HOUSTON, Aug. 4, 2016 /PRNewswire/ --
- Increases Net Premium Inventory to 4,300 Locations and Total
Net Premium Resource Potential to 3.5 BnBoe
- Premium Inventory Well-Level Rates of Return Exceed 30 Percent
at $40 Crude Oil Price
- Beats All U.S. Production and Operating Cost Targets
- Raises 2016 U.S. Crude Oil Production Guidance
- Announces $425 Million in
Proceeds from Asset Sales
- Provides Crude Oil Production Growth Outlook through 2020
EOG Resources, Inc. (EOG) today reported a second quarter 2016
net loss of $292.6 million, or
$0.53 per share. This compares to
second quarter 2015 net income of $5.3
million, or $0.01 per
share.
Adjusted non-GAAP net loss for the second quarter 2016 was
$209.7 million, or $0.38 per share, compared to adjusted non-GAAP
net income of $153.1 million, or
$0.28 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
items. For a reconciliation of non-GAAP measures to GAAP
measures, please refer to the attached tables.
Lower commodity prices more than offset significant well
productivity improvements and cost reductions, resulting in
decreases in adjusted non-GAAP net income, discretionary cash flow
and EBITDAX during the second quarter 2016 compared to the second
quarter 2015. For a reconciliation of non-GAAP measures to
GAAP measures, please refer to the attached
tables.
Operational Highlights
In the second quarter 2016, EOG
increased its inventory of net premium drilling locations from
3,200 to 4,300. Premium inventory is defined by a direct
after-tax rate of return hurdle rate of at least 30 percent
assuming $40 flat crude oil
prices. Total premium net resource potential increased from
2.0 billion barrels of oil equivalent (BnBoe) to 3.5 BnBoe.
These additions were the result of advances in completion
technology, precision targeting, longer laterals and cost
reductions.
U.S. crude oil volumes of 265,400 barrels of oil per day (Bopd)
in the second quarter 2016 exceeded the midpoint of the company's
guidance by 2 percent. Compared to the same prior year period,
lease and well expenses decreased 23 percent, and transportation
costs decreased 13 percent, both on a per-unit basis. Total
general and administrative expenses decreased 5 percent compared to
the second quarter 2015, excluding expenses related to a voluntary
retirement program.
Exploration and development expenditures (excluding property
acquisitions) decreased 49 percent, while total crude oil
production declined by only 4 percent, in the second quarter 2016
compared to the same period last year. Total natural gas
production for the second quarter 2016 decreased 5 percent versus
the same prior year period.
"The benefits of EOG's premium drilling strategy are beginning
to show in our operating performance," said William R. "Bill"
Thomas, Chairman and Chief Executive Officer. "We are
committed to focusing capital on our premium assets which we are
confident will increasingly lead to break-out performance as prices
improve. This quarter's addition of 1.5 BnBoe of additional
premium net resource potential further solidifies our ability to
deliver premium returns over the long term."
2016 Capital Plan Update and 2020 Crude Oil Production
Outlook
As a result of cost reductions and efficiency
improvements, EOG has increased its targeted number of well
completions for 2016 from 270 to 350 net wells. Many of the
additional well completions are scheduled for late 2016. In
addition, due to increased drilling productivity, the company
expects to drill 250 net wells, 50 more than in its original 2016
plans. This increase in activity will be accomplished while
maintaining 2016 capital expenditure guidance of $2.4 to $2.6 billion, excluding
acquisitions.
EOG can achieve significant production growth with balanced cash
flow from 2017 through 2020, even in a moderate commodity price
environment. Based on EOG's long-term plan and assuming a
flat $50 West Texas Intermediate
crude oil price (WTI), EOG would expect 10 percent compound annual
crude oil production growth through 2020. Assuming flat
$60 WTI, EOG would expect 20 percent
compound annual crude oil production growth through 2020.
"EOG's long-term outlook reflects superior capital efficiency
and continued capital discipline, hallmarks of the company since
its founding," Thomas said. "Our premium drilling strategy is
the key to our future success, and it is underpinned by EOG's
industry-leading asset quality, scale, technology, well performance
and low-cost structure. Most importantly, EOG's
high-performance culture prioritizes rates of return over other
performance metrics."
South Texas Eagle Ford
The South Texas Eagle Ford,
EOG's largest high-return play, continues to lead the company in
activity and production. In the second quarter, EOG increased
its Eagle Ford premium inventory by 390 net drilling locations to
almost 2,000 total. This large inventory of high-quality
locations could be expanded significantly should additional cost
reductions or improvements in well productivity be achieved.
For example, EOG estimates that a 10 percent reduction in completed
well costs or a 10 percent improvement in estimated recoverable
reserves per well would more than double EOG's premium inventory in
the Eagle Ford.
In the second quarter, EOG completed 60 wells in the Eagle Ford
with an average treated lateral length of 4,800 feet per well and
an average 30-day initial production rate per well of 1,705 barrels
of oil equivalent per day (Boed), or 1,340 Bopd, 175 barrels per
day (Bpd) of natural gas liquids (NGLs) and 1.1 million cubic feet
per day (MMcfd) of natural gas.
Delaware Basin
In the
second quarter, EOG expanded its premium inventory in all three of
its major Delaware Basin
formations – the Wolfcamp, the Second Bone Spring and the
Leonard. By organically adding more than 500 net premium
drilling locations, EOG is well positioned for years of high-return
growth in this world-class basin. EOG continues to improve
well economics in the Delaware
Basin through advances in well and completion designs, including
recent breakthroughs that enable higher productivity with longer
laterals.
