HOUSTON, Nov. 3, 2016 /PRNewswire/ --
- Increases 2020 Crude Oil Production CAGR Outlook to 15 to 25
Percent
- Expands Delaware Basin Net
Resource Potential from 2.35 to 6.0 BnBoe (includes Assets from
Recent Yates Transaction)
- Exceeds U.S. Production Targets
- Raises 2016 U.S. Crude Oil Production Guidance
- Updates Year-to-Date Proceeds from Asset Sales to $625 Million
EOG Resources, Inc. (NYSE: EOG) today reported a third quarter
2016 net loss of $190.0 million, or
$0.35 per share. This compares to a
third quarter 2015 net loss of $4.1
billion, or $7.47 per
share.
Adjusted non-GAAP net loss for the third quarter 2016 was
$220.8 million, or $0.40 per share, compared to adjusted non-GAAP
net income of $13.5 million, or
$0.02 per share, for the same prior
year period. Adjusted non-GAAP net income (loss) is
calculated by matching hedge realizations to settlement months and
making certain other adjustments in order to exclude non-recurring
and certain other items. For a reconciliation of non-GAAP
measures to GAAP measures, please refer to the attached tables.
Lower crude oil and natural gas prices more than offset
significant well productivity improvements and lease and well cost
reductions, resulting in decreases in adjusted non-GAAP net income,
discretionary cash flow and EBITDAX during the third quarter 2016
compared to the third quarter 2015. For a reconciliation of
non-GAAP measures to GAAP measures, please refer to the attached
tables.
Operational Highlights
U.S. crude oil volumes of 275,700 barrels of oil per day (Bopd) in
the third quarter 2016 exceeded the midpoint of the company's
guidance by 3 percent. Compared to the same prior year period,
lease and well expenses decreased 18 percent on a per-unit
basis.
In the third quarter 2016, total crude oil production increased
1 percent while exploration and development expenditures (excluding
property acquisitions) decreased 32 percent, compared to the same
period last year. Natural gas liquids production increased 5
percent, while total natural gas production for the third quarter
2016 decreased 10 percent versus the same prior year
period.
"Even in a low commodity price environment, 2016 is proving to
be a breakout year for EOG with record well productivity,
sustainable cost reductions and organic growth in all our core
plays, coupled with a historic transaction that adds substantial
high-return growth potential," said William R. "Bill" Thomas,
Chairman and Chief Executive Officer. "EOG's third quarter
accomplishments reflect the hard work and ingenuity of our great
employees and our unique culture."
2020 Crude Oil Production Outlook and 2016 Capital Plan
Update
As a result of continued improvements in capital
efficiency which have been augmented by the Yates transaction, EOG
is increasing its crude oil organic production growth outlook
through 2020. The long term outlook includes growth from key
areas such as the Eagle Ford, Delaware Basin, Rockies and the Bakken.
In addition to the growth illustrated in the outlook, the company
continues to evaluate high-quality emerging plays through its
ongoing exploration efforts.
Assuming balanced spending including dividend payments and a
flat $50 West Texas Intermediate
crude oil (WTI) price, EOG now expects 15 percent compound annual
crude oil production growth through 2020. If the assumed WTI
price is increased to $60, EOG would
expect 25 percent compound annual crude oil production growth
through 2020. This reflects an increase from the company's
prior outlook of 10 to 20 percent growth at $50 to $60 WTI.
"EOG's future has never been brighter, and we are already in a
position to make a material improvement to the long-term outlook we
provided last quarter," Thomas said. "The company-wide
premium drilling strategy and the recently closed Yates transaction
are significantly boosting capital efficiency and enabling us to
extend our lead in unconventional resource productivity."
For 2016, EOG is increasing its capital spending guidance range
by $200 million to $2.6 to $2.8
billion, excluding acquisitions. The spending increase
will be directed toward well completions, which are now targeted to
increase from the initial plan of 270 and the prior revised
forecast of 350 to 450 net wells in 2016. Drilling
productivity continues to improve, and the company now expects to
drill 290 net wells, 40 more than its prior forecast and 90 more
than its original 2016 plans.
Delaware Basin
EOG increased its Delaware Basin
net resource potential by 155 percent to 6.0 billion barrels of oil
equivalent (BnBoe) in the third quarter 2016 (inclusive of the
recent Yates transaction). Delaware Basin net well locations increased by
27 percent to 6,330. The average planned lateral length for
these locations increased from 4,500 feet to over 7,000
feet.
"With the Yates transaction, EOG's Delaware Basin position now exceeds 400,000
net acres in the core window of this world-class play," Thomas
said. "Our technical and operational advances applied to the
combined assets have produced a major increase in EOG's
Delaware Basin potential.
As we continue to make advances in cost management and
technology, we believe our resource potential over time will
continue to increase in both size and quality."
In the Delaware Basin Wolfcamp,
EOG increased its net resource potential from 1.3 BnBoe to 2.9
BnBoe and net well locations from 2,130 to 2,660. For the
Delaware Basin Wolfcamp oil play,
EOG's average gross reserves per well increased to 1,330 thousand
barrels of crude oil equivalent (MBoe) from 750 MBoe, while average
gross reserves per well increased to 1,550 MBoe from 900 MBoe in
the combo portion of the play.
For the Delaware Basin Second
Bone Spring, EOG increased its net resource potential from 0.5
BnBoe to 1.4 BnBoe and net well locations from 1,250 to
1,870. Average gross reserves per well increased to 950 MBoe
from 500 MBoe.
EOG also increased its Delaware
Basin Leonard net resource potential from 0.6 BnBoe to 1.7 BnBoe
and net well locations from 1,600 to 1,800. Average gross
reserves per well increased to 1,175 MBoe from 500 MBoe.
In the third quarter 2016, EOG completed 22 wells in the
Delaware Basin Wolfcamp with an
average treated lateral length of 4,800 feet per well and an
average 30-day initial production rate per well of 2,350 barrels of
oil equivalent per day (Boed), or 1,675 Bopd, 275 barrels per day
(Bpd) of natural gas liquids (NGLs) and 2.4 million cubic feet per
day (MMcfd) of natural gas. In the Delaware Basin Second Bone Spring, EOG
completed four wells in the third quarter with an average treated
lateral length of 4,600 feet per well and an average 30-day initial
production rate per well of 1,240 Boed, or 940 Bopd, 120 Bpd of
NGLs and 1.1 MMcfd of natural gas.
South Texas Eagle Ford
EOG's oil-rich South Texas Eagle Ford acreage continued to deliver
exceptional results in the third quarter 2016 and was once again
the largest contributor to EOG's U.S. crude oil
production.
In the third quarter, EOG completed 47 wells in the Eagle Ford
with an average treated lateral length of 5,700 feet per well and
an average 30-day initial production rate per well of 1,825 Boed,
or 1,425 Bopd, 190 Bpd of NGLs and 1.3 MMcfd of natural gas.
Rockies and the Bakken
In the third quarter, EOG completed nine wells in the Powder River
Basin with an average 30-day initial production rate per well of
1,560 Boed, or 840 Bopd, 245 Bpd of NGLs and 2.8 MMcfd of natural
gas.
In the DJ Basin Codell in Wyoming, EOG completed five wells in the third
quarter with an average 30-day initial production rate per well of
720 Boed, or 610 Bopd, 70 Bpd of NGLs and 0.3 MMcfd of natural gas.
In the North Dakota Bakken, EOG completed 13 wells in the third
quarter with an average 30-day initial production rate per well of
850 Boed, or 763 Bopd, 45 Bpd of NGLs and 0.3 MMcfd of natural gas.
Hedging Activity
For the period November 1 through December
31, 2016, EOG has crude oil financial price collar contracts
in place for 70,000 Bopd at an average ceiling price of
$54.25 per barrel and an average
floor price of $45.00 per
barrel.
For the period March 1 through November
30, 2017, EOG has natural gas financial price swap contracts
in place for 30,000 million British thermal units (MMBtu) per day
at a weighted average price of $3.10
per MMBtu.
For the period March 1 through November
30, 2017, EOG sold natural gas call option contracts for
213,750 MMBtu per day at an average strike price of $3.44 per MMBtu. For the period
March 1 through November 30, 2018,
EOG sold natural gas call option contracts for 120,000 MMBtu per
day at an average strike price of $3.38 per MMBtu.
For the period March 1 through November
30, 2017, EOG purchased natural gas put option contracts for
171,000 MMBtu per day at an average strike price of $2.92 per MMBtu. For the period
March 1 through November 30, 2018,
EOG purchased natural gas put option contracts for 96,000 MMBtu per
day at an average strike price of $2.94 per MMBtu.
