HOUSTON, Nov. 5, 2015 /PRNewswire/ --
- Updates Delaware Basin Net
Resource Potential to 2.35 BnBoe
- Increases Wolfcamp Net Reserve Potential by 500 MMBoe
- Announces Second Bone Spring Sand Net Reserve Potential of 500
MMBoe
- Expands Drilling Inventory from 2,700 to 4,900 Net Wells
- Acquires 26,000 Net Acres in the Delaware Basin Oil Window in Three
Transactions
- Completes Record Horizontal Well for Delaware Basin Wolfcamp
- Continues to Improve Well Productivity While Lowering
Costs
- Exceeds Third Quarter Oil and Total Production Guidance
- Reduces Per-Unit Lease Operating Costs by 5 Percent Versus
Second Quarter
EOG Resources, Inc. (NYSE: EOG) (EOG) today reported a
third quarter 2015 net loss of $4.1
billion, or $7.47 per share.
This compares to third quarter 2014 net income of $1.1 billion, or $2.01 per share.
Adjusted non-GAAP net income for the third quarter 2015 was
$13.5 million, or $0.02 per share, compared to the same prior year
period adjusted non-GAAP net income of $720.6 million, or $1.31 per share. Adjusted non-GAAP net
income is calculated by matching realizations to settlement months
and making certain other adjustments in order to exclude one-time
items. (Please refer to the attached tables for the
reconciliation of non-GAAP measures to GAAP measures.)
During the third quarter 2015, proved oil and gas properties and
related assets were written down to their fair value resulting in
non-cash impairment charges of $4.1
billion net of tax. The impairments were due to
declines in commodity prices and were primarily related
to legacy natural gas and marginal liquids assets.
Significant reductions in operating expenses were more than
offset by lower commodity price realizations, resulting in
decreases in adjusted non-GAAP net income, discretionary cash flow
and adjusted EBITDAX during the third quarter 2015 compared to the
third quarter 2014. (Please refer to the attached tables for the
reconciliation of non-GAAP measures to GAAP measures.)
Operational Highlights
In the third quarter 2015, total crude oil and condensate
production exceeded prior guidance due to improved well
productivity. Total company production decreased 5 percent
compared to the third quarter 2014 excluding production related to
EOG's Canadian operations, which were divested in the fourth
quarter 2014. Total capital expenditures decreased 36 percent
compared to the same prior year period.
EOG also continued to reduce completed well costs and operating
costs compared to the same quarter last year. Lease and well
expenses decreased 17 percent on a per-unit basis due to improved
operational efficiencies and reduced service costs. Per-unit
transportation costs decreased 11 percent, and total general and
administrative expenses declined 6 percent.
"We are executing on our 2015 plan to reset the company to be
successful in a low commodity price environment," said William R.
"Bill" Thomas, Chairman and Chief Executive Officer. "By
continuing to make the best oil wells in the industry,
significantly reducing costs and expanding resource potential in
the best North American oil plays, EOG is uniquely positioned for
2016 and to lead the industry for years to come."
2015 Capital Plan Update
EOG is maintaining full-year 2015 capital spending guidance.
U.S. crude oil production guidance increased due to strong well
performance. Total company crude oil production guidance is
slightly lower due to delays in the startup of the U.K. Conwy
project.
Delaware Basin
EOG increased its Delaware Basin
net resource potential by 1.0 billion barrels of oil equivalent
(BnBoe). For the Delaware
Basin Wolfcamp, EOG added 950 net drilling locations and increased
its net resource potential estimate over 60 percent to 1.3
BnBoe. Advancements in targeting and completion technology
are enabling tighter well spacing and increased production per
well. In the Second Bone Spring Sand oil play, EOG provided
an initial net resource potential estimate of 500 million barrels
of oil equivalent (MMBoe) and added 1,250 net drilling locations in
this high quality crude oil play.