In the Delaware Basin Wolfcamp,
EOG completed 16 wells in the second quarter with an average
treated lateral length of 6,500 feet per well, a 44 percent
increase in lateral length from the prior quarter. The
average 30-day initial production rate per well was 2,410 Boed, or
1,610 Bopd, 340 Bpd of NGLs and 2.8 MMcfd of natural gas. In
the Delaware Basin Second Bone
Spring, EOG completed nine wells in the second quarter with an
average treated lateral length of 4,500 feet per well and an
average 30-day initial production rate per well of 1,500 Boed, or
1,120 Bopd, 155 Bpd of NGLs and 1.4 MMcfd of natural gas.
Rockies and the Bakken
EOG is continuing to optimize
its core Rockies and Bakken plays, adding 200 additional net
premium drilling locations to its inventory in the DJ Basin Codell
in Wyoming. The Codell is a liquids-rich sandstone formation
that now has significant premium potential due to cost reductions
and efficiencies along with the application of EOG's precision
targeting and completion technology.
In the DJ Basin Codell in Wyoming, EOG completed the Jubilee 541-3502H
well in the second quarter with average 30-day initial production
rates of 1,190 Bopd, 130 Bpd of NGLs and 0.5 MMcfd of natural gas.
In the Powder River Basin Turner, EOG completed the Arbalest
73-06H, 272-06H and 66-0607H wells on the same pad during the
second quarter with average 30-day initial production rates per
well of 1,000 Bopd, 330 Bpd of NGLs and 3.8 MMcfd of natural
gas.
In the North Dakota Bakken, EOG completed the Austin 421-2821H, 422-2821H and 423-2821H
wells in a three-well pattern in the second quarter with average
30-day initial production rates per well of 1,100 Bopd, 90 Bpd of
NGLs and 0.5 MMcfd of natural gas. Also in the North Dakota
Bakken, EOG completed the West Clark 103-0136H and 104-0136H wells
in a two-well pattern with average 30-day initial production rates
per well of 1,210 Bopd, 390 Bpd of NGLs and 1.8 MMcfd of natural
gas.
In the Three Forks, EOG completed the West Clark 117-0136H well
in the second quarter with average 30-day initial production rates
of 1,290 Bopd, 380 Bpd of NGLs and 1.8 MMcfd of natural
gas.
Hedging Activity
For the period March 1 through August 31, 2016, EOG had natural
gas financial price swap contracts in place for 60,000 million
British thermal units (MMBtu) per day at a weighted average price
of $2.49 per MMBtu.
For the period September 1 through
November 30, 2016, EOG sold natural gas call option
contracts for 43,750 MMBtu per day at an average strike price of
$3.45 per MMBtu. For the period
March 1 through November 30, 2017,
EOG sold natural gas call option contracts for 43,750 MMBtu per day
at an average strike price of $3.45
per MMBtu. For the period March 1
through November 30, 2018, EOG sold natural gas call option
contracts for 12,500 MMBtu per day at an average strike price of
$3.32 per MMBtu.
For the period March 1 through November
30, 2017, EOG purchased natural gas put option contracts for
35,000 MMBtu per day at an average strike price of $2.90 per MMBtu. For the period
March 1 through November 30, 2018,
EOG purchased natural gas put option contracts for 10,000 MMBtu per
day at an average strike price of $2.90 per MMBtu.
A comprehensive summary of natural gas derivative contracts is
provided in the attached tables.
Capital Structure and Asset Sales
At June 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 $780 million at the
end of the second quarter, EOG's net debt was $6.2 billion with a net debt-to-total
capitalization ratio of 34 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 $425 million. This includes proceeds from
two transactions that closed in the third quarter 2016. The
assets were divested in more than a dozen separate transactions of
non-core natural gas and liquids-rich properties. Associated
production of the divested assets was 45 MMcfd of natural gas,
3,300 Bopd and 3,700 Bpd of NGLs. Sales of additional
non-core assets are in progress and anticipated to close in
2016.
Conference Call August 5,
2016
EOG's second 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, August
5, 2016. To listen, log on to the Investors Overview
page on the EOG website at
http://investors.eogresources.com/overview. The webcast will
be archived on EOG's website through August
19, 2016.
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.
EOG RESOURCES,
INC.
