|
|
At
|
|
At
|
|
December
31,
|
|
December
31,
|
|
2018
|
|
2017
|
|
|
|
|
|
|
Total Stockholders'
Equity - (a)
|
$
|
19,364
|
|
$
|
16,283
|
|
|
|
|
|
|
Current and Long-Term
Debt (GAAP) - (b)
|
|
6,083
|
|
|
6,387
|
Less:
Cash
|
|
(1,556)
|
|
|
(834)
|
Net Debt (Non-GAAP) -
(c)
|
|
4,527
|
|
|
5,553
|
|
|
|
|
|
|
Total Capitalization
(GAAP) - (a) + (b)
|
$
|
25,447
|
|
$
|
22,670
|
|
|
|
|
|
|
Total Capitalization
(Non-GAAP) - (a) + (c)
|
$
|
23,891
|
|
$
|
21,836
|
|
|
|
|
|
|
Debt-to-Total
Capitalization (GAAP) - (b) / [(a) + (b)]
|
|
24%
|
|
|
28%
|
|
|
|
|
|
|
Net Debt-to-Total
Capitalization (Non-GAAP) - (c) / [(a) + (c)]
|
|
19%
|
|
|
25%
|
EOG RESOURCES,
INC.
|
Reserves
Supplemental Data
|
(Unaudited)
|
|
|
|
|
|
|
|
|
2018 NET PROVED
RESERVES RECONCILIATION SUMMARY
|
|
United
|
|
|
|
Other
|
|
|
|
States
|
|
Trinidad
|
|
International
|
|
Total
|
CRUDE OIL AND
CONDENSATE (MMBbl)
|
|
|
|
|
|
|
|
Beginning
Reserves
|
1,304.1
|
|
0.9
|
|
8.0
|
|
1,313.0
|
Revisions
|
(13.2)
|
|
(0.2)
|
|
-
|
|
(13.4)
|
Purchases in
Place
|
2.7
|
|
-
|
|
-
|
|
2.7
|
Extensions,
Discoveries and Other Additions
|
383.0
|
|
-
|
|
-
|
|
383.0
|
Sales in
Place
|
(0.8)
|
|
-
|
|
(6.3)
|
|
(7.1)
|
Production
|
(144.1)
|
|
(0.3)
|
|
(1.5)
|
|
(145.9)
|
Ending
Reserves
|
1,531.7
|
|
0.4
|
|
0.2
|
|
1,532.3
|
|
NATURAL GAS
LIQUIDS (MMBbl)
|
|
|
|
|
|
|
|
Beginning
Reserves
|
503.5
|
|
-
|
|
-
|
|
503.5
|
Revisions
|
23.9
|
|
-
|
|
-
|
|
23.9
|
Purchases in
Place
|
2.0
|
|
-
|
|
-
|
|
2.0
|
Extensions,
Discoveries and Other Additions
|
127.4
|
|
-
|
|
-
|
|
127.4
|
Sales in
Place
|
-
|
|
-
|
|
-
|
|
-
|
Production
|
(42.5)
|
|
-
|
|
-
|
|
(42.5)
|
Ending
Reserves
|
614.3
|
|
-
|
|
-
|
|
614.3
|
|
NATURAL GAS
(Bcf)
|
|
|
|
|
|
|
|
Beginning
Reserves
|
3,898.5
|
|
313.4
|
|
51.2
|
|
4,263.1
|
Revisions
|
(127.2)
|
|
20.7
|
|
15.0
|
|
(91.5)
|
Purchases in
Place
|
41.3
|
|
-
|
|
-
|
|
41.3
|
Extensions,
Discoveries and Other Additions
|
951.4
|
|
-
|
|
4.6
|
|
956.0
|
Sales in
Place
|
(22.2)
|
|
-
|
|
-
|
|
(22.2)
|
Production
|
(351.2)
|
|
(97.1)
|
|
(11.2)
|
|
(459.5)
|
Ending
Reserves
|
4,390.6
|
|
237.0
|
|
59.6
|
|
4,687.2
|
|
OIL EQUIVALENTS
(MMBoe)
|
|
|
|
|
|
|
|
Beginning
Reserves
|
2,457.3
|
|
53.1
|
|
16.6
|
|
2,527.0
|
Revisions
|
(10.5)
|
|
3.3
|
|
2.5
|
|
(4.7)
|
Purchases in
Place
|
11.6
|
|
-
|
|
-
|
|
11.6
|
Extensions,
Discoveries and Other Additions
|
669.0
|
|
-
|
|
0.7
|
|
669.7
|
Sales in
Place
|
(4.5)
|
|
-
|
|
(6.3)
|
|
(10.8)
|
Production
|
(245.1)
|
|
(16.5)
|
|
(3.4)
|
|
(265.0)
|
Ending
Reserves
|
2,877.8
|
|
39.9
|
|
10.1
|
|
2,927.8
|
|
Net Proved
Developed Reserves (MMBoe)
|
|
|
|
|
|
|
|
At December 31,
2017
|
1,300.7
|
|
50.8
|
|
12.8
|
|
1,364.3
|
At December 31,
2018
|
1,503.4
|
|
37.7
|
|
7.0
|
|
1,548.1
|
|
2018 EXPLORATION
AND DEVELOPMENT EXPENDITURES ($ Millions)
|
|
United
|
|
|
|
Other
|
|
|
|
States
|
|
Trinidad
|
|
International
|
|
Total
|
|
Acquisition Cost of
Unproved Properties
|
$
486.0
|
|
$
1.3
|
|
$
-
|
|
$
487.3
|
Exploration
Costs
|
157.2
|
|
22.5
|
|
13.9
|
|
193.6
|
Development
Costs
|
5,515.4
|
|
(0.8)
|
|
30.8
|
|
5,545.4
|
Total
Drilling
|
6,158.6
|
|
23.0
|
|
44.7
|
|
6,226.3
|
Acquisition Cost of
Proved Properties
|
123.7
|
|
-
|
|
-
|
|
123.7
|
Asset Retirement
Costs
|
90.0
|
|
(12.1)
|
|
(8.2)
|
|
69.7
|
Total Exploration
and Development Expenditures
|
6,372.3
|
|
10.9
|
|
36.5
|
|
6,419.7
|
Gathering, Processing
and Other
|
286.0
|
|
0.4
|
|
0.3
|
|
286.7
|
Total
Expenditures
|
6,658.3
|
|
11.3
|
|
36.8
|
|
6,706.4
|
Proceeds from Sales
in Place
|
(53.3)
|
|
-
|
|
(174.1)
|
|
(227.4)
|
Net
Expenditures
|
$
6,605.0
|
|
$
11.3
|
|
$
(137.3)
|
|
$
6,479.0
|
|
RESERVE
REPLACEMENT COSTS ($ / Boe ) *
|
|
|
|
|
|
|
|
All-in Total, Net
of Revisions
|
$
8.84
|
|
$
6.97
|
|
$
13.97
|
|
$
8.85
|
All-in Total,
Excluding Revisions Due to Price
|
$
9.32
|
|
$
6.97
|
|
$
13.97
|
|
$
9.33
|
|
RESERVE
REPLACEMENT *
|
|
|
|
|
|
|
|
Drilling
Only
|
273%
|
|
0%
|
|
21%
|
|
253%
|
All-in Total, Net
of Revisions and Dispositions
|
272%
|
|
20%
|
|
-91%
|
|
251%
|
All-in Total,
Excluding Revisions Due to Price
|
257%
|
|
20%
|
|
-91%
|
|
238%
|
All-in Total,
Liquids
|
281%
|
|
-67%
|
|
-420%
|
|
275%
|
|
* See
attached reconciliation schedule for calculation
methodology
|
|
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Total Exploration and Development Expenditures
(Non-GAAP)
|
As Used in the
Calculation of Reserve Replacement Costs ($ / BOE)
|
To Total Costs
Incurred in Exploration and Development Activities
(GAAP)
|
(Unaudited; in
millions, except ratio data)
|
|
|
|
|
|
|
|
|
The following chart
reconciles Total Costs Incurred in Exploration and Development
Activities (GAAP) to Total Exploration and Development Expenditures
for Drilling Only (Non-GAAP) and Total Exploration and Development
Expenditures (Non-GAAP), as used in the calculation of Reserve
Replacement Costs per Boe. There are numerous ways that
industry participants present Reserve Replacement Costs, including
"Drilling Only" and "All-In", which reflect total exploration and
development expenditures divided by total net proved reserve
additions from extensions and discoveries only, or from all
sources. Combined with Reserve Replacement, these statistics
provide management and investors with an indication of the results
of the current year capital investment program. Reserve
Replacement Cost statistics are widely recognized and reported by
industry participants and are used by EOG management and other
third parties for comparative purposes within the industry.