EOG added 26,000 net acres to its Delaware Basin position in the third quarter
2015 through three tactical acquisitions in Loving County, Texas, and Lea County, N.M., for a total of $368 million. Most of the acquired acreage
is adjacent to EOG's existing operating areas in the high rate of
return Delaware Basin oil
window. Combined, these acquisitions added net production of
750 barrels of oil equivalent (Boe) per day with an associated 2.5
MMBoe of proved producing reserves. These acquisitions and
the updated resource potential bring EOG's total Delaware Basin net position to 2.35 BnBoe and
4,900 locations, providing decades of high return drilling
potential.
"Outstanding technical and operational advances enabled us to
increase potential resource estimates for our Delaware Basin position by over 70 percent,"
Thomas said. "We are also pleased that through our tactical
acquisitions of new, high quality Delaware Basin acreage, we added assets which
meet our high rate of return hurdle. EOG's Delaware Basin assets along with the company's
Eagle Ford and Bakken positions continue to grow in both size and
quality. With premier assets and commitment to innovation,
EOG continues to enhance its capability for high return growth in a
low oil price environment."
In addition, EOG completed a number of noteworthy new wells in
the Delaware Basin in the third
quarter.
In the Wolfcamp shale in Lea County,
N.M., EOG completed the Thor 21 #701H and #702H with average
initial production rates per well of 3,255 barrels of oil per day
(Bopd), 470 barrels per day (Bpd) of natural gas liquids (NGLs) and
3.9 million cubic feet per day (MMcfd) of natural gas. The
Thor 21 #702H set a new industry 30-day production record for
horizontal wells in the Delaware
Basin Wolfcamp.
In the Second Bone Spring Sand in Lea
County, N.M., EOG completed the Neptune 10 State Com #501H
and #502H in a two-well pattern with average initial production
rates per well of 2,205 Bopd, 185 Bpd of NGLs and 1.5 MMcfd of
natural gas.
In the Leonard shale in
Lea County, N.M., EOG completed
the Hawk 35 Fed #7H, #8H, #9H and #10H in a four-well pattern with
average initial production rates per well of 1,615 Bopd, 160 Bpd of
NGLs and 1.3 MMcfd of natural gas.
South Texas Eagle Ford
The Eagle Ford continues to be EOG's largest high return
play. During 2015, the company expanded the use of high
density completions to 95 percent of the Eagle Ford wells planned
for the year. Enabled by high density completions and
proprietary targeting technology, EOG is actively testing tighter
well spacing in the lower Eagle Ford with stacked-staggered "W"
patterns. Additionally, an efficient drilling program
increased the amount of acreage held by production to 91 percent of
EOG's 561,000 net acres in the Eagle Ford oil window. In
Gonzales County, EOG completed the Phoenix Unit #4H and #5H with
average initial production rates per well of 3,815 Bopd, 415 Bpd of
NGLs and 2.8 MMcfd of natural gas. In McMullen County, EOG
completed the Naylor Jones Unit 26 #1H and #2H in a two-well
pattern with average initial production rates per well of 2,650
Bopd with 150 Bpd of NGLs and 1.0 MMcfd of natural gas.
North Dakota Bakken
EOG's activity in North Dakota
remains focused on the Bakken Core and Antelope Extension
areas. The company continued to improve its drilling and
completion techniques including the expanded use of high density
completions. In addition, recently installed water gathering
facilities have significantly reduced operating expenses.
During the third quarter 2015, the company completed the
Parshall #88-3029H, #23-3029H and
#26-3029H in a three-well pattern with average initial production
rates per well of 1,830 Bopd and 1.0 MMcfd of rich natural
gas. Average lateral lengths for the wells were 5,925
feet.
Hedging Activity
For the period November 1 through December
31, 2015, EOG has crude oil financial price swap contracts
in place for 10,000 Bopd at a weighted average price of
$89.98 per barrel. In addition,
EOG has put options in place which establish a floor price of
$45.00 per barrel for 82,500 Bopd for
November 2015.