A comprehensive summary of crude oil and natural gas derivative
contracts is provided in the attached tables.
Capital Structure and Asset Sales
At September 30, 2016, EOG's total
debt outstanding was $7.0 billion
with a debt-to-total capitalization ratio of 37 percent. Taking
into account cash on the balance sheet of $1.1 billion at the end of the third quarter,
EOG's net debt was $5.9 billion with
a net debt-to-total capitalization ratio of 33 percent. For a
reconciliation of non-GAAP measures to GAAP measures, please refer
to the attached tables.
Proceeds from asset sales this year to date total $625 million. This includes proceeds from a
transaction that has already closed in the fourth quarter
2016. Associated production of the divested assets was 80
MMcfd of natural gas, 3,400 Bopd and 4,290 Bpd of NGLs.
Conference Call November 4,
2016
EOG's third quarter 2016 results conference call will be available
via live audio webcast at 9 a.m. Central
time (10 a.m. Eastern time) on
Friday, November 4, 2016. To
listen, log on to the Investors Overview page on the EOG website at
http://investors.eogresources.com/overview.
EOG Resources, Inc. is one of the largest independent
(non-integrated) crude oil and natural gas companies in
the United States with proved
reserves in the United States,
Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on
the New York Stock Exchange and is traded under the ticker symbol
"EOG." For additional information about EOG, please visit
www.eogresources.com.
This press release includes forward-looking statements within
the meaning of Section 27A of the Securities Act of 1933, as
amended, and Section 21E of the Securities Exchange Act of 1934, as
amended. All statements, other than statements of historical
facts, including, among others, statements and projections
regarding EOG's future financial position, operations, performance,
business strategy, returns, budgets, reserves, levels of production
and costs, statements regarding future commodity prices and
statements regarding the plans and objectives of EOG's management
for future operations, are forward-looking statements. EOG
typically uses words such as "expect," "anticipate," "estimate,"
"project," "strategy," "intend," "plan," "target," "goal," "may,"
"will," "should" and "believe" or the negative of those terms or
other variations or comparable terminology to identify its
forward-looking statements. In particular, statements,
express or implied, concerning EOG's future operating results and
returns or EOG's ability to replace or increase reserves, increase
production, reduce or otherwise control operating and capital
costs, generate income or cash flows or pay dividends are
forward-looking statements. Forward-looking statements are
not guarantees of performance. Although EOG believes the
expectations reflected in its forward-looking statements are
reasonable and are based on reasonable assumptions, no assurance
can be given that these assumptions are accurate or that any of
these expectations will be achieved (in full or at all) or will
prove to have been correct. Moreover, EOG's forward-looking
statements may be affected by known, unknown or currently
unforeseen risks, events or circumstances that may be outside EOG's
control. Important factors that could cause EOG's actual
results to differ materially from the expectations reflected in
EOG's forward-looking statements include, among others:
- the timing, extent and duration of changes in prices for,
supplies of, and demand for, crude oil and condensate, natural gas
liquids, natural gas and related commodities;
- the extent to which EOG is successful in its efforts to acquire
or discover additional reserves;
- the extent to which EOG is successful in its efforts to
economically develop its acreage in, produce reserves and achieve
anticipated production levels from, and maximize reserve recovery
from, its existing and future crude oil and natural gas exploration
and development projects;
- the extent to which EOG is successful in its efforts to market
its crude oil and condensate, natural gas liquids, natural gas and
related commodity production;
- the availability, proximity and capacity of, and costs
associated with, appropriate gathering, processing, compression,
transportation and refining facilities;
- the availability, cost, terms and timing of issuance or
execution of, and competition for, mineral licenses and leases and
governmental and other permits and rights-of-way, and EOG's ability
to retain mineral licenses and leases;
- the impact of, and changes in, government policies, laws and
regulations, including tax laws and regulations; environmental,
health and safety laws and regulations relating to air emissions,
disposal of produced water, drilling fluids and other wastes,
hydraulic fracturing and access to and use of water; laws and
regulations imposing conditions or restrictions on drilling and
completion operations and on the transportation of crude oil and
natural gas; laws and regulations with respect to derivatives and
hedging activities; and laws and regulations with respect to the
import and export of crude oil, natural gas and related
commodities;
- EOG's ability to effectively integrate acquired crude oil and
natural gas properties into its operations, fully identify existing
and potential problems with respect to such properties and
accurately estimate reserves, production and costs with respect to
such properties;
- the extent to which EOG's third-party-operated crude oil and
natural gas properties are operated successfully and
economically;
- competition in the oil and gas exploration and production
industry for the acquisition of licenses, leases and properties,
employees and other personnel, facilities, equipment, materials and
services;
- the availability and cost of employees and other personnel,
facilities, equipment, materials (such as water) and services;
- the accuracy of reserve estimates, which by their nature
involve the exercise of professional judgment and may therefore be
imprecise;
- weather, including its impact on crude oil and natural gas
demand, and weather-related delays in drilling and in the
installation and operation (by EOG or third parties) of production,
gathering, processing, refining, compression and transportation
facilities;
- the ability of EOG's customers and other contractual
counterparties to satisfy their obligations to EOG and, related
thereto, to access the credit and capital markets to obtain
financing needed to satisfy their obligations to EOG;
- EOG's ability to access the commercial paper market and other
credit and capital markets to obtain financing on terms it deems
acceptable, if at all, and to otherwise satisfy its capital
expenditure requirements;
- the extent and effect of any hedging activities engaged in by
EOG;
- the timing and extent of changes in foreign currency exchange
rates, interest rates, inflation rates, global and domestic
financial market conditions and global and domestic general
economic conditions;
- political conditions and developments around the world (such as
political instability and armed conflict), including in the areas
in which EOG operates;
- the use of competing energy sources and the development of
alternative energy sources;
- the extent to which EOG incurs uninsured losses and liabilities
or losses and liabilities in excess of its insurance coverage;
- acts of war and terrorism and responses to these acts;
- physical, electronic and cyber security breaches; and
- the other factors described under ITEM 1A, Risk Factors, on
pages 13 through 21 of EOG's Annual Report on Form 10-K for the
fiscal year ended December 31, 2015,
and any updates to those factors set forth in EOG's subsequent
Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.
In light of these risks, uncertainties and assumptions, the
events anticipated by EOG's forward-looking statements may not
occur, and, if any of such events do, we may not have anticipated
the timing of their occurrence or the duration and extent of their
impact on our actual results. Accordingly, you should not
place any undue reliance on any of EOG's forward-looking
statements. EOG's forward-looking statements speak only as of the
date made, and EOG undertakes no obligation, other than as required
by applicable law, to update or revise its forward-looking
statements, whether as a result of new information, subsequent
events, anticipated or unanticipated circumstances or
otherwise.
The United States Securities and Exchange Commission (SEC)
permits oil and gas companies, in their filings with the SEC, to
disclose not only "proved" reserves (i.e., quantities of oil and
gas that are estimated to be recoverable with a high degree of
confidence), but also "probable" reserves (i.e., quantities of oil
and gas that are as likely as not to be recovered) as well as
"possible" reserves (i.e., additional quantities of oil and gas
that might be recovered, but with a lower probability than probable
reserves). Statements of reserves are only estimates and may
not correspond to the ultimate quantities of oil and gas recovered.
Any reserve estimates provided in this press release that are not
specifically designated as being estimates of proved reserves may
include "potential" reserves and/or other estimated reserves not
necessarily calculated in accordance with, or contemplated by, the
SEC's latest reserve reporting guidelines. Investors are
urged to consider closely the disclosure in EOG's Annual Report on
Form 10-K for the fiscal year ended December
31, 2015, 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.