Please note that the actual cost of adding reserves will vary from
the reported statistics due to timing differences in reserve
bookings and capital expenditures. Accordingly, some analysts
use three or five year averages of reported statistics, while
others prefer to estimate future costs. EOG has not included
future capital costs to develop proved undeveloped reserves in
exploration and development expenditures.
|
|
|
|
|
|
|
|
|
For the Twelve
Months Ended December 31, 2018
|
|
|
|
|
|
|
|
|
United
|
|
|
|
Other
|
|
|
|
States
|
|
Trinidad
|
|
International
|
|
Total
|
|
Total Costs Incurred
in Exploration and Development Activities (GAAP)
|
$
6,372.3
|
|
$
10.9
|
|
$
36.5
|
|
$
6,419.7
|
Less: Asset
Retirement Costs
|
(90.0)
|
|
12.1
|
|
8.2
|
|
(69.7)
|
Non-Cash Acquisition Costs of Unproved Properties
|
(290.5)
|
|
-
|
|
-
|
|
(290.5)
|
Total Acquisition Costs of Proved Properties
|
(123.7)
|
|
-
|
|
-
|
|
(123.7)
|
|
Total Exploration
and Development Expenditures (Non-GAAP) (a)
|
$
5,868.1
|
|
$
23.0
|
|
$
44.7
|
|
$
5,935.8
|
|
Total Costs Incurred
in Exploration and Development Activities (GAAP)
|
$
6,372.3
|
|
$
10.9
|
|
$
36.5
|
|
$
6,419.7
|
Less: Asset
Retirement Costs
|
(90.0)
|
|
12.1
|
|
8.2
|
|
(69.7)
|
Non-Cash Acquisition Costs of Unproved Properties
|
(290.5)
|
|
-
|
|
-
|
|
(290.5)
|
Non-Cash Acquisition Costs of Proved Properties
|
(70.9)
|
|
-
|
|
-
|
|
(70.9)
|
|
Total Exploration
and Development Expenditures (Non-GAAP) (b)
|
$
5,920.9
|
|
$
23.0
|
|
$
44.7
|
|
$
5,988.6
|
|
|
|
|
|
|
|
|
Total Expenditures
(GAAP)
|
$
6,658.3
|
|
$
11.3
|
|
$
36.8
|
|
$
6,706.4
|
Less: Asset
Retirement Costs
|
(90.0)
|
|
12.1
|
|
8.2
|
|
(69.7)
|
Non-Cash Acquisition Costs of Unproved Properties
|
(290.5)
|
|
-
|
|
-
|
|
(290.5)
|
Non-Cash Acquisition Costs of Proved Properties
|
(70.9)
|
|
-
|
|
-
|
|
(70.9)
|
Non-Cash Capital - Other Miscellaneous
|
(49.5)
|
|
-
|
|
-
|
|
(49.5)
|
Total Cash
Expenditures (Non-GAAP)
|
$
6,157.4
|
|
$
23.4
|
|
$
45.0
|
|
$
6,225.8
|
|
Net Proved Reserve
Additions From All Sources - Oil Equivalents
(MMBoe)
|
|
|
|
|
|
|
|
Revisions Due to
Price (c)
|
34.8
|
|
-
|
|
-
|
|
34.8
|
Revisions Other Than
Price
|
(45.3)
|
|
3.3
|
|
2.5
|
|
(39.5)
|
Purchases in
Place
|
11.6
|
|
-
|
|
-
|
|
11.6
|
Extensions,
Discoveries and Other Additions (d)
|
669.0
|
|
-
|
|
0.7
|
|
669.7
|
Total Proved
Reserve Additions (e)
|
670.1
|
|
3.3
|
|
3.2
|
|
676.6
|
Sales in
Place
|
(4.5)
|
|
-
|
|
(6.3)
|
|
(10.8)
|
Net Proved Reserve
Additions From All Sources (f)
|
665.6
|
|
3.3
|
|
(3.1)
|
|
665.8
|
|
Production
(g)
|
245.1
|
|
16.5
|
|
3.4
|
|
265.0
|
|
RESERVE
REPLACEMENT COSTS ($ / Boe)
|
|
|
|
|
|
|
|
Total Drilling,
Before Revisions (a / d)
|
$
8.77
|
|
$
-
|
|
$
63.86
|
|
$
8.86
|
All-in Total, Net
of Revisions (b / e)
|
$
8.84
|
|
$
6.97
|
|
$
13.97
|
|
$
8.85
|
All-in Total,
Excluding Revisions Due to Price (b / (e - c))
|
$
9.32
|
|
$
6.97
|
|
$
13.97
|
|
$
9.33
|
|
RESERVE
REPLACEMENT
|
|
|
|
|
|
|
|
Drilling Only (d /
g)
|
273%
|
|
0%
|
|
21%
|
|
253%
|
All-in Total, Net
of Revisions and Dispositions (f / g)
|
272%
|
|
20%
|
|
-91%
|
|
251%
|
All-in Total,
Excluding Revisions Due to Price ((f - c ) /
g)
|
257%
|
|
20%
|
|
-91%
|
|
238%
|
|
Net Proved Reserve
Additions From All Sources - Liquids (MMBbl)
|
|
|
|
|
|
|
|
Revisions
|
10.7
|
|
(0.2)
|
|
-
|
|
10.5
|
Purchases in
Place
|
4.7
|
|
-
|
|
-
|
|
4.7
|
Extensions,
Discoveries and Other Additions (h)
|
510.4
|
|
-
|
|
-
|
|
510.4
|
Total Proved
Reserve Additions
|
525.8
|
|
(0.2)
|
|
-
|
|
525.6
|
Sales in
Place
|
(0.8)
|
|
-
|
|
(6.3)
|
|
(7.1)
|
Net Proved Reserve
Additions From All Sources (i)
|
525.0
|
|
(0.2)
|
|
(6.3)
|
|
518.5
|
|
Production
(j)
|
186.6
|
|
0.3
|
|
1.5
|
|
188.4
|
|
RESERVE
REPLACEMENT - LIQUIDS
|
|
|
|
|
|
|
|
Drilling Only (h /
j)
|
274%
|
|
0%
|
|
0%
|
|
271%
|
All-in Total, Net
of Revisions and Dispositions (i / j)
|
281%
|
|
-67%
|
|
-420%
|
|
275%
|
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Drillbit Exploration and Development Expenditures
(Non-GAAP)
|
As Used in the
Calculation of Proved Developed Reserve Replacement Costs ($ /
BOE)
|
To Total Costs
Incurred in Exploration and Development Activities
(GAAP)
|
(Unaudited; in
millions, except ratio data)
|
|
|
|
|
|
|
|
|
The following chart
reconciles Total Costs Incurred in Exploration and Development
Activities (GAAP) to Drillbit Exploration and Development
Expenditures (Non-GAAP), as used in the calculation of Proved
Developed Reserve Replacement Costs per Boe. These statistics
provide management and investors with an indication of the results
of the current year capital investment program. Reserve
Replacement Cost statistics are widely recognized and reported by
industry participants and are used by EOG management and other
third parties for comparative purposes within the
industry.