For December 2015, EOG has natural
gas financial price swap contracts in place for 175,000 million
British thermal units (MMBtu) per day at a weighted average price
of $4.51 per MMBtu, excluding
unexercised options. Comprehensive summaries of crude oil and
natural gas derivative contracts are provided in the attached
tables.
Capital Structure
At September 30, 2015, EOG's total
debt outstanding was $6.4 billion
with a debt-to-total capitalization ratio of 33 percent. Taking
into account cash on the balance sheet of $743 million at September
30, EOG's net debt was $5.7
billion with a net debt-to-total capitalization ratio of 30
percent. A reconciliation of non-GAAP measures to GAAP measures is
provided in the attached tables.
Conference Call November 6,
2015
EOG's third quarter 2015 results conference call will be available
via live audio webcast at 9 a.m. Central
time (10 a.m. Eastern time) on
Friday, November 6, 2015. To listen,
log on to www.eogresources.com. The webcast will be archived on
EOG's website through December 7,
2015.
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, 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, 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 optimize 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, 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 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 20 of EOG's Annual Report on Form 10-K for the
fiscal year ended December 31, 2014,
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 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, 2014, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor
Relations). You can also obtain this report from the SEC by calling
1-800-SEC-0330 or from the SEC's website at www.sec.gov. In
addition, reconciliation and calculation schedules for non-GAAP
financial measures can be found on the EOG website at
www.eogresources.com.
For Further
Information Contact:
|
Investors
|
|
Cedric W.
Burgher
|
|
(713)
571-4658
|
|
David J.
Streit
|
|
(713)
571-4902
|
|
Kimberly M.
Ehmer
|
|
(713)
571-4676
|
|
|
|
Media
|
|
K
Leonard
|
|
(713)
571-3870
|
EOG RESOURCES,
INC.
|
Financial
Report
|
(Unaudited; in
millions, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Nine Months
Ended
|
|
September
30,
|
|
September
30,
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Operating
Revenues
|
$
|
2,172.4
|
|
$
|
5,118.6
|
|
$
|
6,960.7
|
|
$
|
13,389.8
|
Net Income
(Loss)
|
$
|
(4,075.7)
|
|
$
|
1,103.6
|
|
$
|
(4,240.2)
|
|
$
|
2,470.9
|
Net Income (Loss) Per
Share
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
$
|
(7.47)
|
|
$
|
2.03
|
|
$
|
(7.77)
|
|
$
|
4.55
|
Diluted
|
$
|
(7.47)
|
|
$
|
2.01
|
|
$
|
(7.77)
|
|
$
|
4.51
|
Average Number of
Common Shares
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
545.9
|
|
|
544.0
|
|
|
545.5
|
|
|
543.1
|
Diluted
|
|
545.9
|
|
|
549.5
|
|
|
545.5
|
|
|
548.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Summary Income
Statements