Investors
Cedric W. Burgher
(713) 571-4658
David J. Streit
(713) 571-4902
Media and Investors
Kimberly M. Ehmer
(713) 571-4676
EOG RESOURCES,
INC.
|
Financial
Report
|
(Unaudited; in
millions, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Nine Months
Ended
|
|
September
30,
|
|
September
30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Operating
Revenues
|
$
|
2,118.5
|
|
$
|
2,172.4
|
|
$
|
5,248.6
|
|
$
|
6,960.7
|
Net Loss
|
$
|
(190.0)
|
|
$
|
(4,075.7)
|
|
$
|
(954.3)
|
|
$
|
(4,240.2)
|
Net Loss Per
Share
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
$
|
(0.35)
|
|
$
|
(7.47)
|
|
$
|
(1.74)
|
|
$
|
(7.77)
|
Diluted
|
$
|
(0.35)
|
|
$
|
(7.47)
|
|
$
|
(1.74)
|
|
$
|
(7.77)
|
Average Number of
Common Shares
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
547.8
|
|
|
545.9
|
|
|
547.3
|
|
|
545.5
|
Diluted
|
|
547.8
|
|
|
545.9
|
|
|
547.3
|
|
|
545.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Summary Income
Statements
|
(Unaudited; in
thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Nine Months
Ended
|
|
September
30,
|
|
September
30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Net Operating
Revenues
|
|
|
|
|
|
|
|
Crude Oil
and Condensate
|
$
|
1,137,717
|
|
$
|
1,181,092
|
|
$
|
2,951,118
|
|
$
|
3,894,092
|
Natural
Gas Liquids
|
|
112,439
|
|
|
95,217
|
|
|
299,401
|
|
|
311,137
|
Natural
Gas
|
|
205,293
|
|
|
281,837
|
|
|
526,779
|
|
|
843,657
|
Gains
(Losses) on Mark-to-Market Commodity
Derivative Contracts
|
|
5,117
|
|
|
29,239
|
|
|
(33,821)
|
|
|
56,954
|
Gathering,
Processing and Marketing
|
|
532,456
|
|
|
572,217
|
|
|
1,351,665
|
|
|
1,820,843
|
Gains
(Losses) on Asset Dispositions, Net
|
|
108,204
|
|
|
(1,185)
|
|
|
101,801
|
|
|
(5,142)
|
Other,
Net
|
|
17,278
|
|
|
14,011
|
|
|
51,650
|
|
|
39,126
|
Total
|
|
2,118,504
|
|
|
2,172,428
|
|
|
5,248,593
|
|
|
6,960,667
|
Operating
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
Lease and
Well
|
|
226,348
|
|
|
283,221
|
|
|
685,606
|
|
|
934,366
|
Transportation Costs
|
|
200,862
|
|
|
203,594
|
|
|
570,787
|
|
|
641,739
|
Gathering
and Processing Costs
|
|
32,635
|
|
|
35,497
|
|
|
90,385
|
|
|
106,503
|
Exploration Costs
|
|
25,455
|
|
|
31,344
|
|
|
85,843
|
|
|
114,548
|
Dry Hole
Costs
|
|
10,390
|
|
|
198
|
|
|
10,464
|
|
|
14,317
|
Impairments
|
|
177,990
|
|
|
6,307,420
|
|
|
322,321
|
|
|
6,445,375
|
Marketing
Costs
|
|
552,487
|
|
|
615,303
|
|
|
1,373,387
|
|
|
1,924,134
|
Depreciation, Depletion and Amortization
|
|
899,511
|
|
|
722,172
|
|
|
2,690,893
|
|
|
2,544,187
|
General
and Administrative
|
|
94,397
|
|
|
90,959
|
|
|
292,633
|
|
|
257,580
|
Taxes
Other Than Income
|
|
91,909
|
|
|
105,677
|
|
|
246,068
|
|
|
334,244
|
Total
|
|
2,311,984
|
|
|
8,395,385
|
|
|
6,368,387
|
|
|
13,316,993
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Loss
|
|
(193,480)
|
|
|
(6,222,957)
|
|
|
(1,119,794)
|
|
|
(6,356,326)
|
|
|
|
|
|
|
|
|
|
|
|
|
Other (Expense)
Income, Net
|
|
(7,912)
|
|
|
8,607
|
|
|
(33,345)
|
|
|
7,996
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss Before Interest
Expense and Income Taxes
|
|
(201,392)
|
|
|
(6,214,350)
|
|
|
(1,153,139)
|
|
|
(6,348,330)
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense,
Net
|
|
70,858
|
|
|
60,571
|
|
|
210,356
|
|
|
174,400
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss Before Income
Taxes
|
|
(272,250)
|
|
|
(6,274,921)
|
|
|
(1,363,495)
|
|
|
(6,522,730)
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax
Benefit
|
|
(82,250)
|
|
|
(2,199,182)
|
|
|
(409,161)
|
|
|
(2,282,511)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Loss
|
$
|
(190,000)
|
|
$
|
(4,075,739)
|
|
$
|
(954,334)
|
|
$
|
(4,240,219)
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends Declared
per Common Share
|
$
|
0.1675
|
|
$
|
0.1675
|
|
$
|
0.5025
|
|
$
|
0.5025
|
EOG RESOURCES,
INC.
|
|
Operating
Highlights
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Nine Months
Ended
|
|
|
September
30,
|
|
September
30,
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
Wellhead Volumes
and Prices
|
|
|
|
|
Crude Oil and
Condensate Volumes (MBbld) (A)
|
|
|
|
|
United
States
|
|
275.7
|
|
|
278.3
|
|
|
269.0
|
|
|
284.4
|
|
Trinidad
|
|
0.7
|
|
|
1.0
|
|
|
0.8
|
|
|
0.9
|
|
Other International
(B)
|
|
6.2
|
|
|
0.2
|
|
|
3.0
|
|
|
0.2
|
|
Total
|
|
282.6
|
|
|
279.5
|
|
|
272.8
|
|
|
285.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Crude Oil and
Condensate Prices ($/Bbl) (C)
|
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$
|
43.66
|
|
$
|
45.93
|
|
$
|
39.53
|
|
$
|
49.94
|
|
Trinidad
|
|
34.81
|
|
|
38.56
|
|
|
31.36
|
|
|
41.98
|
|
Other International
(B)
|
|
43.53
|
|
|
61.80
|
|
|
35.30
|
|
|
58.44
|
|
Composite
|
|
43.63
|
|
|
45.91
|
|
|
39.46
|
|
|
49.92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids
Volumes (MBbld) (A)
|
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
|
81.9
|
|
|
77.7
|
|
|
81.9
|
|
|
76.2
|
|
Other International
(B)
|
|
-
|
|
|
0.1
|
|
|
-
|
|
|
0.1
|
|
Total
|
|
81.9
|
|
|
77.8
|
|
|
81.9
|
|
|
76.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Natural Gas
Liquids Prices ($/Bbl) (C)
|
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$
|
14.92
|
|
$
|
13.25
|
|
$
|
13.34
|
|
$
|
14.94
|
|
Other International
(B)
|
|
-
|
|
|
8.05
|
|
|
-
|
|
|
6.05
|
|
Composite
|
|
14.92
|
|
|
13.24
|
|
|
13.34
|
|
|
14.93
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Volumes
(MMcfd) (A)
|
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
|
791
|
|
|
889
|
|
|
813
|
|
|
895
|
|
Trinidad
|
|
329
|
|
|
355
|
|
|
346
|
|
|
342
|
|
Other International
(B)
|
|
24
|
|
|
30
|
|
|
25
|
|
|
31
|
|
Total
|
|
1,144
|
|
|
1,274
|
|
|
1,184
|
|
|
1,268
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Natural Gas
Prices ($/Mcf) (C)
|
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$
|
1.94
|
|
$
|
2.04
|
|
$
|
1.46
|
|
$
|
2.14
|
|
Trinidad
|
|
1.86
|
|
|
2.90
|
|
|
1.88
|
|
|
3.01
|
|
Other International
(B)
|
|
3.74
|
|
|
7.18
|
(E)
|
|
3.57
|
|
|
4.63
|
(E)
|
Composite
|
|
1.95
|
|
|
2.40
|
|
|
1.62
|
|
|
2.44
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Equivalent
Volumes (MBoed) (D)
|
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
|
489.4
|
|
|
504.2
|
|
|
486.4
|
|
|
509.8
|
|
Trinidad
|
|
55.6
|
|
|
60.2
|
|
|
58.5
|
|
|
57.9
|
|
Other International
(B)
|
|
10.2
|
|
|
5.2
|
|
|
7.2
|
|
|
5.4
|
|
Total
|
|
555.2
|
|
|
569.6
|
|
|
552.1
|
|
|
573.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total MMBoe
(D)
|
|
51.1
|
|
|
52.4
|
|
|
151.3
|
|
|
156.5
|
|
|
(A) Thousand barrels
per day or million cubic feet per day, as applicable.
|
(B) Other
International includes EOG's United Kingdom, China and Canada
operations.
|
(C) Dollars per
barrel or per thousand cubic feet, as applicable. Excludes
the impact of financial commodity derivative
instruments.