|
|
|
For the Twelve
Months Ended December 31, 2018
|
|
|
Total
|
PROVED DEVELOPED
RESERVE REPLACEMENT COSTS ($ / Boe)
|
|
Total Costs Incurred
in Exploration and Development Activities (GAAP)
|
$
6,419.7
|
Less: Asset
Retirement Costs
|
(69.7)
|
Acquisition Costs of Unproved Properties
|
(487.3)
|
Acquisition Costs of Proved Properties
|
(123.7)
|
Drillbit
Exploration and Development Expenditures (Non-GAAP)
(j)
|
$
5,739.0
|
|
|
Total Proved Reserves
- Extensions, Discoveries and Other Additions (MMBoe)
|
669.7
|
Add:
Conversion of Proved Undeveloped Reserves to Proved
Developed
|
265.7
|
Less: Proved
Undeveloped Extensions and Discoveries
|
(490.7)
|
Proved Developed
Reserves - Extensions and Discoveries (MMBoe)
|
444.7
|
|
|
Total Proved Reserves
- Revisions (MMBoe)
|
(4.7)
|
Less: Proved
Undeveloped Reserves - Revisions
|
8.2
|
Proved Developed - Revisions Due to Price
|
(31.8)
|
Proved Developed
Reserves - Revisions Other Than Price (MMBoe)
|
(28.3)
|
|
|
Proved Developed
Reserves - Extensions and Discoveries plus Revisions Other than
Price (MMBoe) (k)
|
416.4
|
|
|
Proved Developed
Reserve Replacement Cost Excluding Revisions Due to Price ($ / Boe)
(j / k)
|
$
13.78
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Total Exploration and Development
Expenditures
|
For Drilling Only
(Non-GAAP) and Total Exploration and Development Expenditures
(Non-GAAP)
|
As Used in the
Calculation of Reserve Replacement Costs ($ / BOE)
|
To Total Costs
Incurred in Exploration and Development Activities
(GAAP)
|
(Unaudited; in
millions, except ratio data)
|
|
|
|
|
|
|
|
|
|
|
The following chart
reconciles Total Costs Incurred in Exploration and Development
Activities (GAAP) to Total Exploration and Development Expenditures
for Drilling Only (Non-GAAP) and Total Exploration and Development
Expenditures (Non-GAAP), as used in the calculation of Reserve
Replacement Costs per Boe. There are numerous ways that
industry participants present Reserve Replacement Costs, including
"Drilling Only" and "All-In", which reflect total exploration and
development expenditures divided by total net proved reserve
additions from extensions and discoveries only, or from all
sources. Combined with Reserve Replacement, these statistics
provide management and investors with an indication of the results
of the current year capital investment program. Reserve
Replacement Cost statistics are widely recognized and reported by
industry participants and are used by EOG management and other
third parties for comparative purposes within the industry.
Please note that the actual cost of adding reserves will vary from
the reported statistics due to timing differences in reserve
bookings and capital expenditures. Accordingly, some analysts
use three or five year averages of reported statistics, while
others prefer to estimate future costs. EOG has not included
future capital costs to develop proved undeveloped reserves in
exploration and development expenditures.
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
|
|
|
|
Total Costs Incurred
in Exploration and Development Activities (GAAP)
|
$
6,419.7
|
|
$
4,439.4
|
|
$
6,445.2
|
|
$
4,928.3
|
|
$
7,904.8
|
Less: Asset
Retirement Costs
|
(69.7)
|
|
(55.6)
|
|
19.9
|
|
(53.5)
|
|
(195.6)
|
Non-Cash Acquisition Costs of Unproved Properties
|
(290.5)
|
|
(255.7)
|
|
(3,101.8)
|
|
-
|
|
-
|
Acquisition Costs of Proved Properties
|
(123.7)
|
|
(72.6)
|
|
(749.0)
|
|
(480.6)
|
|
(139.1)
|
Total Exploration
and Development Expenditures for Drilling Only (Non-GAAP)
(a)
|
$
5,935.8
|
|
$
4,055.5
|
|
$
2,614.3
|
|
$
4,394.2
|
|
$
7,570.1
|
|
|
|
|
|
|
|
|
|
|
Total Costs Incurred
in Exploration and Development Activities (GAAP)
|
$
6,419.7
|
|
$
4,439.4
|
|
$
6,445.2
|
|
$
4,928.3
|
|
$
7,904.8
|
Less: Asset
Retirement Costs
|
(69.7)
|
|
(55.6)
|
|
19.9
|
|
(53.5)
|
|
(195.6)
|
Non-Cash Acquisition Costs of Unproved Properties
|
(290.5)
|
|
(255.7)
|
|
(3,101.8)
|
|
-
|
|
-
|
Non-Cash Acquisition Costs of Proved Properties
|
(70.9)
|
|
(26.2)
|
|
(732.3)
|
|
-
|
|
-
|
Total Exploration
and Development Expenditures (Non-GAAP) (b)
|
$
5,988.6
|
|
$
4,101.9
|
|
$
2,631.0
|
|
$
4,874.8
|
|
$
7,709.2
|
|
|
|
|
|
|
|
|
|
|
Net Proved Reserve
Additions From All Sources - Oil Equivalents
(MMBoe)
|
|
|
|
|
|
|
|
|
|
Revisions Due to
Price (c)
|
34.8
|
|
154.0
|
|
(100.7)
|
|
(573.8)
|
|
52.2
|
Revisions Other Than
Price
|
(39.5)
|
|
48.0
|
|
252.9
|
|
107.2
|
|
48.4
|
Purchases in
Place
|
11.6
|
|
2.3
|
|
42.3
|
|
56.2
|
|
14.4
|
Extensions,
Discoveries and Other Additions (d)
|
669.7
|
|
420.8
|
|
209.0
|
|
245.9
|
|
519.2
|
Total Proved
Reserve Additions (e)
|
676.6
|
|
625.1
|
|
403.5
|
|
(164.5)
|
|
634.2
|
Sales in
Place
|
(10.8)
|
|
(20.7)
|
|
(167.6)
|
|
(3.5)
|
|
(36.3)
|
Net Proved Reserve
Additions From All Sources (f)
|
665.8
|
|
604.4
|
|
235.9
|
|
(168.0)
|
|
597.9
|
|
|
|
|
|
|
|
|
|
|
Production
(g)
|
265.0
|
|
224.4
|
|
207.1
|
|
211.2
|
|
219.1
|
|
|
|
|
|
|
|
|
|
|
RESERVE
REPLACEMENT COSTS ($ / Boe)
|
|
|
|
|
|
|
|
|
|
Total Drilling,
Before Revisions (a / d)
|
$
8.86
|
|
$
9.64
|
|
$
12.51
|
|
$
17.87
|
|
$
14.58
|
All-in Total, Net
of Revisions (b / e)
|
$
8.85
|
|
$
6.56
|
|
$
6.52
|
|
$
(29.63)
|
|
$
12.16
|
All-in Total,
Excluding Revisions Due to Price (b / (e - c))
|
$
9.33
|
|
$
8.71
|
|
$
5.22
|
|
$
11.91
|
|
$
13.25
|
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 February 19, 2019. 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 December 31, 2018 (closed)
|
|
|
|
|
15,000
|
|
$
1.063
|
|
|
|
|
|
|
|
|
|
2019
|
|
|
|
|
|
|
|
|
January 1, 2019
through February 28, 2019 (closed)
|
|
|
|
|
20,000
|
|
$
1.075
|
March 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 February 19, 2019. 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 September 30, 2018 (closed)
|
|
|
|
|
37,000
|
|
$
3.818
|
October 1, 2018
through December 31, 2018 (closed)
|
|
|
|
|
52,000
|
|
3.911
|
|
|
|
|
|
|
|
|
|
2019
|
|
|
|
|
|
|
|
|
January 1, 2019
through February 28, 2019 (closed)
|
|
|
|
|
13,000
|
|
$
5.572
|
March 1, 2019 through
December 31, 2019
|
|
|
|
|
13,000
|
|
5.572
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Presented below is a
comprehensive summary of EOG's crude oil price swap contracts
through February 19, 2019, 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 November 30, 2018 (closed)
|
|
|
|
|
134,000
|
|
$
60.04
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
On November 20, 2018,
EOG entered into crude oil price swap contracts for the period
December 1, 2018 through December 31, 2018, with notional volumes
of 134,000 Bbld at an average price of $53.75 per Bbl. These
contracts offset the crude oil price swap contracts for the same
time period with notional volumes of 134,000 Bbld at an average
price of $60.04 per Bbl. The net cash EOG received for
settling these contracts was $26.1 million. The offsetting
contracts are excluded from the above table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Presented below is a
comprehensive summary of EOG's natural gas price swap contracts
through February 19, 2019, 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
November 30, 2018 (closed)
|
|
|
|
|
35,000
|
|
$
3.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EOG has sold call
options which establish a ceiling price for the sale of notional
volumes of natural gas as specified in the call option
contracts. The call options require that EOG pay the
difference between the call option strike price and either the
average or last business day NYMEX Henry Hub natural gas price for
the contract month (Henry Hub Index Price) in the event the Henry
Hub Index Price is above the call option strike
price.