|
(Unaudited; in
thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Nine Months
Ended
|
|
September
30,
|
|
September
30,
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
Net Operating
Revenues
|
|
|
|
|
|
|
|
Crude Oil
and Condensate
|
$
|
1,181,092
|
|
$
|
2,671,502
|
|
$
|
3,894,092
|
|
$
|
7,687,579
|
Natural
Gas Liquids
|
|
95,217
|
|
|
258,927
|
|
|
311,137
|
|
|
753,135
|
Natural
Gas
|
|
281,837
|
|
|
443,108
|
|
|
843,657
|
|
|
1,508,892
|
Gains on
Mark-to-Market Commodity
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Contracts
|
|
29,239
|
|
|
469,125
|
|
|
56,954
|
|
|
84,119
|
Gathering,
Processing and Marketing
|
|
572,217
|
|
|
1,196,933
|
|
|
1,820,843
|
|
|
3,240,139
|
Gains
(Losses) on Asset Dispositions, Net
|
|
(1,185)
|
|
|
60,346
|
|
|
(5,142)
|
|
|
75,700
|
Other,
Net
|
|
14,011
|
|
|
18,675
|
|
|
39,126
|
|
|
40,279
|
Total
|
|
2,172,428
|
|
|
5,118,616
|
|
|
6,960,667
|
|
|
13,389,843
|
Operating
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
Lease and
Well
|
|
283,221
|
|
|
368,340
|
|
|
934,366
|
|
|
1,035,632
|
Transportation Costs
|
|
203,594
|
|
|
246,067
|
|
|
641,739
|
|
|
729,883
|
Gathering
and Processing Costs
|
|
35,497
|
|
|
41,621
|
|
|
106,503
|
|
|
108,015
|
Exploration Costs
|
|
31,344
|
|
|
48,955
|
|
|
114,548
|
|
|
139,221
|
Dry Hole
Costs
|
|
198
|
|
|
16,359
|
|
|
14,317
|
|
|
30,265
|
Impairments
|
|
6,307,420
|
|
|
55,542
|
|
|
6,445,375
|
|
|
207,938
|
Marketing
Costs
|
|
615,303
|
|
|
1,213,652
|
|
|
1,924,134
|
|
|
3,263,471
|
Depreciation, Depletion and Amortization
|
|
722,172
|
|
|
1,040,018
|
|
|
2,544,187
|
|
|
2,983,111
|
General
and Administrative
|
|
90,959
|
|
|
96,931
|
|
|
257,580
|
|
|
270,725
|
Taxes
Other Than Income
|
|
105,677
|
|
|
204,969
|
|
|
334,244
|
|
|
606,411
|
Total
|
|
8,395,385
|
|
|
3,332,454
|
|
|
13,316,993
|
|
|
9,374,672
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
(Loss)
|
|
(6,222,957)
|
|
|
1,786,162
|
|
|
(6,356,326)
|
|
|
4,015,171
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income
(Expense), Net
|
|
8,607
|
|
|
(21,338)
|
|
|
7,996
|
|
|
(16,726)
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) Before
Interest Expense and Income Taxes
|
|
(6,214,350)
|
|
|
1,764,824
|
|
|
(6,348,330)
|
|
|
3,998,445
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense,
Net
|
|
60,571
|
|
|
49,704
|
|
|
174,400
|
|
|
151,723
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) Before
Income Taxes
|
|
(6,274,921)
|
|
|
1,715,120
|
|
|
(6,522,730)
|
|
|
3,846,722
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax Provision
(Benefit)
|
|
(2,199,182)
|
|
|
611,502
|
|
|
(2,282,511)
|
|
|
1,375,823
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
(Loss)
|
$
|
(4,075,739)
|
|
$
|
1,103,618
|
|
$
|
(4,240,219)
|
|
$
|
2,470,899
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends Declared
per Common Share
|
$
|
0.1675
|
|
$
|
0.1675
|
|
$
|
0.5025
|
|
$
|
0.4175
|
|
|
|
|
EOG RESOURCES,
INC.