|
(D) Thousand barrels
of oil equivalent per day or million barrels of oil equivalent, as
applicable; includes crude oil and condensate, natural gas liquids
and natural gas. Crude oil equivalent volumes are determined
using a ratio of 1.0 barrel of crude oil and condensate or natural
gas liquids to 6.0 thousand cubic feet of natural gas. MMBoe
is calculated by multiplying the MBoed amount by the number of days
in the period and then dividing that amount by one
thousand.
|
(E) Includes revenue
adjustment of $3.62 per Mcf and $1.19 per Mcf for the quarter and
year-to-date, respectively, related to a price adjustment for
natural gas sales made in China from June 2012 to March
2015.
|
EOG RESOURCES,
INC.
|
Summary Balance
Sheets
|
(Unaudited; in
thousands, except share data)
|
|
|
|
|
|
|
|
September
30,
|
|
December
31,
|
|
2016
|
|
2015
|
ASSETS
|
Current
Assets
|
|
|
|
|
|
Cash and Cash
Equivalents
|
$
|
1,048,727
|
|
$
|
718,506
|
Accounts Receivable,
Net
|
|
920,189
|
|
|
930,610
|
Inventories
|
|
429,667
|
|
|
598,935
|
Assets from Price Risk
Management Activities
|
|
2,185
|
|
|
-
|
Income Taxes
Receivable
|
|
178
|
|
|
40,704
|
Deferred Income
Taxes
|
|
137,098
|
|
|
147,812
|
Other
|
|
199,720
|
|
|
155,677
|
Total
|
|
2,737,764
|
|
|
2,592,244
|
|
|
|
|
|
|
Property, Plant
and Equipment
|
|
|
|
|
|
Oil and Gas Properties
(Successful Efforts Method)
|
|
50,465,979
|
|
|
50,613,241
|
Other Property, Plant and
Equipment
|
|
4,013,602
|
|
|
3,986,610
|
Total Property, Plant and Equipment
|
|
54,479,581
|
|
|
54,599,851
|
Less: Accumulated
Depreciation, Depletion and Amortization
|
|
(31,835,196)
|
|
|
(30,389,130)
|
Total Property, Plant and Equipment, Net
|
|
22,644,385
|
|
|
24,210,721
|
Other
Assets
|
|
172,772
|
|
|
167,505
|
Total
Assets
|
$
|
25,554,921
|
|
$
|
26,970,470
|
|
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS' EQUITY
|
Current
Liabilities
|
|
|
|
|
|
Accounts Payable
|
$
|
1,296,240
|
|
$
|
1,471,953
|
Accrued Taxes
Payable
|
|
143,257
|
|
|
93,618
|
Dividends Payable
|
|
91,842
|
|
|
91,546
|
Current Portion of Long-Term
Debt
|
|
6,579
|
|
|
6,579
|
Other
|
|
195,045
|
|
|
155,591
|
Total
|
|
1,732,963
|
|
|
1,819,287
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term
Debt
|
|
6,979,538
|
|
|
6,648,911
|
Other
Liabilities
|
|
975,763
|
|
|
971,335
|
Deferred Income
Taxes
|
|
4,068,345
|
|
|
4,587,902
|
Commitments and
Contingencies
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders'
Equity
|
|
|
|
|
|
Common Stock, $0.01 Par,
640,000,000 Shares Authorized and
|
|
|
|
|
|
551,425,785
Shares Issued at September 30, 2016 and 550,150,823
|
|
|
|
|
|
Shares
Issued at December 31, 2015
|
|
205,514
|
|
|
205,502
|
Additional Paid in
Capital
|
|
2,992,887
|
|
|
2,923,461
|
Accumulated Other
Comprehensive Loss
|
|
(25,100)
|
|
|
(33,338)
|
Retained Earnings
|
|
8,641,704
|
|
|
9,870,816
|
Common Stock Held in
Treasury, 197,181 Shares at September 30, 2016
|
|
|
|
|
|
and
292,179 Shares at December 31, 2015
|
|
(16,693)
|
|
|
(23,406)
|
Total Stockholders' Equity
|
|
11,798,312
|
|
|
12,943,035
|
Total Liabilities
and Stockholders' Equity
|
$
|
25,554,921
|
|
$
|
26,970,470
|
EOG RESOURCES,
INC.
|
Summary Statements
of Cash Flows
|
(Unaudited; in
thousands)
|
|
|
|
|
|
|
|
Nine Months
Ended
|
|
September
30,
|
|
2016
|
|
2015
|
Cash Flows from
Operating Activities
|
|
|
|
|
|
Reconciliation of Net
Loss to Net Cash Provided by Operating Activities:
|
|
|
|
|
|
Net Loss
|
$
|
(954,334)
|
|
$
|
(4,240,219)
|
Items Not Requiring
(Providing) Cash
|
|
|
|
|
|
Depreciation, Depletion and Amortization
|
|
2,690,893
|
|
|
2,544,187
|
Impairments
|
|
322,321
|
|
|
6,445,375
|
Stock-Based Compensation Expenses
|
|
97,072
|
|
|
101,926
|
Deferred Income Taxes
|
|
(492,489)
|
|
|
(2,377,030)
|
(Gains) Losses on Asset Dispositions, Net
|
|
(101,801)
|
|
|
5,142
|
Other, Net
|
|
42,149
|
|
|
3,735
|
Dry Hole Costs
|
|
10,464
|
|
|
14,317
|
Mark-to-Market Commodity
Derivative Contracts
|
|
|
|
|
|
Total Losses (Gains)
|
|
33,821
|
|
|
(56,954)
|
Net Cash (Payments for) Received from Settlements of Commodity
Derivative Contracts
|
|
(22,219)
|
|
|
661,021
|
Excess Tax Benefits from
Stock-Based Compensation
|
|
(22,071)
|
|
|
(24,219)
|
Other, Net
|
|
7,513
|
|
|
8,904
|
Changes in Components of
Working Capital and Other Assets and Liabilities
|
|
|
|
|
|
Accounts Receivable
|
|
(11,860)
|
|
|
448,311
|
Inventories
|
|
137,563
|
|
|
27,007
|
Accounts Payable
|
|
(201,213)
|
|
|
(1,310,211)
|
Accrued Taxes Payable
|
|
113,996
|
|
|
77,575
|
Other Assets
|
|
(12,526)
|
|
|
146,965
|
Other Liabilities
|
|
36,799
|
|
|
(15,683)
|
Changes in Components of
Working Capital Associated with Investing and Financing
Activities
|
|
(119,760)
|
|
|
519,203
|
Net Cash Provided
by Operating Activities
|
|
1,554,318
|
|
|
2,979,352
|
|
|
|
|
|
|
Investing Cash
Flows
|
|
|
|
|
|
Additions to Oil and Gas
Properties
|
|
(1,781,547)
|
|
|
(3,918,065)
|
Additions to Other Property,
Plant and Equipment
|
|
(60,343)
|
|
|
(252,295)
|
Proceeds from Sales of
Assets
|
|
457,665
|
|
|
144,285
|
Changes in Components of
Working Capital Associated with Investing Activities
|
|
120,614
|
|
|
(519,323)
|
Net Cash Used in
Investing Activities
|
|
(1,263,611)
|
|
|
(4,545,398)
|
|
|
|
|
|
|
Financing Cash
Flows
|
|
|
|
|
|
Net Commercial Paper
(Repayments) Borrowings
|
|
(259,718)
|
|
|
29,700
|
Long-Term Debt
Borrowings
|
|
991,097
|
|
|
990,225
|
Long-Term Debt
Repayments
|
|
(400,000)
|
|
|
(500,000)
|
Dividends Paid
|
|
(276,726)
|
|
|
(274,577)
|
Excess Tax Benefits from
Stock-Based Compensation
|
|
22,071
|
|
|
24,219
|
Treasury Stock
Purchased
|
|
(55,641)
|
|
|
(43,419)
|
Proceeds from Stock Options
Exercised and Employee Stock Purchase Plan
|
|
14,283
|
|
|
14,967
|
Debt Issuance
Costs
|
|
(1,602)
|
|
|
(5,933)
|
Repayment of Capital Lease
Obligation
|
|
(4,746)
|
|
|
(4,599)
|
Other, Net
|
|
(854)
|
|
|
120
|
Net Cash Provided
by Financing Activities
|
|
28,164
|
|
|
230,703
|
|
|
|
|
|
|
Effect of Exchange
Rate Changes on Cash
|
|
11,350
|
|
|
(9,181)
|
|
|
|
|
|
|
Increase
(Decrease) in Cash and Cash Equivalents
|
|
330,221
|
|
|
(1,344,524)
|
Cash and Cash
Equivalents at Beginning of Period
|
|
718,506
|
|
|
2,087,213
|
Cash and Cash
Equivalents at End of Period
|
$
|
1,048,727
|
|
$
|
742,689
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Adjusted Net Income (Loss)
(Non-GAAP)