|
|
|
|
|
|
|
|
|
|
In addition, EOG has
purchased put options which establish a floor price for the sale of
notional volumes of natural gas as specified in the put option
contracts. The put options grant EOG the right to receive the
difference between the put option strike price and the Henry Hub
Index Price in the event the Henry Hub Index Price is below the put
option strike price. Presented below is a comprehensive
summary of EOG's natural gas call and put option contracts through
February 19, 2019, 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
November 30, 2018 (closed)
|
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 (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
|
(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 (GAAP), Current
and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to
After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income
(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, 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.
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
2017
|
|
|
|
Return on Capital
Employed (ROCE) (Non-GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Interest Expense
(GAAP)
|
$
|
245
|
|
|
|
|
|
|
Tax Benefit Imputed
(based on 21%)
|
|
(51)
|
|
|
|
|
|
|
After-Tax Net
Interest Expense (Non-GAAP) - (a)
|
$
|
194
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (GAAP) -
(b)
|
$
|
3,419
|
|
|
|
|
|
|
Adjustments to Net
Income, Net of Tax (See Accompanying Schedule)
|
|
(201)
|
(1)
|
|
|
|
|
|
Adjusted Net Income
(Non-GAAP) - (c)
|
$
|
3,218
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Stockholders'
Equity - (d)
|
$
|
19,364
|
|
$
|
16,283
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Total
Stockholders' Equity * - (e)
|
$
|
17,824
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current and Long-Term
Debt (GAAP) - (f)
|
$
|
6,083
|
|
$
|
6,387
|
|
|
|
Less:
Cash
|
|
(1,556)
|
|
|
(834)
|
|
|
|
Net Debt (Non-GAAP) -
(g)
|
$
|
4,527
|
|
$
|
5,553
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
(GAAP) - (d) + (f)
|
$
|
25,447
|
|
$
|
22,670
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
(Non-GAAP) - (d) + (g)
|
$
|
23,891
|
|
$
|
21,836
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Total
Capitalization (Non-GAAP) * - (h)
|
$
|
22,864
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROCE (GAAP Net
Income) - [(a) + (b)] /
(h)
|
|
15.8%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROCE (Non-GAAP
Adjusted Net Income) - [(a) + (c)] /
(h)
|
|
14.9%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Return on Equity
(ROE)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROE (GAAP Net
Income) - (b) / (e)
|
|
19.2%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROE (Non-GAAP
Adjusted Net Income) - (c) / (e)
|
|
18.1%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* Average for the
current and immediately preceding year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments to Net
Income (GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) See below
schedule for detail of adjustments to Net Income (GAAP) in
2018:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31, 2018
|
|
|
Before
|
|
|
Income
Tax
|
|
|
After
|
|
|
Tax
|
|
|
Impact
|
|
|
Tax
|
Adjustments:
|
|
|
|
|
|
|
|
|
Add: Mark-to-Market Commodity Derivative Contracts
Impact
|
$
|
(93)
|
|
$
|
20
|
|
$
|
(73)
|
Add: Impairments of Certain Assets
|
|
153
|
|
|
(34)
|
|
|
119
|
Less: Net Gains on Asset Dispositions
|
|
(175)
|
|
|
38
|
|
|
(137)
|
Less: Tax Reform Impact
|
|
-
|
|
|
(110)
|
|
|
(110)
|
Total
|
$
|
(115)
|
|
$
|
(86)
|
|
$
|
(201)
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net
Debt (Non-GAAP) and Total
|
Capitalization
(Non-GAAP) as used in the Calculation of Return on Capital Employed
(Non-GAAP) to Net Interest
|
Expense (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), Current and Long-Term Debt
(GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest
Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization
(Non-GAAP), respectively, as used in the Return on Capital Employed
(ROCE) (Non-GAAP) calculation. EOG believes this presentation
may be useful to investors who follow the practice of some industry
analysts who utilize After-Tax Net Interest Expense, Net Debt and
Total Capitalization (Non-GAAP) in their ROCE calculation.
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)
|
|
|
|
|
|
|
|
|
|
|
(Calculated Using
GAAP Net Income)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Interest Expense
(GAAP)
|
$
|
274
|
$
|
282
|
$
|
237
|
$
|
201
|
$
|
235
|
Tax Benefit Imputed
(based on 35%)
|
|
(96)
|
|
(99)
|
|
(83)
|
|
(70)
|
|
(82)
|
After-Tax Net
Interest Expense (Non-GAAP) - (a)
|
$
|
178
|
$
|
183
|
$
|
154
|
$
|
131
|
$
|
153
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
(GAAP) -
(b)
|
$
|
2,583
|
$
|
(1,097)
|
$
|
(4,525)
|
$
|
2,915
|
$
|
2,197
|
|
|
|
|
|
|
|
|
|
|
|
Total Stockholders'
Equity - (d)
|
$
|
16,283
|
$
|
13,982
|
$
|
12,943
|
$
|
17,713
|
$
|
15,418
|
|
|
|
|
|
|
|
|
|
|
|
Average Total
Stockholders' Equity * - (e)
|
$
|
15,133
|
$
|
13,463
|
$
|
15,328
|
$
|
16,566
|
$
|
14,352
|
|
|
|
|
|
|
|
|
|
|
|
Current and Long-Term
Debt (GAAP) - (f)
|
$
|
6,387
|
$
|
6,986
|
$
|
6,655
|
$
|
5,906
|
$
|
5,909
|
Less:
Cash
|
|
(834)
|
|
(1,600)
|
|
(719)
|
|
(2,087)
|
|
(1,318)
|
Net Debt (Non-GAAP) -
(g)
|
$
|
5,553
|
$
|
5,386
|
$
|
5,936
|
$
|
3,819
|
$
|
4,591
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
(GAAP) - (d) + (f)
|
$
|
22,670
|
$
|
20,968
|
$
|
19,598
|
$
|
23,619
|
$
|
21,327
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
(Non-GAAP) - (d) + (g)
|
$
|
21,836
|
$
|
19,368
|
$
|
18,879
|
$
|
21,532
|
$
|
20,009
|
|
|
|
|
|
|
|
|
|
|
|
Average Total
Capitalization (Non-GAAP) * - (h)
|
$
|
20,602
|
$
|
19,124
|
$
|
20,206
|
$
|
20,771
|
$
|
19,365
|
|
|
|
|
|
|
|
|
|
|
|
ROCE (GAAP Net
Income) - [(a) + (b)] /
(h)
|
|
13.4%
|
|
-4.8%
|
|
-21.6%
|
|
14.7%
|
|
12.1%
|
|
|
|
|
|
|
|
|
|
|
|
Return on Equity
(ROE) (GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROE (GAAP Net
Income) - (b) / (e)
|
|
17.1%
|
|
-8.1%
|
|
-29.5%
|
|
17.6%
|
|
15.3%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* Average for the
current and immediately preceding year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net
Debt (Non-GAAP) and Total
|
Capitalization
(Non-GAAP) as used in the Calculation of Return on Capital Employed
(Non-GAAP) to Net Interest
|
Expense (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), Current and Long-Term Debt
(GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest
Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization
(Non-GAAP), respectively, as used in the Return on Capital Employed
(ROCE) (Non-GAAP) calculation. EOG believes this presentation
may be useful to investors who follow the practice of some industry
analysts who utilize After-Tax Net Interest Expense, Net Debt and
Total Capitalization (Non-GAAP) in their ROCE calculation.