|
Operating
Highlights
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Nine Months
Ended
|
|
September
30,
|
|
September
30,
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
Wellhead Volumes
and Prices
|
|
|
|
Crude Oil and
Condensate Volumes (MBbld) (A)
|
|
|
|
United
States
|
|
278.3
|
|
|
293.2
|
|
|
284.4
|
|
|
275.5
|
Trinidad
|
|
1.0
|
|
|
0.9
|
|
|
0.9
|
|
|
1.0
|
Other International
(B)
|
|
0.2
|
|
|
5.4
|
|
|
0.2
|
|
|
6.1
|
Total
|
|
279.5
|
|
|
299.5
|
|
|
285.5
|
|
|
282.6
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Crude Oil and
Condensate Prices ($/Bbl) (C)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$
|
45.93
|
|
$
|
97.33
|
|
$
|
49.94
|
|
$
|
100.10
|
Trinidad
|
|
38.56
|
|
|
87.87
|
|
|
41.98
|
|
|
90.84
|
Other International
(B)
|
|
61.80
|
|
|
87.72
|
|
|
58.44
|
|
|
90.74
|
Composite
|
|
45.91
|
|
|
97.13
|
|
|
49.92
|
|
|
99.87
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids
Volumes (MBbld) (A)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
|
77.7
|
|
|
85.8
|
|
|
76.2
|
|
|
78.4
|
Other International
(B)
|
|
0.1
|
|
|
0.6
|
|
|
0.1
|
|
|
0.7
|
Total
|
|
77.8
|
|
|
86.4
|
|
|
76.3
|
|
|
79.1
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Natural Gas
Liquids Prices ($/Bbl) (C)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$
|
13.25
|
|
$
|
32.61
|
|
$
|
14.94
|
|
$
|
34.83
|
Other International
(B)
|
|
8.05
|
|
|
40.38
|
|
|
6.05
|
|
|
43.01
|
Composite
|
|
13.24
|
|
|
32.67
|
|
|
14.93
|
|
|
34.90
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Volumes
(MMcfd) (A)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
|
889
|
|
|
941
|
|
|
895
|
|
|
920
|
Trinidad
|
|
355
|
|
|
356
|
|
|
342
|
|
|
374
|
Other International
(B)
|
|
30
|
|
|
72
|
|
|
31
|
|
|
74
|
Total
|
|
1,274
|
|
|
1,369
|
|
|
1,268
|
|
|
1,368
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Natural Gas
Prices ($/Mcf) (C)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$
|
2.04
|
|
$
|
3.48
|
|
$
|
2.14
|
|
$
|
4.17
|
Trinidad
|
|
2.90
|
|
|
3.50
|
|
|
3.01
|
|
|
3.61
|
Other International
(B)
|
|
7.18
|
(E)
|
|
4.16
|
|
|
4.63
|
(E)
|
|
4.56
|
Composite
|
|
2.40
|
|
|
3.52
|
|
|
2.44
|
|
|
4.04
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Equivalent
Volumes (MBoed) (D)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
|
504.2
|
|
|
536.1
|
|
|
509.8
|
|
|
507.3
|
Trinidad
|
|
60.2
|
|
|
60.1
|
|
|
57.9
|
|
|
63.4
|
Other International
(B)
|
|
5.2
|
|
|
17.9
|
|
|
5.4
|
|
|
19.0
|
Total
|
|
569.6
|
|
|
614.1
|
|
|
573.1
|
|
|
589.7
|
|
|
|
|
|
|
|
|
|
|
|
|
Total MMBoe
(D)
|
|
52.4
|
|
|
56.5
|
|
|
156.5
|
|
|
161.0
|
|
|
(A)
|
Thousand barrels per
day or million cubic feet per day, as applicable.
|
(B)
|
Other International
includes EOG's Canada, United Kingdom, China 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.
|
(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 during the period June 2012 through
March 2015.
|
EOG RESOURCES,
INC.