|
to Net Loss
(GAAP)
|
(Unaudited; in
thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following chart
adjusts the three-month and nine-month periods ended September 30,
2016 and 2015 reported Net Loss (GAAP) to reflect actual net cash
received from (payments for) settlements of commodity derivative
contracts by eliminating the unrealized mark-to-market (gains)
losses from these transactions, to eliminate the net (gains) losses
on asset dispositions in 2016 and 2015, to eliminate the impact of
the Texas margin tax rate reduction in 2015, to add back severance
costs associated with EOG's North American operations in 2015, to
eliminate the impact of the Trinidad tax settlement in 2016, to add
back certain voluntary retirement expense in 2016, to add back
impairment charges related to certain of EOG's assets in 2016 and
2015, and to add back acquisition costs related to the Yates
transaction in 2016. 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
|
|
September 30,
2016
|
|
September 30,
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
|
|
|
|
Diluted
|
|
|
|
Income
|
|
|
|
Diluted
|
|
Before
|
|
Tax
|
|
After
|
|
Earnings
|
|
Before
|
|
Tax
|
|
After
|
|
Earnings
|
|
Tax
|
|
Impact
|
|
Tax
|
|
per
Share
|
|
Tax
|
|
Impact
|
|
Tax
|
|
per
Share
|
Reported Net Loss
(GAAP)
|
$
(272,250)
|
|
$
82,250
|
|
$
(190,000)
|
|
$
(0.35)
|
|
$
(6,274,921)
|
|
$
2,199,182
|
|
$
(4,075,739)
|
|
$
(7.47)
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Gains) Losses
on Mark-to-Market Commodity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative
Contracts
|
(5,117)
|
|
1,824
|
|
(3,293)
|
|
(0.01)
|
|
(29,239)
|
|
10,424
|
|
(18,815)
|
|
(0.03)
|
Net Cash
Received from (Payments for)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Settlements of Commodity
Derivative
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contracts
|
(25,071)
|
|
8,938
|
|
(16,133)
|
|
(0.03)
|
|
99,879
|
|
(35,607)
|
|
64,272
|
|
0.12
|
Add: Net
(Gains) Losses on Asset Dispositions
|
(108,204)
|
|
28,802
|
|
(79,402)
|
|
(0.13)
|
|
1,185
|
|
(4,614)
|
|
(3,429)
|
|
(0.01)
|
Add:
Impairments of Certain Assets
|
102,778
|
|
(36,640)
|
|
66,138
|
|
0.12
|
|
6,213,107
|
|
(2,165,884)
|
|
4,047,223
|
|
7.41
|
Add:
Acquisition Costs
|
2,927
|
|
(1,043)
|
|
1,884
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
Adjustments to Net
Income (Loss)
|
(32,687)
|
|
1,881
|
|
(30,806)
|
|
(0.05)
|
|
6,284,932
|
|
(2,195,681)
|
|
4,089,251
|
|
7.49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Net
Income (Loss) (Non-GAAP)
|
$
(304,937)
|
|
$
84,131
|
|
$
(220,806)
|
|
$
(0.40)
|
|
$
10,011
|
|
$
3,501
|
|
$
13,512
|
|
$
0.02
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Number of
Common Shares (GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
547,838
|
|
|
|
|
|
|
|
545,920
|
Diluted
|
|
|
|
|
|
|
547,838
|
|
|
|
|
|
|
|
545,920
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Number of
Common Shares (Non-GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
547,838
|
|
|
|
|
|
|
|
545,920
|
Diluted
|
|
|
|
|
|
|
547,838
|
|
|
|
|
|
|
|
549,434
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months
Ended
|
|
Nine Months
Ended
|
|
September 30,
2016
|
|
September 30,
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
|
|
|
|
Diluted
|
|
|
|
Income
|
|
|
|
Diluted
|
|
Before
|
|
Tax
|
|
After
|
|
Earnings
|
|
Before
|
|
Tax
|
|
After
|
|
Earnings
|
|
Tax
|
|
Impact
|
|
Tax
|
|
per
Share
|
|
Tax
|
|
Impact
|
|
Tax
|
|
per
Share
|
Reported Net Loss
(GAAP)
|
$
(1,363,495)
|
|
$
409,161
|
|
$
(954,334)
|
|
$
(1.74)
|
|
$
(6,522,730)
|
|
$
2,282,511
|
|
$
(4,240,219)
|
|
$
(7.77)
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Gains) Losses
on Mark-to-Market Commodity
Derivative Contracts
|
33,821
|
|
(12,057)
|
|
21,764
|
|
0.04
|
|
(56,954)
|
|
20,304
|
|
(36,650)
|
|
(0.07)
|
Net Cash
Received from (Payments for)
Settlements of Commodity Derivative
Contracts
|
(22,219)
|
|
7,921
|
|
(14,298)
|
|
(0.03)
|
|
661,021
|
|
(235,654)
|
|
425,367
|
|
0.79
|
Add: Net
(Gains) Losses on Asset Dispositions
|
(101,801)
|
|
24,635
|
|
(77,166)
|
|
(0.14)
|
|
5,142
|
|
(3,448)
|
|
1,694
|
|
-
|
Less: Texas
Margin Tax Rate Reduction
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(19,500)
|
|
(19,500)
|
|
(0.04)
|
Add:
Severance Costs
|
-
|
|
-
|
|
-
|
|
-
|
|
8,505
|
|
(3,032)
|
|
5,473
|
|
0.01
|
Add:
Trinidad Tax Settlement
|
-
|
|
43,000
|
|
43,000
|
|
0.08
|
|
-
|
|
-
|
|
-
|
|
-
|
Add:
Voluntary Retirement Expense
|
42,054
|
|
(14,992)
|
|
27,062
|
|
0.05
|
|
-
|
|
-
|
|
-
|
|
-
|
Add:
Impairments of Certain Assets
|
102,778
|
|
(36,640)
|
|
66,138
|
|
0.12
|
|
6,213,107
|
|
(2,165,884)
|
|
4,047,223
|
|
7.41
|
Add:
Acquisition Costs
|
2,927
|
|
(1,043)
|
|
1,884
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
Adjustments to Net
Income (Loss)
|
57,560
|
|
10,824
|
|
68,384
|
|
0.12
|
|
6,830,821
|
|
(2,407,214)
|
|
4,423,607
|
|
8.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Net
Income (Loss) (Non-GAAP)
|
$
(1,305,935)
|
|
$
419,985
|
|
$
(885,950)
|
|
$
(1.62)
|
|
$
308,091
|
|
$
(124,703)
|
|
$
183,388
|
|
$
0.33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Number of
Common Shares (GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
547,295
|
|
|
|
|
|
|
|
545,466
|
Diluted
|
|
|
|
|
|
|
547,295
|
|
|
|
|
|
|
|
545,466
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Number of
Common Shares (Non-GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
547,295
|
|
|
|
|
|
|
|
545,466
|
Diluted
|
|
|
|
|
|
|
547,295
|
|
|
|
|
|
|
|
549,414
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Discretionary Cash Flow (Non-GAAP)
|
to Net Cash
Provided By Operating Activities (GAAP)
|
(Unaudited; in
thousands)
|
|
The following chart
reconciles the three-month and nine-month periods ended September
30, 2016 and 2015 Net Cash Provided by Operating Activities (GAAP)
to Discretionary Cash Flow (Non-GAAP). EOG believes this
presentation may be useful to investors who follow the practice of
some industry analysts who adjust Net Cash Provided by Operating
Activities for Exploration Costs (excluding Stock-Based
Compensation Expenses), Excess Tax Benefits from Stock-Based
Compensation, Changes in Components of Working Capital and Other
Assets and Liabilities, and Changes in Components of Working
Capital Associated with Investing and Financing Activities.