|
Financial
Report
|
(Unaudited; in
millions, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Six Months
Ended
|
|
June
30,
|
|
June
30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Operating
Revenues
|
$
|
1,775.7
|
|
$
|
2,469.7
|
|
$
|
3,130.1
|
|
$
|
4,788.2
|
Net Income (
Loss)
|
$
|
(292.6)
|
|
$
|
5.3
|
|
$
|
(764.3)
|
|
$
|
(164.5)
|
Net Income (Loss) Per
Share
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
$
|
(0.53)
|
|
$
|
0.01
|
|
$
|
(1.40)
|
|
$
|
(0.30)
|
Diluted
|
$
|
(0.53)
|
|
$
|
0.01
|
|
$
|
(1.40)
|
|
$
|
(0.30)
|
Average Number of
Common Shares
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
547.3
|
|
|
545.5
|
|
|
547.0
|
|
|
545.2
|
Diluted
|
|
547.3
|
|
|
549.7
|
|
|
547.0
|
|
|
545.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Summary Income
Statements
|
(Unaudited; in
thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Six Months
Ended
|
|
June
30,
|
|
June
30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Net Operating
Revenues
|
|
|
|
|
|
|
|
Crude Oil
and Condensate
|
$
|
1,059,690
|
|
$
|
1,452,756
|
|
$
|
1,813,401
|
|
$
|
2,713,000
|
Natural
Gas Liquids
|
|
111,643
|
|
|
103,930
|
|
|
186,962
|
|
|
215,920
|
Natural
Gas
|
|
155,983
|
|
|
274,038
|
|
|
321,486
|
|
|
561,820
|
Gains
(Losses) on Mark-to-Market Commodity
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Contracts
|
|
(44,373)
|
|
|
(48,493)
|
|
|
(38,938)
|
|
|
27,715
|
Gathering,
Processing and Marketing
|
|
485,256
|
|
|
678,356
|
|
|
819,209
|
|
|
1,248,626
|
Losses on
Asset Dispositions, Net
|
|
(15,550)
|
|
|
(5,564)
|
|
|
(6,403)
|
|
|
(3,957)
|
Other,
Net
|
|
23,091
|
|
|
14,678
|
|
|
34,372
|
|
|
25,115
|
Total
|
|
1,775,740
|
|
|
2,469,701
|
|
|
3,130,089
|
|
|
4,788,239
|
Operating
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
Lease and
Well
|
|
218,393
|
|
|
289,664
|
|
|
459,258
|
|
|
651,145
|
Transportation Costs
|
|
179,471
|
|
|
209,833
|
|
|
369,925
|
|
|
438,145
|
Gathering
and Processing Costs
|
|
29,226
|
|
|
34,997
|
|
|
57,750
|
|
|
71,006
|
Exploration Costs
|
|
30,559
|
|
|
43,755
|
|
|
60,388
|
|
|
83,204
|
Dry Hole
Costs
|
|
(172)
|
|
|
(551)
|
|
|
74
|
|
|
14,119
|
Impairments
|
|
72,714
|
|
|
68,519
|
|
|
144,331
|
|
|
137,955
|
Marketing
Costs
|
|
480,046
|
|
|
670,169
|
|
|
820,900
|
|
|
1,308,831
|
Depreciation, Depletion and Amortization
|
|
862,491
|
|
|
909,227
|
|
|
1,791,382
|
|
|
1,822,015
|
General
and Administrative
|
|
97,705
|
|
|
82,324
|
|
|
198,236
|
|
|
166,621
|
Taxes
Other Than Income
|
|
93,480
|
|
|
122,138
|
|
|
154,159
|
|
|
228,567
|
Total
|
|
2,063,913
|
|
|
2,430,075
|
|
|
4,056,403
|
|
|
4,921,608
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
(Loss)
|
|
(288,173)
|
|
|
39,626
|
|
|
(926,314)
|
|
|
(133,369)
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income
(Expense), Net
|
|
(20,996)
|
|
|
9,380
|
|
|
(25,433)
|
|
|
(611)
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) Before
Interest Expense and Income Taxes
|
|
(309,169)
|
|
|
49,006
|
|
|
(951,747)
|
|
|
(133,980)
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense,
Net
|
|
71,108
|
|
|
60,484
|
|
|
139,498
|
|
|
113,829
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss Before Income
Taxes
|
|
(380,277)
|
|
|
(11,478)
|
|
|
(1,091,245)
|
|
|
(247,809)
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax
Benefit
|
|
(87,719)
|
|
|
(16,746)
|
|
|
(326,911)
|
|
|
(83,329)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
(Loss)
|
$
|
(292,558)
|
|
$
|
5,268
|
|
$
|
(764,334)
|
|
$
|
(164,480)
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends Declared
per Common Share
|
$
|
0.1675
|
|
$
|
0.1675
|
|
$
|
0.3350
|
|
$
|
0.3350
|
EOG RESOURCES,
INC.
|
Operating
Highlights
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Six Months
Ended
|
|
June
30,
|
|
June
30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Wellhead Volumes
and Prices
|
|
|
|
Crude Oil and
Condensate Volumes (MBbld) (A)
|
|
|
|
United
States
|
|
265.4
|
|
|
276.5
|
|
|
265.6
|
|
|
287.5
|
Trinidad
|
|
0.8
|
|
|
0.7
|
|
|
0.8
|
|
|
0.9
|
Other International
(B)
|
|
1.5
|
|
|
0.3
|
|
|
1.4
|
|
|
0.2
|
Total
|
|
267.7
|
|
|
277.5
|
|
|
267.8
|
|
|
288.6
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Crude Oil and
Condensate Prices ($/Bbl) (C)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$
|
43.87
|
|
$
|
57.47
|
|
$
|
37.36
|
|
$
|
51.91
|
Trinidad
|
|
35.91
|
|
|
49.53
|
|
|
29.83
|
|
|
44.03
|
Other International
(B)
|
|
-
|
|
|
62.40
|
|
|
-
|
|
|
56.67
|
Composite
|
|
43.65
|
|
|
57.45
|
|
|
37.23
|
|
|
51.89
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids
Volumes (MBbld) (A)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
|
84.3
|
|
|
73.4
|
|
|
81.8
|
|
|
75.4
|
Other International
(B)
|
|
-
|
|
|
0.1
|
|
|
-
|
|
|
0.1
|
Total
|
|
84.3
|
|
|
73.5
|
|
|
81.8
|
|
|
75.5
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Natural Gas
Liquids Prices ($/Bbl) (C)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$
|
14.56
|
|
$
|
15.55
|
|
$
|
12.54
|
|
$
|
15.83
|
Other International
(B)
|
|
-
|
|
|
7.81
|
|
|
-
|
|
|
5.80
|
Composite
|
|
14.56
|
|
|
15.54
|
|
|
12.54
|
|
|
15.82
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Volumes
(MMcfd) (A)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
|
820
|
|
|
891
|
|
|
825
|
|
|
898
|
Trinidad
|
|
349
|
|
|
334
|
|
|
355
|
|
|
336
|
Other International
(B)
|
|
25
|
|
|
32
|
|
|
25
|
|
|
31
|
Total
|
|
1,194
|
|
|
1,257
|
|
|
1,205
|
|
|
1,265
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Natural Gas
Prices ($/Mcf) (C)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$
|
1.18
|
|
$
|
2.11
|
|
$
|
1.22
|
|
$
|
2.19
|
Trinidad
|
|
1.89
|
|
|
3.05
|
|
|
1.88
|
|
|
3.07
|
Other International
(B)
|
|
3.35
|
|
|
3.49
|
|
|
3.49
|
|
|
3.39
|
Composite
|
|
1.44
|
|
|
2.40
|
|
|
1.47
|
|
|
2.45
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Equivalent
Volumes (MBoed) (D)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
|
486.3
|
|
|
498.3
|
|
|
484.9
|
|
|
512.6
|
Trinidad
|
|
59.0
|
|
|
56.5
|
|
|
59.9
|
|
|
56.8
|
Other International
(B)
|
|
5.8
|
|
|
5.7
|
|
|
5.6
|
|
|
5.5
|
Total
|
|
551.1
|
|
|
560.5
|
|
|
550.4
|
|
|
574.9
|
|
|
|
|
|
|
|
|
|
|
|
|
Total MMBoe
(D)
|
|
50.1
|
|
|
51.0
|
|
|
100.2
|
|
|
104.1
|
|
(A) Thousand barrels
per day or million cubic feet per day, as applicable.