EOG management uses this information for purposes of comparing its
financial performance with the financial performance of other
companies in the industry.
|
|
|
|
|
|
|
|
|
|
|
|
|
2012
|
2011
|
2010
|
2009
|
2008
|
Return on Capital
Employed (ROCE) (Non-GAAP)
|
|
|
|
|
|
|
|
|
|
|
(Calculated Using
GAAP Net Income)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Interest Expense
(GAAP)
|
$
|
214
|
$
|
210
|
$
|
130
|
$
|
101
|
$
|
52
|
Tax Benefit Imputed
(based on 35%)
|
|
(75)
|
|
(74)
|
|
(46)
|
|
(35)
|
|
(18)
|
After-Tax Net
Interest Expense (Non-GAAP) - (a)
|
$
|
139
|
$
|
136
|
$
|
84
|
$
|
66
|
$
|
34
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
(GAAP) -
(b)
|
$
|
570
|
$
|
1,091
|
$
|
161
|
$
|
547
|
$
|
2,437
|
|
|
|
|
|
|
|
|
|
|
|
Total Stockholders'
Equity - (d)
|
$
|
13,285
|
$
|
12,641
|
$
|
10,232
|
$
|
9,998
|
$
|
9,015
|
|
|
|
|
|
|
|
|
|
|
|
Average Total
Stockholders' Equity * - (e)
|
$
|
12,963
|
$
|
11,437
|
$
|
10,115
|
$
|
9,507
|
$
|
8,003
|
|
|
|
|
|
|
|
|
|
|
|
Current and Long-Term
Debt (GAAP) - (f)
|
$
|
6,312
|
$
|
5,009
|
$
|
5,223
|
$
|
2,797
|
$
|
1,897
|
Less:
Cash
|
|
(876)
|
|
(616)
|
|
(789)
|
|
(686)
|
|
(331)
|
Net Debt (Non-GAAP) -
(g)
|
$
|
5,436
|
$
|
4,393
|
$
|
4,434
|
$
|
2,111
|
$
|
1,566
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
(GAAP) - (d) + (f)
|
$
|
19,597
|
$
|
17,650
|
$
|
15,455
|
$
|
12,795
|
$
|
10,912
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
(Non-GAAP) - (d) + (g)
|
$
|
18,721
|
$
|
17,034
|
$
|
14,666
|
$
|
12,109
|
$
|
10,581
|
|
|
|
|
|
|
|
|
|
|
|
Average Total
Capitalization (Non-GAAP) * - (h)
|
$
|
17,878
|
$
|
15,850
|
$
|
13,388
|
$
|
11,345
|
$
|
9,351
|
|
|
|
|
|
|
|
|
|
|
|
ROCE (GAAP Net
Income) - [(a) + (b)] /
(h)
|
|
4.0%
|
|
7.7%
|
|
1.8%
|
|
5.4%
|
|
26.4%
|
|
|
|
|
|
|
|
|
|
|
|
Return on Equity
(ROE) (GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROE (GAAP Net
Income) - (b) / (e)
|
|
4.4%
|
|
9.5%
|
|
1.6%
|
|
5.8%
|
|
30.5%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* Average for the
current and immediately preceding year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net
Debt (Non-GAAP) and Total
|
Capitalization
(Non-GAAP) as used in the Calculation of Return on Capital Employed
(Non-GAAP) to Net Interest
|
Expense (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), Current and Long-Term Debt
(GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest
Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization
(Non-GAAP), respectively, as used in the Return on Capital Employed
(ROCE) (Non-GAAP) calculation. EOG believes this presentation
may be useful to investors who follow the practice of some industry
analysts who utilize After-Tax Net Interest Expense, Net Debt and
Total Capitalization (Non-GAAP) in their ROCE calculation.
EOG management uses this information for purposes of comparing its
financial performance with the financial performance of other
companies in the industry.
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
2006
|
2005
|
2004
|
2003
|
Return on Capital
Employed (ROCE) (Non-GAAP)
|
|
|
|
|
|
|
|
|
|
|
(Calculated Using
GAAP Net Income)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Interest Expense
(GAAP)
|
$
|
47
|
$
|
43
|
$
|
63
|
$
|
63
|
$
|
59
|
Tax Benefit Imputed
(based on 35%)
|
|
(16)
|
|
(15)
|
|
(22)
|
|
(22)
|
|
(21)
|
After-Tax Net
Interest Expense (Non-GAAP) - (a)
|
$
|
31
|
$
|
28
|
$
|
41
|
$
|
41
|
$
|
38
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
(GAAP) -
(b)
|
$
|
1,090
|
$
|
1,300
|
$
|
1,260
|
$
|
625
|
$
|
430
|
|
|
|
|
|
|
|
|
|
|
|
Total Stockholders'
Equity - (d)
|
$
|
6,990
|
$
|
5,600
|
$
|
4,316
|
$
|
2,945
|
$
|
2,223
|
|
|
|
|
|
|
|
|
|
|
|
Average Total
Stockholders' Equity * - (e)
|
$
|
6,295
|
$
|
4,958
|
$
|
3,631
|
$
|
2,584
|
$
|
1,948
|
|
|
|
|
|
|
|
|
|
|
|
Current and Long-Term
Debt (GAAP) - (f)
|
$
|
1,185
|
$
|
733
|
$
|
985
|
$
|
1,078
|
$
|
1,109
|
Less:
Cash
|
|
(54)
|
|
(218)
|
|
(644)
|
|
(21)
|
|
(4)
|
Net Debt (Non-GAAP) -
(g)
|
$
|
1,131
|
$
|
515
|
$
|
341
|
$
|
1,057
|
$
|
1,105
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
(GAAP) - (d) + (f)
|
$
|
8,175
|
$
|
6,333
|
$
|
5,301
|
$
|
4,023
|
$
|
3,332
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
(Non-GAAP) - (d) + (g)
|
$
|
8,121
|
$
|
6,115
|
$
|
4,657
|
$
|
4,002
|
$
|
3,328
|
|
|
|
|
|
|
|
|
|
|
|
Average Total
Capitalization (Non-GAAP) * - (h)
|
$
|
7,118
|
$
|
5,386
|
$
|
4,330
|
$
|
3,665
|
$
|
3,068
|
|
|
|
|
|
|
|
|
|
|
|
ROCE (GAAP Net
Income) - [(a) + (b)] /
(h)
|
|
15.7%
|
|
24.7%
|
|
30.0%
|
|
18.2%
|
|
15.3%
|
|
|
|
|
|
|
|
|
|
|
|
Return on Equity
(ROE) (GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROE (GAAP Net
Income) - (b) / (e)
|
|
17.3%
|
|
26.2%
|
|
34.7%
|
|
24.2%
|
|
22.1%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* Average for the
current and immediately preceding year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net
Debt (Non-GAAP) and Total
|
Capitalization
(Non-GAAP) as used in the Calculation of Return on Capital Employed
(Non-GAAP) to Net Interest
|
Expense (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), Current and Long-Term Debt
(GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest
Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization
(Non-GAAP), respectively, as used in the Return on Capital Employed
(ROCE) (Non-GAAP) calculation. EOG believes this presentation
may be useful to investors who follow the practice of some industry
analysts who utilize After-Tax Net Interest Expense, Net Debt and
Total Capitalization (Non-GAAP) in their ROCE calculation.