EOG management uses this information for comparative purposes
within the industry.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Nine Months
Ended
|
|
|
September
30,
|
|
September
30,
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by
Operating Activities (GAAP)
|
$
|
759,581
|
|
$
|
1,131,432
|
|
$
|
1,554,318
|
|
$
|
2,979,352
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration Costs
(excluding Stock-Based Compensation Expenses)
|
|
21,384
|
|
|
25,286
|
|
|
70,268
|
|
|
95,253
|
Excess Tax Benefits
from Stock-Based Compensation
|
|
|
10,260
|
|
|
7,826
|
|
|
22,071
|
|
|
24,219
|
Changes in Components
of Working Capital and Other Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
and
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
Receivable
|
|
|
(10,712)
|
|
|
(150,128)
|
|
|
11,860
|
|
|
(448,311)
|
Inventories
|
|
|
(41,750)
|
|
|
10,602
|
|
|
(137,563)
|
|
|
(27,007)
|
Accounts
Payable
|
|
|
(2,145)
|
|
|
310,567
|
|
|
201,213
|
|
|
1,310,211
|
Accrued Taxes
Payable
|
|
|
(20,676)
|
|
|
(13,451)
|
|
|
(113,996)
|
|
|
(77,575)
|
Other
Assets
|
|
|
(21,063)
|
|
|
(70,851)
|
|
|
12,526
|
|
|
(146,965)
|
Other
Liabilities
|
|
|
(35,234)
|
|
|
(33,165)
|
|
|
(36,799)
|
|
|
15,683
|
Changes in Components
of Working Capital Associated with
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing and
Financing Activities
|
|
|
65,307
|
|
|
(349,401)
|
|
|
119,760
|
|
|
(519,203)
|
|
Discretionary Cash
Flow (Non-GAAP)
|
|
$
|
724,952
|
|
$
|
868,717
|
|
$
|
1,703,658
|
|
$
|
3,205,657
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discretionary Cash
Flow (Non-GAAP) - Percentage Decrease
|
|
|
-17%
|
|
|
|
|
|
-47%
|
|
|
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Adjusted Earnings Before Interest
Expense,
|
Income Taxes,
Depreciation, Depletion and Amortization, Exploration
Costs,
|
Dry Hole Costs,
Impairments and Additional Items (Adjusted EBITDAX)
|
(Non-GAAP)
to Net Loss (GAAP)
|
(Unaudited; in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
The following chart
adjusts the three-month and nine-month periods ended September 30,
2016 and 2015 reported Net Loss (GAAP) to Earnings Before Interest
Expense, Income Taxes, Depreciation, Depletion and Amortization,
Exploration Costs, Dry Hole Costs and Impairments (EBITDAX)
(Non-GAAP) and further adjusts such amount to reflect actual net
cash received from (payments for) settlements of commodity
derivative contracts by eliminating the unrealized mark-to-market
(MTM) (gains) losses from these transactions and to eliminate the
net (gains) losses on asset dispositions. EOG believes this
presentation may be useful to investors who follow the practice of
some industry analysts who adjust reported Net Income (Loss) (GAAP)
to add back Interest Expense, Income Taxes (Income Tax Benefit),
Depreciation, Depletion and Amortization, Exploration Costs, Dry
Hole Costs and Impairments and further adjust such amount to match
realizations to production settlement months and make certain other
adjustments to exclude non-recurring and certain other items.
EOG management uses this information for purposes of comparing its
financial performance with the financial performance of other
companies in the industry.
|
|
|
Three Months
Ended
|
|
Nine Months
Ended
|
|
September
30,
|
|
September
30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss
(GAAP)
|
$
|
(190,000)
|
|
$
|
(4,075,739)
|
|
$
|
(954,334)
|
|
$
|
(4,240,219)
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense,
Net
|
|
70,858
|
|
|
60,571
|
|
|
210,356
|
|
|
174,400
|
Income Tax
Benefit
|
|
(82,250)
|
|
|
(2,199,182)
|
|
|
(409,161)
|
|
|
(2,282,511)
|
Depreciation, Depletion and
Amortization
|
|
899,511
|
|
|
722,172
|
|
|
2,690,893
|
|
|
2,544,187
|
Exploration Costs
|
|
25,455
|
|
|
31,344
|
|
|
85,843
|
|
|
114,548
|
Dry Hole Costs
|
|
10,390
|
|
|
198
|
|
|
10,464
|
|
|
14,317
|
Impairments
|
|
177,990
|
|
|
6,307,420
|
|
|
322,321
|
|
|
6,445,375
|
EBITDAX (Non-GAAP)
|
|
911,954
|
|
|
846,784
|
|
|
1,956,382
|
|
|
2,770,097
|
Total (Gains) Losses on MTM
Commodity Derivative Contracts
|
|
(5,117)
|
|
|
(29,239)
|
|
|
33,821
|
|
|
(56,954)
|
Net Cash Received from (Payments for) Settlements of
Commodity
|
|
|
|
|
|
|
|
|
|
|
|
Derivative
Contracts
|
|
(25,071)
|
|
|
99,879
|
|
|
(22,219)
|
|
|
661,021
|
(Gains) Losses on Asset
Dispositions, Net
|
|
(108,204)
|
|
|
1,185
|
|
|
(101,801)
|
|
|
5,142
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX
(Non-GAAP)
|
$
|
773,562
|
|
$
|
918,609
|
|
$
|
1,866,183
|
|
$
|
3,379,306
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX
(Non-GAAP) - Percentage Decrease
|
|
-16%
|
|
|
|
|
|
-45%
|
|
|
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Net Debt (Non-GAAP) and Total
|
Capitalization
(Non-GAAP) as Used in the Calculation of
|
the Net
Debt-to-Total Capitalization Ratio (Non-GAAP) to
|
Current and
Long-Term Debt (GAAP) and Total Capitalization
(GAAP)
|
(Unaudited; in
millions, except ratio data)
|
|
|
|
|
|
|
The following chart
reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP)
and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP),
as used in the Net Debt-to-Total Capitalization ratio
calculation. A portion of the cash is associated with
international subsidiaries; tax considerations may impact debt
paydown. EOG believes this presentation may be useful to
investors who follow the practice of some industry analysts who
utilize Net Debt and Total Capitalization (Non-GAAP) in their Net
Debt-to-Total Capitalization ratio calculation. EOG
management uses this information for comparative purposes within
the industry.