|
(B) Other
International includes EOG's United Kingdom, China, Canada and
Argentina operations.
|
(C) Dollars per
barrel or per thousand cubic feet, as applicable. Excludes
the impact of financial commodity derivative
instruments.
|
(D) Thousand barrels
of oil equivalent per day or million barrels of oil equivalent, as
applicable; includes crude oil and condensate, natural gas liquids
and natural gas. Crude oil equivalent volumes are determined
using a ratio of 1.0 barrel of crude oil and condensate or natural
gas liquids to 6.0 thousand cubic feet of natural gas. MMBoe
is calculated by multiplying the MBoed amount by the number of days
in the period and then dividing that amount by one
thousand.
|
EOG RESOURCES,
INC.
|
Summary Balance
Sheets
|
(Unaudited; in
thousands, except share data)
|
|
|
|
|
|
|
|
June
30,
|
|
December
31,
|
|
2016
|
|
2015
|
ASSETS
|
Current
Assets
|
|
|
|
|
|
Cash and Cash
Equivalents
|
$
|
779,722
|
|
$
|
718,506
|
Accounts Receivable,
Net
|
|
935,592
|
|
|
930,610
|
Inventories
|
|
495,826
|
|
|
598,935
|
Income Taxes
Receivable
|
|
4,880
|
|
|
40,704
|
Deferred Income
Taxes
|
|
46,712
|
|
|
147,812
|
Other
|
|
187,389
|
|
|
155,677
|
Total
|
|
2,450,121
|
|
|
2,592,244
|
|
|
|
|
|
|
Property, Plant
and Equipment
|
|
|
|
|
|
Oil and Gas Properties
(Successful Efforts Method)
|
|
51,355,620
|
|
|
50,613,241
|
Other Property, Plant and
Equipment
|
|
4,001,132
|
|
|
3,986,610
|
Total Property, Plant and Equipment
|
|
55,356,752
|
|
|
54,599,851
|
Less: Accumulated
Depreciation, Depletion and Amortization
|
|
(32,143,873)
|
|
|
(30,389,130)
|
Total Property, Plant and Equipment, Net
|
|
23,212,879
|
|
|
24,210,721
|
Other
Assets
|
|
167,538
|
|
|
167,505
|
Total
Assets
|
$
|
25,830,538
|
|
$
|
26,970,470
|
|
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS' EQUITY
|
Current
Liabilities
|
|
|
|
|
|
Accounts Payable
|
$
|
1,305,651
|
|
$
|
1,471,953
|
Accrued Taxes
Payable
|
|
138,395
|
|
|
93,618
|
Dividends Payable
|
|
91,679
|
|
|
91,546
|
Liabilities from Price Risk
Management Activities
|
|
1,315
|
|
|
-
|
Current Portion of Long-Term
Debt
|
|
6,579
|
|
|
6,579
|
Other
|
|
168,642
|
|
|
155,591
|
Total
|
|
1,712,261
|
|
|
1,819,287
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term
Debt
|
|
6,979,286
|
|
|
6,648,911
|
Other
Liabilities
|
|
978,513
|
|
|
971,335
|
Deferred Income
Taxes
|
|
4,103,777
|
|
|
4,587,902
|
Commitments and
Contingencies
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders'
Equity
|
|
|
|
|
|
Common Stock, $0.01 Par,
640,000,000 Shares Authorized and
|
|
|
|
|
|
551,004,831 Shares Issued at June 30, 2016 and
550,150,823
|
|
|
|
|
|
Shares Issued at December 31, 2015
|
|
205,510
|
|
|
205,502
|
Additional Paid in
Capital
|
|
2,982,047
|
|
|
2,923,461
|
Accumulated Other
Comprehensive Loss
|
|
(25,264)
|
|
|
(33,338)
|
Retained Earnings
|
|
8,923,666
|
|
|
9,870,816
|
Common Stock Held in
Treasury, 375,869 Shares at June 30, 2016
|
|
|
|
|
|
and
292,179 Shares at December 31, 2015
|
|
(29,258)
|
|
|
(23,406)
|
Total Stockholders' Equity
|
|
12,056,701
|
|
|
12,943,035
|
Total Liabilities
and Stockholders' Equity
|
$
|
25,830,538
|
|
$
|
26,970,470
|
EOG RESOURCES,
INC.