EOG management uses this information for purposes of comparing its
financial performance with the financial performance of other
companies in the industry.
|
|
|
|
|
|
|
|
|
|
|
|
|
2002
|
2001
|
2000
|
1999
|
1998
|
Return on Capital
Employed (ROCE) (Non-GAAP)
|
|
|
|
|
|
|
|
|
|
|
(Calculated Using
GAAP Net Income)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Interest Expense
(GAAP)
|
$
|
60
|
$
|
45
|
$
|
61
|
$
|
62
|
|
|
Tax Benefit Imputed
(based on 35%)
|
|
(21)
|
|
(16)
|
|
(21)
|
|
(22)
|
|
|
After-Tax Net
Interest Expense (Non-GAAP) - (a)
|
$
|
39
|
$
|
29
|
$
|
40
|
$
|
40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
(GAAP) -
(b)
|
$
|
87
|
$
|
399
|
$
|
397
|
$
|
569
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Stockholders'
Equity - (d)
|
$
|
1,672
|
$
|
1,643
|
$
|
1,381
|
$
|
1,130
|
$
|
1,280
|
|
|
|
|
|
|
|
|
|
|
|
Average Total
Stockholders' Equity * - (e)
|
$
|
1,658
|
$
|
1,512
|
$
|
1,256
|
$
|
1,205
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current and Long-Term
Debt (GAAP) - (f)
|
$
|
1,145
|
$
|
856
|
$
|
859
|
$
|
990
|
$
|
1,143
|
Less:
Cash
|
|
(10)
|
|
(3)
|
|
(20)
|
|
(25)
|
|
(6)
|
Net Debt (Non-GAAP) -
(g)
|
$
|
1,135
|
$
|
853
|
$
|
839
|
$
|
965
|
$
|
1,137
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
(GAAP) - (d) + (f)
|
$
|
2,817
|
$
|
2,499
|
$
|
2,240
|
$
|
2,120
|
$
|
2,423
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
(Non-GAAP) - (d) + (g)
|
$
|
2,807
|
$
|
2,496
|
$
|
2,220
|
$
|
2,095
|
$
|
2,417
|
|
|
|
|
|
|
|
|
|
|
|
Average Total
Capitalization (Non-GAAP) * - (h)
|
$
|
2,652
|
$
|
2,358
|
$
|
2,158
|
$
|
2,256
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROCE (GAAP Net
Income) - [(a) + (b)] /
(h)
|
|
4.8%
|
|
18.2%
|
|
20.2%
|
|
27.0%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Return on Equity
(ROE) (GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROE (GAAP Net
Income) - (b) / (e)
|
|
5.2%
|
|
26.4%
|
|
31.6%
|
|
47.2%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* Average for the
current and immediately preceding year
|
EOG RESOURCES,
INC.
|
Cash Operating
Expenses per Barrel of Oil Equivalent (Boe)
|
(Unaudited; in
thousands, except per Boe amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ended
|
|
|
December
31,
|
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Operating
Expenses (GAAP)*
|
|
|
|
|
|
|
|
|
|
|
|
Lease and
Well
|
$
1,282,678
|
|
$
1,044,847
|
|
$
927,452
|
|
$
1,182,282
|
|
$
1,416,413
|
|
Transportation
Costs
|
746,876
|
|
740,352
|
|
764,106
|
|
849,319
|
|
972,176
|
|
General and
Administrative
|
426,969
|
|
434,467
|
|
394,815
|
|
366,594
|
|
402,010
|
|
Cash Operating
Expenses
|
2,456,523
|
|
2,219,666
|
|
2,086,373
|
|
2,398,195
|
|
2,790,599
|
|
Less: Legal
Settlement - Early Leasehold Termination
|
-
|
|
(10,202)
|
|
-
|
|
(19,355)
|
|
-
|
|
Less: Voluntary
Retirement Expense
|
-
|
|
-
|
|
(42,054)
|
|
-
|
|
-
|
|
Less:
Acquisition Costs - Yates Transaction
|
-
|
|
-
|
|
(5,100)
|
|
-
|
|
-
|
|
Less: Joint
Venture Transaction Costs
|
-
|
|
(3,056)
|
|
-
|
|
-
|
|
-
|
|
Less: Joint
Interest Billings Deemed Uncollectible
|
-
|
|
(4,528)
|
|
-
|
|
-
|
|
-
|
|
Adjusted Cash Operating
Expenses (Non-GAAP) - (a)
|
$
2,456,523
|
|
$
2,201,880
|
|
$
2,039,219
|
|
$
2,378,840
|
|
$
2,790,599
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume - Thousand
Barrels of Oil Equivalent - (b)
|
262,516
|
|
222,251
|
|
204,929
|
|
208,862
|
|
217,073
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Cash
Operating Expenses Per Boe (Non-GAAP) - (a) / (b)
|
|
$
9.36
|
(c)
|
$
9.91
|
(d)
|
$
9.95
|
(e)
|
$
11.39
|
(f)
|
$
12.86
|
(g)
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Cash
Operating Expenses Per Boe (Non-GAAP) -
Percentage Decrease
|
|
|
|
|
|
|
|
|
|
|
|
2018 compared to 2017
- [(c) - (d)] /
(d)
|
-6%
|
|
|
|
|
|
|
|
|
|
2018 compared to 2016
- [(c) - (e)] /
(e)
|
-6%
|
|
|
|
|
|
|
|
|
|
2018 compared to 2015
- [(c) - (f)] /
(f)
|
-18%
|
|
|
|
|
|
|
|
|
|
2018 compared to 2014
- [(c) - (g)] /
(g)
|
-27%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* Includes stock
compensation expense and other non-cash items.
|
EOG RESOURCES,
INC.
|
Cost per Barrel of
Oil Equivalent (Boe)
|
(Unaudited; in
thousands, except per Boe amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
|
|
March
31,
|
|
June
30,
|
|
September
30,
|
|
December
31,
|
|
|
|
2018
|
|
2018
|
|
2018
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume - Thousand
Barrels of Oil Equivalent - (a)
|
59,394
|
|
63,898
|
|
68,890
|
|
70,334
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil and
Condensate
|
$
2,101,308
|
|
$
2,377,528
|
|
$
2,655,278
|
|
$
2,383,326
|
|
|
Natural Gas
Liquids
|
221,415
|
|
286,354
|
|
353,704
|
|
266,037
|
|
|
Natural Gas
|
299,766
|
|
300,845
|
|
311,713
|
|
389,213
|
|
|
Total Wellhead
Revenues - (b)
|
$
2,622,489
|
|
$
2,964,727
|
|
$
3,320,695
|
|
$
3,038,576
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Costs
|
|
|
|
|
|
|
|
|
|
Lease and Well
|
$
300,064
|
|
$
314,604
|
|
$
321,568
|
|
$
346,442
|
|
|
Transportation
Costs
|
176,957
|
|
177,797
|
|
196,027
|
|
196,095
|
|
|
Gathering and Processing
Costs
|
101,345
|
|
109,169
|
|
114,063
|
|
112,396
|
|
|
General and
Administrative
|
94,698
|
|
104,083
|
|
111,284
|
|
116,904
|
|
|
Taxes Other Than
Income
|
179,084
|
|
194,268
|
|
209,043
|
|
190,086
|
|
|
Interest Expense,
Net
|
61,956
|
|
63,444
|
|
63,632
|
|
56,020
|
|
|
Total Cash
Operating Cost (excluding
DD&A and Exploration Costs) - (c)
|
$
914,104
|
|
$
963,365
|
|
$
1,015,617
|
|
$
1,017,943
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, Depletion and
Amortization (DD&A)
|
748,591
|
|
848,674
|
|
918,180
|
|
919,963
|
|
|
Total Operating
Cost (excluding Exploration
Costs) - (d)
|
$
1,662,695
|
|
$
1,812,039
|
|
$
1,933,797
|
|
$
1,937,906
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration Costs
|
$
34,836
|
|
$
47,478
|
|
$
32,823
|
|
$
33,862
|
|
|
Dry Hole Costs
|
-
|
|
4,902
|
|
358
|
|
145
|
|
|
Impairments
|
64,609
|
|
51,708
|
|
44,617
|
|
186,087
|
|
|
Total Exploration
Costs
|
99,445
|
|
104,088
|
|
77,798
|
|
220,094
|
|
|
Less: Impairments (Non-GAAP)
|
(20,876)
|
|
-
|
|
-
|
|
(131,795)
|
|
|
Total Exploration Costs
(Non-GAAP)
|
$
78,569
|
|
$
104,088
|
|
$
77,798
|
|
$
88,299
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating
Cost (Non-GAAP) (including Exploration
Costs) - (e)
|
$
1,741,264
|
|
$
1,916,127
|
|
$
2,011,595
|
|
$
2,026,205
|
|
|
|
|
|
|
|
|
|
|
|
|
Composite Average
Wellhead Revenue per Boe - (b) / (a)
|
$
44.15
|
|
$
46.40
|
|
$
48.20
|
|
$
43.20
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Cash
Operating Cost per Boe
(excluding DD&A and Exploration Costs) - (c) /
(a)
|
$
15.39
|
|
$
15.07
|
|
$
14.75
|
|
$
14.48
|
|
|
|
|
|
|
|
|
|
|
|
|
Composite Average
Margin per Boe (excluding
DD&A and Exploration Costs) - [(b) / (a) - (c) /
(a)]
|
$
28.76
|
|
$
31.33
|
|
$
33.45
|
|
$
28.72
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating
Cost per Boe (excluding
Exploration Costs) - (d) / (a)
|
$
27.99
|
|
$
28.35
|
|
$
28.08
|
|
$
27.56
|
|
|
|
|
|
|
|
|
|
|
|
|
Composite
Average Margin per Boe (excluding
Exploration Costs) - [(b) / (a) - (d) /
(a)]
|
$
16.16
|
|
$
18.05
|
|
$
20.12
|
|
$
15.64
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating
Cost per Boe (Non-GAAP) (including
Exploration Costs) (e) / (a)
|
$
29.31
|
|
$
29.98
|
|
$
29.21
|
|
$
28.82
|
|
|
|
|
|
|
|
|
|
|
|
|
Composite Average
Margin per Boe (Non-GAAP)
(including Exploration Costs) - [(b) / (a) - (e) /
(a)]
|
$
14.84
|
|
$
16.42
|
|
$
18.99
|
|
$
14.38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EOG RESOURCES,
INC.