|
|
|
|
|
|
|
|
At
|
|
At
|
|
September
30,
|
|
December
31,
|
|
2016
|
|
2015
|
|
|
|
|
|
|
Total Stockholders'
Equity - (a)
|
$
|
11,798
|
|
$
|
12,943
|
|
|
|
|
|
|
Current and Long-Term
Debt (GAAP) - (b)
|
|
6,986
|
|
|
6,655
|
Less:
Cash
|
|
(1,049)
|
|
|
(719)
|
Net Debt (Non-GAAP) -
(c)
|
|
5,937
|
|
|
5,936
|
|
|
|
|
|
|
Total Capitalization
(GAAP) - (a) + (b)
|
$
|
18,784
|
|
$
|
19,598
|
|
|
|
|
|
|
Total Capitalization
(Non-GAAP) - (a) + (c)
|
$
|
17,735
|
|
$
|
18,879
|
|
|
|
|
|
|
Debt-to-Total
Capitalization (GAAP) - (b) / [(a) + (b)]
|
|
37%
|
|
|
34%
|
|
|
|
|
|
|
Net Debt-to-Total
Capitalization (Non-GAAP) - (c) / [(a) + (c)]
|
|
33%
|
|
|
31%
|
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. Presented below is a comprehensive summary
of EOG's crude oil price swap contracts through November 3, 2016,
with notional volumes expressed in Bbld and prices expressed in
$/Bbl.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Price
Swap Contracts
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Volume
|
|
Average
Price
|
|
|
|
|
|
|
|
|
|
(Bbld)
|
|
($/Bbl)
|
2016
|
|
|
|
|
|
|
|
|
|
|
April 12, 2016
through April 30, 2016 (closed)
|
|
|
|
|
|
|
90,000
|
|
$
42.30
|
May 1, 2016 through
June 30, 2016 (closed)
|
|
|
|
|
|
|
128,000
|
|
42.56
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EOG has entered into
crude oil collar contracts, which establish ceiling and floor
prices for the sale of notional volumes of crude oil as specified
in the collar contracts. The collars require that EOG pay the
difference between the ceiling price and the average NYMEX West
Texas Intermediate crude oil price for the contract month (Index
Price) in the event the Index Price is above the ceiling
price. The collars grant EOG the right to receive the
difference between the floor price and the Index Price in the event
the Index Price is below the floor price. Presented below is
a comprehensive summary of EOG's crude oil collar contracts through
November 3, 2016, with notional volumes expressed in Bbld and
prices expressed in $/Bbl.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Collar
Contracts
|
|
|
|
|
|
|
|
|
|
Weighted Average
Price ($/Bbl)
|
|
|
|
|
|
|
|
Volume
(Bbld)
|
|
Ceiling
Price
|
|
Floor
Price
|
2016
|
|
|
|
|
|
|
|
|
|
|
September 1, 2016
through October 31, 2016 (closed)
|
|
|
|
70,000
|
|
$
54.25
|
|
$
45.00
|
November 1, 2016
through December 31, 2016
|
|
|
|
|
70,000
|
|
54.25
|
|
45.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Presented below is a
comprehensive summary of EOG's natural gas price swap contracts
through November 3, 2016, with notional volumes expressed in MMBtud
and prices expressed in $/MMBtu.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Price
Swap Contracts
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Volume
|
|
Average
Price
|
|
|
|
|
|
|
|
|
|
(MMBtud)
|
|
($/MMBtu)
|
2016
|
|
|
|
|
|
|
|
|
|
|
March 1, 2016 through
August 31, 2016 (closed)
|
|
|
|
|
|
|
60,000
|
|
$
2.49
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
March 1, 2017 through
November 30, 2017
|
|
|
|
|
|
|
30,000
|
|
$
3.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EOG has sold call
options which establish a ceiling price for the sale of notional
volumes of natural gas as specified in the call option
contracts. The call options require that EOG pay the
difference between the call option strike price and either the
average or last business day NYMEX Henry Hub natural gas price for
the contract month (Henry Hub Index Price) in the event the Henry
Hub Index Price is above the call option strike price. In
addition, EOG has purchased put options which establish a floor
price for the sale of notional volumes of natural gas as specified
in the put option contracts. The put options grant EOG the
right to receive the difference between the put option strike price
and the Henry Hub Index Price in the event the Henry Hub Index
Price is below the put option strike price. Presented below
is a comprehensive summary of EOG's natural gas call and put option
contracts through November 3, 2016, 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)
|
2016
|
|
|
|
|
|
|
|
|
|
|
September 2016
(closed)
|
|
|
56,250
|
|
$
3.46
|
|
-
|
|
$
-
|
October 1, 2016
through November 30, 2016 (closed)
|
|
|
106,250
|
|
3.48
|
|
-
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
March 1, 2017 through
November 30, 2017
|
|
|
213,750
|
|
$
3.44
|
|
171,000
|
|
$
2.92
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
March 1, 2018 through
November 30, 2018
|
|
|
120,000
|
|
$
3.38
|
|
96,000
|
|
$
2.94
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Definitions
|
|
|
|
|
|
|
|
|
|
|
Bbld
|
Barrels per
day
|
|
|
|
|
|
|
|
|
|
$/Bbl
|
Dollars per
barrel
|
|
|
|
|
|
|
|
|
|
MMBtud
|
Million British
thermal units per day
|
|
|
|
|
|
|
|
|
|
$/MMBtu
|
Dollars per million
British thermal units
|
|
|
|
|
|
|
|
|
|
NYMEX
|
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 proved 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 (Loss)
(GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization
(GAAP), Respectively
|
(Unaudited; in
millions, except ratio data)
|
|
|
|
|
|
|
|
|
|
|
|
|
The following chart
reconciles Net Interest Expense (GAAP), Net Income (Loss) (GAAP),
Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP)
to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income
(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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015
|
|
|
2014
|
|
|
2013
|
|
|
2012
|
Return on Capital
Employed (ROCE) (Non-GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Interest Expense
(GAAP)
|
$
|
237
|
|
$
|
201
|
|
$
|
235
|
|
|
|
Tax Benefit Imputed
(based on 35%)
|
|
(83)
|
|
|
(70)
|
|
|
(82)
|
|
|
|
After-Tax Net
Interest Expense (Non-GAAP) - (a)
|
$
|
154
|
|
$
|
131
|
|
$
|
153
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
(GAAP) -
(b)
|
$
|
(4,525)
|
|
$
|
2,915
|
|
$
|
2,197
|
|
|
|
Adjustments to Net
Income (Loss), Net of Tax (See Accompanying Schedules)
|
4,559
|
(a)
|
|
(199)
|
(b)
|
|
49
|
(c)
|
|
|
Adjusted Net Income
(Non-GAAP) - (c)
|
$
|
34
|
|
$
|
2,716
|
|
$
|
2,246
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Stockholders'
Equity - (d)
|
$
|
12,943
|
|
$
|
17,713
|
|
$
|
15,418
|
|
$
|
13,285
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Total
Stockholders' Equity * - (e)
|
$
|
15,328
|
|
$
|
16,566
|
|
$
|
14,352
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current and Long-Term
Debt (GAAP) - (f)
|
$
|
6,660
|
|
$
|
5,910
|
|
$
|
5,913
|
|
$
|
6,312
|
Less:
Cash
|
|
(719)
|
|
|
(2,087)
|
|
|
(1,318)
|
|
|
(876)
|
Net Debt (Non-GAAP) -
(g)
|
$
|
5,941
|
|
$
|
3,823
|
|
$
|
4,595
|
|
$
|
5,436
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
(GAAP) - (d) + (f)
|
$
|
19,603
|
|
$
|
23,623
|
|
$
|
21,331
|
|
$
|
19,597
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
(Non-GAAP) - (d) + (g)
|
$
|
18,884
|
|
$
|
21,536
|
|
$
|
20,013
|
|
$
|
18,721
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Total
Capitalization (Non-GAAP) * - (h)
|
$
|
20,210
|
|
$
|
20,775
|
|
$
|
19,367
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROCE (GAAP Net
Income) - [(a) + (b)] /
(h)
|
|
-21.6%
|
|
|
14.7%
|
|
|
12.1%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROCE (Non-GAAP
Adjusted Net Income) - [(a) + (c)] /
(h)
|
|
0.9%
|
|
|
13.7%
|
|
|
12.4%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Return on Equity
(ROE) (Non-GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROE (GAAP Net
Income) - (b) / (e)
|
|
-29.5%
|
|
|
17.6%
|
|
|
15.3%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROE (Non-GAAP
Adjusted Net Income) - (c) / (e)
|
|
0.2%
|
|
|
16.4%
|
|
|
15.6%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* Average for the
current and immediately preceding year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments to Net
Income (Loss) (GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) See below
schedule for detail of adjustments to Net Income (Loss) (GAAP) in
2015:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31, 2015
|
|
|
|
|
|
Before
|
|
|
Income
Tax
|
|
|
After
|
|
|
|
|
|
Tax
|
|
|
Impact
|
|
|
Tax
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
Add: Mark-to-Market Commodity Derivative Contracts
Impact
|
$
|
668
|
|
$
|
(238)
|
|
$
|
430
|
|
|
|
Add: Impairments of Certain Assets
|
|
6,308
|
|
|
(2,183)
|
|
|
4,125
|
|
|
|
Less: Texas Margin Tax Rate Reduction
|
|
-
|
|
|
(20)
|
|
|
(20)
|
|
|
|
Add: Legal Settlement - Early Leasehold
Termination
|
|
19
|
|
|
(6)
|
|
|
13
|
|
|
|
Add: Severance Costs
|
|
9
|
|
|
(3)
|
|
|
6
|
|
|
|
Add: Net Losses on Asset Dispositions
|
|
9
|
|
|
(4)
|
|
|
5
|
|
|
|
Total
|
$
|
7,013
|
|
$
|
(2,454)
|
|
$
|
4,559
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(b) See below
schedule for detail of adjustments to Net Income (Loss) (GAAP) in
2014:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31, 2014
|
|
|
|
|
|
Before
|
|
|
Income
Tax
|
|
|
After
|
|
|
|
|
|
Tax
|
|
|
Impact
|
|
|
Tax
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
Less: Mark-to-Market Commodity Derivative Contracts
Impact
|
$
|
(800)
|
|
$
|
285
|
|
$
|
(515)
|
|
|
|
Add: Impairments of Certain Assets
|
|
824
|
|
|
(271)
|
|
|
553
|
|
|
|
Less: Net Gains on Asset Dispositions
|
|
(508)
|
|
|
21
|
|
|
(487)
|
|
|
|
Add: Tax Expense Related to the Repatriation of
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
Foreign Earnings in Future Years
|
|
-
|
|
|
250
|
|
|
250
|
|
|
|
Total
|
$
|
(484)
|
|
$
|
285
|
|
$
|
(199)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(c) See below
schedule for detail of adjustments to Net Income (Loss) (GAAP) in
2013:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31, 2013
|
|
|
|
|
|
Before
|
|
|
Income
Tax
|
|
|
After
|
|
|
|
|
|
Tax
|
|
|
Impact
|
|
|
Tax
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
Add: Mark-to-Market Commodity Derivative Contracts
Impact
|
$
|
283
|
|
$
|
(101)
|
|
$
|
182
|
|
|
|
Add: Impairments of Certain Assets
|
|
7
|
|
|
(3)
|
|
|
4
|
|
|
|
Less: Net Gains on Asset Dispositions
|
|
(198)
|
|
|
61
|
|
|
(137)
|
|
|
|
Total
|
$
|
92
|
|
$
|
(43)
|
|
$
|
49
|
|
|
|
EOG RESOURCES,
INC.