|
Summary Statements
of Cash Flows
|
(Unaudited; in
thousands)
|
|
|
|
|
|
|
|
Six Months
Ended
|
|
June
30,
|
|
2016
|
|
2015
|
Cash Flows from
Operating Activities
|
|
|
|
|
|
Reconciliation of Net
Loss to Net Cash Provided by Operating Activities:
|
|
|
|
|
|
Net Loss
|
$
|
(764,334)
|
|
$
|
(164,480)
|
Items Not Requiring
(Providing) Cash
|
|
|
|
|
|
Depreciation, Depletion and Amortization
|
|
1,791,382
|
|
|
1,822,015
|
Impairments
|
|
144,331
|
|
|
137,955
|
Stock-Based Compensation Expenses
|
|
59,471
|
|
|
61,650
|
Deferred Income Taxes
|
|
(384,294)
|
|
|
(154,803)
|
Losses on Asset Dispositions, Net
|
|
6,403
|
|
|
3,957
|
Other, Net
|
|
29,991
|
|
|
6,787
|
Dry Hole Costs
|
|
74
|
|
|
14,119
|
Mark-to-Market Commodity
Derivative Contracts
|
|
|
|
|
|
Total (Gains) Losses
|
|
38,938
|
|
|
(27,715)
|
Net Cash Received from Settlements of Commodity Derivative
Contracts
|
|
2,852
|
|
|
561,142
|
Excess Tax Benefits from
Stock-Based Compensation
|
|
(11,811)
|
|
|
(16,393)
|
Other, Net
|
|
5,008
|
|
|
6,346
|
Changes in Components of
Working Capital and Other Assets and Liabilities
|
|
|
|
|
|
Accounts Receivable
|
|
(22,572)
|
|
|
298,183
|
Inventories
|
|
95,813
|
|
|
37,609
|
Accounts Payable
|
|
(203,358)
|
|
|
(999,644)
|
Accrued Taxes Payable
|
|
93,320
|
|
|
64,124
|
Other Assets
|
|
(33,589)
|
|
|
76,114
|
Other Liabilities
|
|
1,565
|
|
|
(48,848)
|
Changes in Components
of Working Capital Associated with Investing and
Financing
|
|
|
|
|
|
Activities
|
|
(54,453)
|
|
|
169,802
|
Net Cash Provided
by Operating Activities
|
|
794,737
|
|
|
1,847,920
|
|
|
|
|
|
|
Investing Cash
Flows
|
|
|
|
|
|
Additions to Oil and Gas
Properties
|
|
(1,143,549)
|
|
|
(2,611,848)
|
Additions to Other Property,
Plant and Equipment
|
|
(44,584)
|
|
|
(201,597)
|
Proceeds from Sales of
Assets
|
|
252,529
|
|
|
116,166
|
Changes in Components of
Working Capital Associated with Investing Activities
|
|
54,477
|
|
|
(169,903)
|
Net Cash Used in
Investing Activities
|
|
(881,127)
|
|
|
(2,867,182)
|
|
|
|
|
|
|
Financing Cash
Flows
|
|
|
|
|
|
Net Commercial Paper
Repayments
|
|
(259,718)
|
|
|
-
|
Long-Term Debt
Borrowings
|
|
991,097
|
|
|
990,225
|
Long-Term Debt
Repayments
|
|
(400,000)
|
|
|
(500,000)
|
Dividends Paid
|
|
(184,036)
|
|
|
(183,130)
|
Excess Tax Benefits from
Stock-Based Compensation
|
|
11,811
|
|
|
16,393
|
Treasury Stock
Purchased
|
|
(28,755)
|
|
|
(26,362)
|
Proceeds from Stock Options
Exercised and Employee Stock Purchase Plan
|
|
10,624
|
|
|
14,484
|
Debt Issuance
Costs
|
|
(1,602)
|
|
|
(1,585)
|
Repayment of Capital Lease
Obligation
|
|
(3,150)
|
|
|
(3,053)
|
Other, Net
|
|
(24)
|
|
|
101
|
Net Cash Provided
by Financing Activities
|
|
136,247
|
|
|
307,073
|
|
|
|
|
|
|
Effect of Exchange
Rate Changes on Cash
|
|
11,359
|
|
|
(7,629)
|
|
|
|
|
|
|
Increase
(Decrease) in Cash and Cash Equivalents
|
|
61,216
|
|
|
(719,818)
|
Cash and Cash
Equivalents at Beginning of Period
|
|
718,506
|
|
|
2,087,213
|
Cash and Cash
Equivalents at End of Period
|
$
|
779,722
|
|
$
|
1,367,395
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Adjusted Net Income (Loss)
(Non-GAAP)
|
to Net Income
(Loss) (GAAP)
|
(Unaudited; in
thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following chart
adjusts the three-month and six-month periods ended June 30, 2016
and 2015 reported Net Income (Loss) (GAAP) to reflect actual net
cash received from (payments for) settlements of commodity
derivative contracts by eliminating the unrealized mark-to-market
(gains) losses from these transactions, to eliminate the net losses
on asset dispositions in 2015 and 2016, 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 and to
add back certain voluntary retirement expense 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
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
|
|
June 30,
2016
|
|
June 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
Income (Loss) (GAAP)
|
$
(380,277)
|
|
$
87,719
|
|
$
(292,558)
|
|
$
(0.53)
|
|
$
(11,478)
|
|
$
16,746
|
|
$
5,268
|
|
$
0.01
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains (Losses) on
Mark-to-Market Commodity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Contracts
|
44,373
|
|
(15,819)
|
|
28,554
|
|
0.05
|
|
48,493
|
|
(17,288)
|
|
31,205
|
|
0.06
|
Net Cash Received
from (Payments for)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Settlements of Commodity Derivative
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contracts
|
(14,835)
|
|