|
Cost per Barrel of
Oil Equivalent (Boe)
|
(Unaudited; in
thousands, except per Boe amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ended
|
|
December
31,
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
Volume - Thousand
Barrels of Oil Equivalent - (a)
|
262,516
|
|
222,251
|
|
204,929
|
|
208,862
|
|
217,073
|
|
|
|
|
|
|
|
|
|
|
Crude Oil and
Condensate
|
$
9,517,440
|
|
$
6,256,396
|
|
$
4,317,341
|
|
$
4,934,562
|
|
$
9,742,480
|
Natural Gas
Liquids
|
1,127,510
|
|
729,561
|
|
437,250
|
|
407,658
|
|
934,051
|
Natural Gas
|
1,301,537
|
|
921,934
|
|
742,152
|
|
1,061,038
|
|
1,916,386
|
Total Wellhead
Revenues - (b)
|
$
11,946,487
|
|
$
7,907,891
|
|
$
5,496,743
|
|
$
6,403,258
|
|
$
12,592,917
|
|
|
|
|
|
|
|
|
|
|
Operating
Costs
|
|
|
|
|
|
|
|
|
|
Lease and Well
|
$
1,282,678
|
|
$
1,044,847
|
|
$
927,452
|
|
$
1,182,282
|
|
$
1,416,413
|
Transportation
Costs
|
746,876
|
|
740,352
|
|
764,106
|
|
849,319
|
|
972,176
|
Gathering and Processing
Costs
|
436,973
|
|
148,775
|
|
122,901
|
|
146,156
|
|
145,800
|
|
|
|
|
|
|
|
|
|
|
General and
Administrative
|
426,969
|
|
434,467
|
|
394,815
|
|
366,594
|
|
402,010
|
Less: Voluntary Retirement Expense
|
-
|
|
-
|
|
(42,054)
|
|
-
|
|
-
|
Less: Acquisition Costs
|
-
|
|
-
|
|
(5,100)
|
|
-
|
|
-
|
Less: Legal Settlement - Early Leasehold
Termination
|
-
|
|
(10,202)
|
|
-
|
|
(19,355)
|
|
-
|
Less: Joint Venture Transaction Costs
|
-
|
|
(3,056)
|
|
-
|
|
-
|
|
-
|
Less: Joint Interest Billings Deemed Uncollectible
|
-
|
|
(4,528)
|
|
-
|
|
-
|
|
-
|
General and Administrative
(Non-GAAP)
|
426,969
|
|
416,681
|
|
347,661
|
|
347,239
|
|
402,010
|
|
|
|
|
|
|
|
|
|
|
Taxes Other Than
Income
|
772,481
|
|
544,662
|
|
349,710
|
|
421,744
|
|
757,564
|
Interest Expense,
Net
|
245,052
|
|
274,372
|
|
281,681
|
|
237,393
|
|
201,458
|
Total Cash
Operating Cost (Non-GAAP) (excluding
DD&A and Exploration Costs) - (c)
|
$
3,911,029
|
|
$
3,169,689
|
|
$
2,793,511
|
|
$
3,184,133
|
|
$
3,895,421
|
|
|
|
|
|
|
|
|
|
|
Depreciation, Depletion and
Amortization (DD&A)
|
3,435,408
|
|
3,409,387
|
|
3,553,417
|
|
3,313,644
|
|
3,997,041
|
Total Operating
Cost (Non-GAAP) (excluding Exploration
Costs) - (d)
|
$
7,346,437
|
|
$
6,579,076
|
|
$
6,346,928
|
|
$
6,497,777
|
|
$
7,892,462
|
|
|
|
|
|
|
|
|
|
|
Exploration Costs
|
$
148,999
|
|
$
145,342
|
|
$
124,953
|
|
$
149,494
|
|
$
184,388
|
Dry Hole Costs
|
5,405
|
|
4,609
|
|
10,657
|
|
14,746
|
|
48,490
|
Impairments
|
347,021
|
|
479,240
|
|
620,267
|
|
6,613,546
|
|
743,575
|
Total Exploration
Costs
|
501,425
|
|
629,191
|
|
755,877
|
|
6,777,786
|
|
976,453
|
Less: Impairments (Non-GAAP)
|
(152,671)
|
|
(261,452)
|
|
(320,617)
|
|
(6,307,593)
|
|
(824,312)
|
Total Exploration Costs
(Non-GAAP)
|
$
348,754
|
|
$
367,739
|
|
$
435,260
|
|
$
470,193
|
|
$
152,141
|
|
|
|
|
|
|
|
|
|
|
Total Operating
Cost (Non-GAAP) (including Exploration
Costs) - (e)
|
$
7,695,191
|
|
$
6,946,815
|
|
$
6,782,188
|
|
$
6,967,970
|
|
$
8,044,603
|
|
|
|
|
|
|
|
|
|
|
Composite Average
Wellhead Revenue per Boe - (b) / (a)
|
$
45.51
|
|
$
35.58
|
|
$
26.82
|
|
$
30.66
|
|
$
58.01
|
|
|
|
|
|
|
|
|
|
|
Total Cash
Operating Cost per Boe (Non-GAAP)
(excluding DD&A and Exploration Costs) - (c) /
(a)
|
$
14.90
|
|
$
14.25
|
|
$
13.64
|
|
$
15.25
|
|
$
17.95
|
|
|
|
|
|
|
|
|
|
|
Composite Average
Margin per Boe (Non-GAAP)
(excluding DD&A and Exploration Costs) - [(b) /
(a) - (c) / (a)]
|
$
30.61
|
|
$
21.33
|
|
$
13.18
|
|
$
15.41
|
|
$
40.06
|
|
|
|
|
|
|
|
|
|
|
Total Operating
Cost per Boe (Non-GAAP) (excluding
Exploration Costs) - (d) / (a)
|
$
27.99
|
|
$
29.59
|
|
$
30.98
|
|
$
31.11
|
|
$
36.38
|
|
|
|
|
|
|
|
|
|
|
Composite Average
Margin per Boe (Non-GAAP)
(excluding Exploration Costs) - [(b) / (a) - (d) /
(a)]
|
$
17.52
|
|
$
5.99
|
|
$
(4.16)
|
|
$
(0.45)
|
|
$
21.63
|
|
|
|
|
|
|
|
|
|
|
Total Operating
Cost per Boe (Non-GAAP) (including
Exploration Costs) - (e) / (a)
|
$
29.32
|
|
$
31.24
|
|
$
33.10
|
|
$
33.36
|
|
$
37.08
|
|
|
|
|
|
|
|
|
|
|
Composite Average
Margin per Boe (Non-GAAP)
(including Exploration Costs) - [(b) / (a) - (e) /
(a)]
|
$
16.19
|
|
$
4.34
|
|
$
(6.28)
|
|
$
(2.70)
|
|
$
20.93
|
EOG RESOURCES,
INC.