|
Fourth Quarter and
Full Year 2016 Forecast and Benchmark Commodity
Pricing
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Fourth Quarter and
Full Year 2016 Forecast
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The forecast items
for the fourth quarter and full year 2016 set forth below for EOG
Resources, Inc. (EOG) are based on current available information
and expectations as of the date of the accompanying press
release. EOG undertakes no obligation, other than as required
by applicable law, to update or revise this forecast, whether as a
result of new information, subsequent events, anticipated or
unanticipated circumstances or otherwise. This forecast,
which should be read in conjunction with the accompanying press
release and EOG's related Current Report on Form 8-K filing,
replaces and supersedes any previously issued guidance or
forecast.
|
|
|
|
|
|
|
|
|
|
|
|
|
(b) Benchmark
Commodity Pricing
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EOG bases United
States and Trinidad crude oil and condensate price differentials
upon the West Texas Intermediate crude oil price at Cushing,
Oklahoma, using the simple average of the NYMEX settlement prices
for each trading day within the applicable calendar
month.
|
|
|
|
|
|
|
|
|
|
|
|
|
EOG bases United
States natural gas price differentials upon the natural gas price
at Henry Hub, Louisiana, using the simple average of the NYMEX
settlement prices for the last three trading days of the applicable
month.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
Ranges
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
|
|
4Q 2016
|
|
|
Full Year
2016
|
Daily
Production
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil and Condensate
Volumes (MBbld)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
290.0
|
-
|
|
300.0
|
|
|
274.3
|
-
|
|
276.8
|
Trinidad
|
|
0.4
|
-
|
|
0.8
|
|
|
0.7
|
-
|
|
0.8
|
Other International
|
|
5.0
|
-
|
|
9.0
|
|
|
3.5
|
-
|
|
4.5
|
Total
|
|
295.4
|
-
|
|
309.8
|
|
|
278.5
|
-
|
|
282.1
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids Volumes
(MBbld)
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
79.0
|
-
|
|
83.0
|
|
|
81.1
|
-
|
|
82.2
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Volumes
(MMcfd)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
810
|
-
|
|
840
|
|
|
813
|
-
|
|
820
|
Trinidad
|
|
300
|
-
|
|
330
|
|
|
335
|
-
|
|
342
|
Other International
|
|
20
|
-
|
|
24
|
|
|
24
|
-
|
|
25
|
Total
|
|
1,130
|
-
|
|
1,194
|
|
|
1,172
|
-
|
|
1,187
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Equivalent Volumes
(MBoed)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
504.0
|
-
|
|
523.0
|
|
|
490.9
|
-
|
|
495.7
|
Trinidad
|
|
50.4
|
-
|
|
55.8
|
|
|
56.5
|
-
|
|
57.8
|
Other International
|
|
8.3
|
-
|
|
13.0
|
|
|
7.5
|
-
|
|
8.7
|
Total
|
|
562.7
|
-
|
|
591.8
|
|
|
554.9
|
-
|
|
562.2
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Costs
|
|
|
|
|
|
|
|
|
|
|
|
Unit Costs
($/Boe)
|
|
|
|
|
|
|
|
|
|
|
|
Lease and Well
|
$
|
4.40
|
-
|
$
|
4.90
|
|
$
|
4.50
|
-
|
$
|
4.66
|
Transportation Costs
|
$
|
3.75
|
-
|
$
|
4.25
|
|
$
|
3.77
|
-
|
$
|
3.90
|
Depreciation, Depletion and Amortization
|
$
|
17.70
|
-
|
$
|
18.10
|
|
$
|
17.77
|
-
|
$
|
17.87
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses
($MM)
|
|
|
|
|
|
|
|
|
|
|
|
Exploration, Dry Hole and
Impairment
|
$
|
105
|
-
|
$
|
135
|
|
$
|
421
|
-
|
$
|
451
|
General and
Administrative
|
$
|
90
|
-
|
$
|
100
|
|
$
|
338
|
-
|
$
|
348
|
Gathering and
Processing
|
$
|
29
|
-
|
$
|
31
|
|
$
|
119
|
-
|
$
|
121
|
Capitalized
Interest
|
$
|
33
|
-
|
$
|
37
|
|
$
|
58
|
-
|
$
|
62
|
Net Interest
|
$
|
41
|
-
|
$
|
44
|
|
$
|
251
|
-
|
$
|
254
|
|
|
|
|
|
|
|
|
|
|
|
|
Taxes Other Than
Income (% of Wellhead Revenue)
|
|
5.9%
|
-
|
|
6.3%
|
|
|
6.3%
|
-
|
|
6.5%
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Taxes
|
|
|
|
|
|
|
|
|
|
|
|
Effective
Rate
|
|
28%
|
-
|
|
33%
|
|
|
28%
|
-
|
|
33%
|
Current Taxes
($MM)
|
$
|
25
|
-
|
$
|
40
|
|
$
|
108
|
-
|
$
|
123
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures
(Excluding Acquisitions, $MM)
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and Development,
Excluding Facilities
|
|
|
|
|
|
|
$
|
2,200
|
-
|
$
|
2,300
|
Exploration and Development
Facilities
|
|
|
|
|
|
|
$
|
325
|
-
|
$
|
375
|
Gathering, Processing and
Other
|
|
|
|
|
|
|
$
|
75
|
-
|
$
|
125
|
|
|
|
|
|
|
|
|
|
|
|
|
Pricing - (Refer to
Benchmark Commodity Pricing in text)
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil and Condensate
($/Bbl)
|
|
|
|
|
|
|
|
|
|
|
|
Differentials
|
|
|
|
|
|
|
|
|
|
|
|
United States - above (below) WTI
|
$
|
(2.40)
|
-
|
$
|
(1.40)
|
|
$
|
(1.90)
|
-
|
$
|
(1.63)
|
Trinidad - above (below) WTI
|
$
|
(10.50)
|
-
|
$
|
(9.50)
|
|
$
|
(10.31)
|
-
|
$
|
(10.10)
|
Other International - above (below) WTI
|
$
|
(6.00)
|
-
|
$
|
(4.00)
|
|
$
|
(4.00)
|
-
|
$
|
(3.50)
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
Liquids
|
|
|
|
|
|
|
|
|
|
|
|
Realizations as % of WTI
|
|
29%
|
-
|
|
33%
|
|
|
31%
|
-
|
|
32%
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
($/Mcf)
|
|
|
|
|
|
|
|
|
|
|
|
Differentials
|
|
|
|
|
|
|
|
|
|
|
|
United States - above (below) NYMEX Henry Hub
|
$
|
(1.05)
|
-
|
$
|
(0.65)
|
|
$
|
(0.86)
|
-
|
$
|
(0.76)
|
|
|
|
|
|
|
|
|
|
|
|
|
Realizations
|
|
|
|
|
|
|
|
|
|
|
|
Trinidad
|
$
|
1.70
|
-
|
$
|
2.10
|
|
$
|
1.83
|
-
|
$
|
1.93
|
Other International
|
$
|
3.45
|
-
|
$
|
3.95
|
|
$
|
3.54
|
-
|
$
|
3.66
|
|
|
|
|
|
|
|
|
|
|
|
|
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 New York
Mercantile Exchange
|
|
|
|
|
|
|
|
|
|
|
|
WTI
West Texas Intermediate
|
|
|
|
|
|
|
|
|
|
|
|
To view the original version on PR Newswire,
visit:http://www.prnewswire.com/news-releases/eog-resources-announces-third-quarter-2016-results-raises-2020-outlook-and-more-than-doubles-permian-basin-net-resource-potential-300357223.html
SOURCE EOG Resources, Inc.