5,289
|
|
(9,546)
|
|
(0.01)
|
|
193,435
|
|
(68,960)
|
|
124,475
|
|
0.23
|
Add: Net Losses on
Asset Dispositions
|
15,550
|
|
(7,378)
|
|
8,172
|
|
0.01
|
|
5,564
|
|
570
|
|
6,134
|
|
0.01
|
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
|
19,663
|
|
(7,010)
|
|
12,653
|
|
0.02
|
|
-
|
|
-
|
|
-
|
|
-
|
Adjustments to Net
Income (Loss)
|
64,751
|
|
18,082
|
|
82,833
|
|
0.15
|
|
255,997
|
|
(108,210)
|
|
147,787
|
|
0.27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Net
Income (Loss) (Non-GAAP)
|
$
(315,526)
|
|
$
105,801
|
|
$
(209,725)
|
|
$
(0.38)
|
|
$
244,519
|
|
$
(91,464)
|
|
$
153,055
|
|
$
0.28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Number of
Common Shares (GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
547,335
|
|
|
|
|
|
|
|
545,504
|
Diluted
|
|
|
|
|
|
|
547,335
|
|
|
|
|
|
|
|
549,683
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Number of
Common Shares (Non-GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
547,335
|
|
|
|
|
|
|
|
545,504
|
Diluted
|
|
|
|
|
|
|
547,335
|
|
|
|
|
|
|
|
549,683
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months
Ended
|
|
Six Months
Ended
|
|
June 30,
2016
|
|
June 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
Income (Loss) (GAAP)
|
$
(1,091,245)
|
|
$
326,911
|
|
$
(764,334)
|
|
$
(1.40)
|
|
$
(247,809)
|
|
$
83,329
|
|
$
(164,480)
|
|
$
(0.30)
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains (Losses) on
Mark-to-Market Commodity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Contracts
|
38,938
|
|
(13,881)
|
|
25,057
|
|
0.05
|
|
(27,715)
|
|
9,880
|
|
(17,835)
|
|
(0.03)
|
Net Cash Received
from (Payments for)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Settlements of Commodity Derivative
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contracts
|
2,852
|
|
(1,017)
|
|
1,835
|
|
0.00
|
|
561,142
|
|
(200,047)
|
|
361,095
|
|
0.66
|
Add: Net Losses on
Asset Dispositions
|
6,403
|
|
(4,168)
|
|
2,235
|
|
0.00
|
|
3,957
|
|
1,166
|
|
5,123
|
|
0.01
|
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
|
|
-
|
|
-
|
|
-
|
|
-
|
Adjustments to Net
Income (Loss)
|
90,247
|
|
8,942
|
|
99,189
|
|
0.18
|
|
545,889
|
|
(211,533)
|
|
334,356
|
|
0.61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Net
Income (Loss) (Non-GAAP)
|
$
(1,000,998)
|
|
$
335,853
|
|
$
(665,145)
|
|
$
(1.22)
|
|
$
298,080
|
|
$
(128,204)
|
|
$
169,876
|
|
$
0.31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Number of
Common Shares (GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
547,029
|
|
|
|
|
|
|
|
545,245
|
Diluted
|
|
|
|
|
|
|
547,029
|
|
|
|
|
|
|
|
545,245
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Number of
Common Shares (Non-GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
547,029
|
|
|
|
|
|
|
|
545,245
|
Diluted
|
|
|
|
|
|
|
547,029
|
|
|
|
|
|
|
|
549,505
|
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 six-month periods ended June 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
|
|
Six Months
Ended
|
|
|
June
30,
|
|
June
30,
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by
Operating Activities (GAAP)
|
$
|
503,146
|
|
$
|
887,373
|
|
$
|
794,737
|
|
$
|
1,847,920
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration Costs
(excluding Stock-Based Compensation Expenses)
|
|
|
25,527
|
|
|
37,870
|
|
|
48,884
|
|
|
69,967
|
Excess Tax Benefits
from Stock-Based Compensation
|
|
|
11,811
|
|
|
7,535
|
|
|
11,811
|
|
|
16,393
|
Changes in Components
of Working Capital and Other Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
and
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
Receivable
|
|
|
154,970
|
|
|
54,917
|
|
|
22,572
|
|
|
(298,183)
|
Inventories
|
|
|
(38,235)
|
|
|
(99,781)
|
|
|
(95,813)
|
|
|
(37,609)
|
Accounts
Payable
|
|
|
(86,269)
|
|
|
321,769
|
|
|
203,358
|
|
|
999,644
|
Accrued Taxes
Payable
|
|
|
(90,860)
|
|
|
(62,019)
|
|
|
(93,320)
|
|
|
(64,124)
|
Other
Assets
|
|
|
37,535
|
|
|
(16,938)
|
|
|
33,589
|
|
|
(76,114)
|
Other
Liabilities
|
|
|
6,427
|
|
|
16,993
|
|
|
(1,565)
|
|
|
48,848
|
Changes in Components
of Working Capital Associated with
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing and
Financing Activities
|
|
|
56,681
|
|
|
90,190
|
|
|
54,453
|
|
|
(169,802)
|
|
Discretionary Cash
Flow (Non-GAAP)
|
|
$
|
580,733
|
|
$
|
1,237,909
|
|
$
|
978,706
|
|
$
|
2,336,940
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discretionary Cash
Flow (Non-GAAP) - Percentage Decrease
|
|
|
-53%
|
|