|
First Quarter and
Full Year 2019 Forecast and Benchmark Commodity
Pricing
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) First Quarter and
Full Year 2019 Forecast
|
|
The forecast items
for the first quarter and full year 2019 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) Capital
Expenditures
|
|
The forecast includes
expenditures for Exploration and Development Drilling, Facilities,
Leasehold Acquisitions, Capitalized Interest, Exploration Costs,
Dry Hole Costs and Other Property, Plant and Equipment. The
forecast excludes Property Acquisitions, Asset Retirement Costs and
any Non-Cash Exchanges.
|
|
(c) Benchmark
Commodity Pricing
|
|
EOG bases United
States and Trinidad crude oil and condensate price differentials
upon the West Texas Intermediate crude oil price at Cushing,
Oklahoma, using the simple average of the NYMEX settlement prices
for each trading day within the applicable calendar
month.
|
|
EOG bases United
States natural gas price differentials upon the natural gas price
at Henry Hub, Louisiana, using the simple average of the NYMEX
settlement prices for the last three trading days of the applicable
month.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
Ranges
|
|
|
(Unaudited)
|
|
|
1Q 2019
|
|
|
Full Year
2019
|
Daily Sales
Volumes
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil and Condensate
Volumes (MBbld)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
426.6
|
-
|
|
434.2
|
|
|
442.6
|
-
|
|
458.2
|
Trinidad
|
|
0.4
|
-
|
|
0.6
|
|
|
0.4
|
-
|
|
0.6
|
Other International
|
|
0.0
|
-
|
|
0.2
|
|
|
0.0
|
-
|
|
0.2
|
Total
|
|
427.0
|
-
|
|
435.0
|
|
|
443.0
|
-
|
|
459.0
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids Volumes
(MBbld)
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
115.0
|
-
|
|
125.0
|
|
|
120.0
|
-
|
|
140.0
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Volumes
(MMcfd)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
950
|
-
|
|
1,000
|
|
|
1,030
|
-
|
|
1,130
|
Trinidad
|
|
245
|
-
|
|
275
|
|
|
250
|
-
|
|
290
|
Other International
|
|
30
|
-
|
|
40
|
|
|
30
|
-
|
|
40
|
Total
|
|
1,225
|
-
|
|
1,315
|
|
|
1,310
|
-
|
|
1,460
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Equivalent Volumes
(MBoed)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
699.9
|
-
|
|
725.9
|
|
|
734.3
|
-
|
|
786.5
|
Trinidad
|
|
41.2
|
-
|
|
46.4
|
|
|
42.1
|
-
|
|
48.9
|
Other International
|
|
5.0
|
-
|
|
6.9
|
|
|
5.0
|
-
|
|
6.9
|
Total
|
|
746.1
|
-
|
|
779.2
|
|
|
781.4
|
-
|
|
842.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures
($MM)
|
$
|
1,750
|
-
|
$
|
1,950
|
|
$
|
6,100
|
-
|
$
|
6,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
Ranges
|
|
|
(Unaudited)
|
|
1Q 2019
|
|
|
Full Year
2019
|
Operating
Costs
|
|
|
|
|
|
|
|
|
|
|
|
Unit Costs
($/Boe)
|
|
|
|
|
|
|
|
|
|
|
|
Lease and Well
|
$
|
4.90
|
-
|
$
|
5.30
|
|
$
|
4.50
|
-
|
$
|
5.30
|
Transportation Costs
|
$
|
2.50
|
-
|
$
|
3.00
|
|
$
|
2.60
|
-
|
$
|
3.10
|
Depreciation, Depletion and Amortization
|
$
|
12.50
|
-
|
$
|
13.00
|
|
$
|
12.25
|
-
|
$
|
13.25
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses
($MM)
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and Dry
Hole
|
$
|
35
|
-
|
$
|
45
|
|
$
|
155
|
-
|
$
|
195
|
Impairment
|
$
|
55
|
-
|
$
|
65
|
|
$
|
190
|
-
|
$
|
230
|
General and
Administrative
|
$
|
110
|
-
|
$
|
120
|
|
$
|
450
|
-
|
$
|
490
|
Gathering and
Processing
|
$
|
100
|
-
|
$
|
110
|
|
$
|
440
|
-
|
$
|
480
|
Capitalized
Interest
|
$
|
6
|
-
|
$
|
8
|
|
$
|
25
|
-
|
$
|
30
|
Net Interest
|
$
|
54
|
-
|
$
|
56
|
|
$
|
190
|
-
|
$
|
200
|
|
|
|
|
|
|
|
|
|
|
|
|
Taxes Other Than
Income (% of Wellhead Revenue)
|
|
7.2%
|
-
|
|
7.6%
|
|
|
7.2%
|
-
|
|
7.6%
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Taxes
|
|
|
|
|
|
|
|
|
|
|
|
Effective
Rate
|
|
20%
|
-
|
|
25%
|
|
|
20%
|
-
|
|
25%
|
Current Tax (Benefit) /
Expense ($MM)
|
$
|
(55)
|
-
|
$
|
(15)
|
|
$
|
(190)
|
-
|
$
|
(110)
|
|
|
|
|
|
|
|
|
|
|
|
|
Pricing - (Refer
toBenchmark Commodity Pricingin text)
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil and Condensate
($/Bbl)
|
|
|
|
|
|
|
|
|
|
|
|
Differentials
|
|
|
|
|
|
|
|
|
|
|
|
United States - above (below) WTI
|
$
|
0.25
|
-
|
$
|
1.25
|
|
$
|
(1.00)
|
-
|
$
|
1.00
|
Trinidad - above (below) WTI
|
$
|
(11.00)
|
-
|
$
|
(9.00)
|
|
$
|
(11.00)
|
-
|
$
|
(9.00)
|
Other International - above (below) WTI
|
$
|
5.00
|
-
|
$
|
9.00
|
|
$
|
(1.00)
|
-
|
$
|
1.00
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
Liquids
|
|
|
|
|
|
|
|
|
|
|
|
Realizations as % of WTI
|
|
37%
|
-
|
|
43%
|
|
|
37%
|
-
|
|
43%
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
($/Mcf)
|
|
|
|
|
|
|
|
|
|
|
|
Differentials
|
|
|
|
|
|
|
|
|
|
|
|
United States - above (below) NYMEX Henry Hub
|
$
|
(0.40)
|
-
|
$
|
0.00
|
|
$
|
(0.50)
|
-
|
$
|
0.10
|
|
|
|
|
|
|
|
|
|
|
|
|
Realizations
|
|
|
|
|
|
|
|
|
|
|
|
Trinidad
|
$
|
2.50
|
-
|
$
|
2.90
|
|
$
|
2.50
|
-
|
$
|
3.20
|
Other International
|
$
|
4.30
|
-
|
$
|
4.80
|
|
$
|
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
|
|
|
|
|
|
|
|
|
|
|
|
View original
content:http://www.prnewswire.com/news-releases/eog-resources-reports-fourth-quarter-and-full-year-2018-results-and-announces-2019-capital-program-300802665.html
SOURCE EOG Resources, Inc.