|
|
|
|
-58%
|
|
|
|
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 Income (Loss) (GAAP)
|
(Unaudited; in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
The following chart
adjusts the three-month and six-month periods ended June 30, 2016
and 2015 reported Net Income (Loss) (GAAP) to Earnings Before Net
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 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,
Depreciation, Depletion and Amortization, Exploration Costs, Dry
Hole Costs and Impairments and further adjust such amount to match
hedge realizations to production settlement months and make certain
other adjustments to exclude non-recurring items. EOG
management uses this information for purposes of comparing its
financial performance with the financial performance of other
companies in the industry.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Six Months
Ended
|
|
June
30,
|
|
June
30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
(GAAP)
|
$
|
(292,558)
|
|
$
|
5,268
|
|
$
|
(764,334)
|
|
$
|
(164,480)
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense,
Net
|
|
71,108
|
|
|
60,484
|
|
|
139,498
|
|
|
113,829
|
Income Tax
Benefit
|
|
(87,719)
|
|
|
(16,746)
|
|
|
(326,911)
|
|
|
(83,329)
|
Depreciation, Depletion and
Amortization
|
|
862,491
|
|
|
909,227
|
|
|
1,791,382
|
|
|
1,822,015
|
Exploration Costs
|
|
30,559
|
|
|
43,755
|
|
|
60,388
|
|
|
83,204
|
Dry Hole Costs
|
|
(172)
|
|
|
(551)
|
|
|
74
|
|
|
14,119
|
Impairments
|
|
72,714
|
|
|
68,519
|
|
|
144,331
|
|
|
137,955
|
EBITDAX (Non-GAAP)
|
|
656,423
|
|
|
1,069,956
|
|
|
1,044,428
|
|
|
1,923,313
|
Total (Gains) Losses on MTM
Commodity Derivative Contracts
|
|
44,373
|
|
|
48,493
|
|
|
38,938
|
|
|
(27,715)
|
Net Cash Received from
(Payments for) Settlements of Commodity
|
|
|
|
|
|
|
|
|
|
|
|
Derivative
Contracts
|
|
(14,835)
|
|
|
193,435
|
|
|
2,852
|
|
|
561,142
|
Losses on Asset
Dispositions, Net
|
|
15,550
|
|
|
5,564
|
|
|
6,403
|
|
|
3,957
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX
(Non-GAAP)
|
$
|
701,511
|
|
$
|
1,317,448
|
|
$
|
1,092,621
|
|
$
|
2,460,697
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX
(Non-GAAP) - Percentage Decrease
|
|
-47%
|
|
|
|
|
|
-56%
|
|
|
|
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
|
|
June
30,
|
|
December
31,
|
|
2016
|
|
2015
|
|
|
|
|
|
|
Total Stockholders'
Equity - (a)
|
$
|
12,057
|
|
$
|
12,943
|
|
|
|
|
|
|
Current and Long-Term
Debt (GAAP) - (b)
|
|
6,986
|
|
|
6,655
|
Less:
Cash
|
|
(780)
|
|
|
(719)
|
Net Debt (Non-GAAP) -
(c)
|
|
6,206
|
|
|
5,936
|
|
|
|
|
|
|
Total Capitalization
(GAAP) - (a) + (b)
|
$
|
19,043
|
|
$
|
19,598
|
|
|
|
|
|
|
Total Capitalization
(Non-GAAP) - (a) + (c)
|
$
|
18,263
|
|
$
|
18,879
|
|
|
|
|
|
|
Debt-to-Total
Capitalization (GAAP) - (b) / [(a) + (b)]
|
|
37%
|
|
|
34%
|
|
|
|
|
|
|
Net Debt-to-Total
Capitalization (Non-GAAP) - (c) / [(a) + (c)]
|
|
34%
|
|
|
31%
|
EOG RESOURCES,
INC.
|
Natural Gas
Financial
|
Commodity
Derivative Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
Presented below is a
comprehensive summary of EOG's natural gas derivative contracts at
August 4, 2016, with notional volumes expressed in MMBtud and
prices expressed in $/MMBtu. EOG accounts for financial
commodity derivative contracts using the mark-to-market accounting
method.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Option
Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Call Options
Sold
|
|
Put Options
Purchased
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
Weighted
|
|
|
|
|
|
Volume
|
|
Average
Price
|
|
Volume
|
|
Average
Price
|
|
|
|
|
|
(MMBtud)
|
|
($/MMBtu)
|
|
(MMBtud)
|
|
($/MMBtu)
|
2016
|
|
|
|
|
|
|
|
|
|
|
September 1, 2016
through November 30, 2016
|
|
|
43,750
|
|
$
3.45
|
|
-
|
|
$
-
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
March 1, 2017 through
November 30, 2017
|
|
|
43,750
|
|
$
3.45
|
|
35,000
|
|
$
2.90
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
March 1, 2018 through
November 30, 2018
|
|
|
12,500
|
|
$
3.32
|
|
10,000
|
|
$
2.90
|
|
|
|
|
|
|
|
|
|
|
|
|
Definitions
|
|
|
|
|
|
|
|
|
|
|
|
MMBtud Million
British thermal units per day
|
|
|
|
|
|
|
|
|
|
$/MMBtu Dollars per
million British thermal units
|
|
|
|
|
|
|
|
|
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
|
$
|
6,993
|
|
$
|
(2,434)
|
|
$
|
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
|
$
|
(234)
|
|
$
|
35
|
|
$
|
(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.
|
Third Quarter and
Full Year 2016 Forecast and Benchmark Commodity
Pricing
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Third Quarter and
Full Year 2016 Forecast
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The forecast items
for the third 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)
|
|
3Q 2016
|
|
Full Year
2016
|
Daily
Production
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil and Condensate
Volumes (MBbld)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
264.0
|
-
|
|
272.0
|
|
|
266.0
|
-
|
|
270.0
|
Trinidad
|
|
0.4
|
-
|
|
0.8
|
|
|
0.6
|
-
|
|
0.8
|
Other International
|
|
4.0
|
-
|
|
8.0
|
|
|
3.0
|
-
|
|
5.0
|
Total
|
|
268.4
|
-
|
|
280.8
|
|
|
269.6
|
-
|
|
275.8
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids Volumes
(MBbld)
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
75.0
|
-
|
|
79.0
|
|
|
76.0
|
-
|
|
80.0
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Volumes
(MMcfd)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
740
|
-
|
|
760
|
|
|
775
|
-
|
|
795
|
Trinidad
|
|
325
|
-
|
|
355
|
|
|
330
|
-
|
|
355
|
Other International
|
|
20
|
-
|
|
24
|
|
|
22
|
-
|
|
24
|
Total
|
|
1,085
|
-
|
|
1,139
|
|
|
1,127
|
-
|
|
1,174
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Equivalent Volumes
(MBoed)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
462.3
|
-
|
|
477.7
|
|
|
471.2
|
-
|
|
482.5
|
Trinidad
|
|
54.6
|
-
|
|
60.0
|
|
|
55.6
|
-
|
|
60.0
|
Other International
|
|
7.3
|
-
|
|
12.0
|
|
|
6.7
|
-
|
|
9.0
|
Total
|
|
524.2
|
-
|
|
549.7
|
|
|
533.5
|
-
|
|
551.5
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Costs
|
|
|
|
|
|
|
|
|
|
|
|
Unit Costs
($/Boe)
|
|
|
|
|
|
|
|
|
|
|
|
Lease and Well
|
$
|
4.50
|
-
|
$
|
5.00
|
|
$
|
4.50
|
-
|
$
|
5.00
|
Transportation Costs
|
$
|
3.75
|
-
|
$
|
4.25
|
|
$
|
3.70
|
-
|
$
|
4.00
|
Depreciation, Depletion and Amortization
|
$
|
17.45
|
-
|
$
|
17.85
|
|
$
|
17.65
|
-
|
$
|
18.00
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses
($MM)
|
|
|
|
|
|
|
|
|
|
|
|
Exploration, Dry Hole and
Impairment
|
$
|
105
|
-
|
$
|
125
|
|
$
|
415
|
-
|
$
|
460
|
General and
Administrative
|
$
|
85
|
-
|
$
|
95
|
|
$
|
320
|
-
|
$
|
340
|
Gathering and
Processing
|
$
|
28
|
-
|
$
|
32
|
|
$
|
112
|
-
|
$
|
122
|
Capitalized
Interest
|
$
|
6
|
-
|
$
|
8
|
|
$
|
30
|
-
|
$
|
33
|
Net Interest
|
$
|
69
|
-
|
$
|
71
|
|
$
|
277
|
-
|
$
|
283
|
|
|
|
|
|
|
|
|
|
|
|
|
Taxes Other Than
Income (% of Wellhead Revenue)
|
|
6.3%
|
-
|
|
6.7%
|
|
|
6.4%
|
-
|
|
6.6%
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Taxes
|
|
|
|
|
|
|
|
|
|
|
|
Effective
Rate
|
|
28%
|
-
|
|
33%
|
|
|
28%
|
-
|
|
33%
|
Current Taxes
($MM)
|
$
|
(15)
|
-
|
$
|
0
|
|
$
|
50
|
-
|
$
|
70
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures
(Excluding Acquisitions, $MM)
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and Development,
Excluding Facilities
|
|
|
|
|
|
|
$
|
1,925
|
-
|
$
|
2,025
|
Exploration and Development
Facilities
|
|
|
|
|
|
|
$
|
350
|
-
|
$
|
400
|
Gathering, Processing and
Other
|
|
|
|
|
|
|
$
|
125
|
-
|
$
|
175
|
|
|
|
|
|
|
|
|
|
|
|
|
Pricing - (Refer
toBenchmark Commodity Pricingin text)
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil and Condensate
($/Bbl)
|
|
|
|
|
|
|
|
|
|
|
|
Differentials
|
|
|
|
|
|
|
|
|
|
|
|
United States - above (below) WTI
|
$
|
(3.00)
|
-
|
$
|
(1.00)
|
|
$
|
(2.65)
|
-
|
$
|
(1.65)
|
Trinidad - above (below) WTI
|
$
|
(10.50)
|
-
|
$
|
(9.50)
|
|
$
|
(10.80)
|
-
|
$
|
(10.30)
|
Other International - above (below) WTI
|
$
|
(5.00)
|
-
|
$
|
(3.00)
|
|
$
|
(5.15)
|
-
|
$
|
(4.15)
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
Liquids
|
|
|
|
|
|
|
|
|
|
|
|
Realizations as % of WTI
|
|
30%
|
-
|
|
34%
|
|
|
31%
|
-
|
|
33%
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
($/Mcf)
|
|
|
|
|
|
|
|
|
|
|
|
Differentials
|
|
|
|
|
|
|
|
|
|
|
|
United States - above (below) NYMEX Henry Hub
|
$
|
(1.15)
|
-
|
$
|
(0.50)
|
|
$
|
(0.90)
|
-
|
$
|
(0.70)
|
|
|
|
|
|
|
|
|
|
|
|
|
Realizations
|
|
|
|
|
|
|
|
|
|
|
|
Trinidad
|
$
|
1.70
|
-
|
$
|
2.30
|
|
$
|
1.85
|
-
|
$
|
2.20
|
Other International
|
$
|
3.00
|
-
|
$
|
4.25
|
|
$
|
3.30
|
-
|
$
|
3.80
|
|
|
|
|
|
|
|
|
|
|
|
|
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-second-quarter-2016-results-increases-premium-well-inventory-by-34-300309574.html
SOURCE EOG Resources, Inc.