|
Summary Balance
Sheets
|
(Unaudited; in
thousands, except share data)
|
|
|
|
|
|
|
|
September
30,
|
|
December
31,
|
|
2015
|
|
2014
|
ASSETS
|
Current
Assets
|
|
|
|
|
|
Cash and Cash
Equivalents
|
$
|
742,689
|
|
$
|
2,087,213
|
Accounts Receivable,
Net
|
|
1,123,111
|
|
|
1,779,311
|
Inventories
|
|
660,252
|
|
|
706,597
|
Assets from Price Risk
Management Activities
|
|
71,503
|
|
|
465,128
|
Income Taxes
Receivable
|
|
53,667
|
|
|
71,621
|
Deferred Income
Taxes
|
|
40,619
|
|
|
19,618
|
Other
|
|
133,117
|
|
|
286,533
|
Total
|
|
2,824,958
|
|
|
5,416,021
|
|
|
|
|
|
|
Property, Plant
and Equipment
|
|
|
|
|
|
Oil and Gas Properties
(Successful Efforts Method)
|
|
50,025,191
|
|
|
46,503,532
|
Other Property, Plant and
Equipment
|
|
3,890,934
|
|
|
3,750,958
|
Total Property, Plant and Equipment
|
|
53,916,125
|
|
|
50,254,490
|
Less: Accumulated
Depreciation, Depletion and Amortization
|
|
(29,640,793)
|
|
|
(21,081,846)
|
Total Property, Plant and Equipment, Net
|
|
24,275,332
|
|
|
29,172,644
|
Other
Assets
|
|
176,957
|
|
|
174,022
|
Total
Assets
|
$
|
27,277,247
|
|
$
|
34,762,687
|
|
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS' EQUITY
|
Current
Liabilities
|
|
|
|
|
|
Accounts Payable
|
$
|
1,561,574
|
|
$
|
2,860,548
|
Accrued Taxes
Payable
|
|
174,897
|
|
|
140,098
|
Dividends Payable
|
|
91,377
|
|
|
91,594
|
Deferred Income
Taxes
|
|
-
|
|
|
110,743
|
Short-Term Borrowings and
Current Portion of Long-Term Debt
|
|
36,279
|
|
|
6,579
|
Other
|
|
182,834
|
|
|
174,746
|
Total
|
|
2,046,961
|
|
|
3,384,308
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term
Debt
|
|
6,393,931
|
|
|
5,903,354
|
Other
Liabilities
|
|
970,288
|
|
|
939,497
|
Deferred Income
Taxes
|
|
4,581,844
|
|
|
6,822,946
|
Commitments and
Contingencies
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders'
Equity
|
|
|
|
|
|
Common Stock, $0.01 Par,
640,000,000 Shares Authorized and
550,052,879 Shares
Issued at September 30, 2015 and 549,028,374
Shares Issued at
December 31, 2014
|
|
205,503
|
|
|
205,492
|
Additional Paid in
Capital
|
|
2,897,439
|
|
|
2,837,150
|
Accumulated Other
Comprehensive Loss
|
|
(34,979)
|
|
|
(23,056)
|
Retained Earnings
|
|
10,247,349
|
|
|
14,763,098
|
Common Stock Held in
Treasury, 383,870 Shares at September 30, 2015
and 733,517 Shares at
December 31, 2014
|
|
(31,089)
|
|
|
(70,102)
|
Total Stockholders' Equity
|
|
13,284,223
|
|
|
17,712,582
|
Total Liabilities
and Stockholders' Equity
|
$
|
27,277,247
|
|
$
|
34,762,687
|
|
|
|
EOG RESOURCES,
INC.
|
Summary Statements
of Cash Flows
|
(Unaudited; in
thousands)
|
|
|
|
|
|
|
|
Nine Months
Ended
|
|
September
30,
|
|
2015
|
|
2014
|
Cash Flows from
Operating Activities
|
|
|
|
|
|
Reconciliation of Net
Income (Loss) to Net Cash Provided by Operating
Activities:
|
|
|
|
|
|
Net Income (Loss)
|
$
|
(4,240,219)
|
|
$
|
2,470,899
|
Items Not Requiring
(Providing) Cash
|
|
|
|
|
|
Depreciation, Depletion and Amortization
|
|
2,544,187
|
|
|
2,983,111
|
Impairments
|
|
6,445,375
|
|
|
207,938
|
Stock-Based Compensation Expenses
|
|
101,926
|
|
|
103,636
|
Deferred Income Taxes
|
|
(2,377,030)
|
|
|
974,522
|
(Gains) Losses on Asset Dispositions, Net
|
|
5,142
|
|
|
(75,700)
|
Other, Net
|
|
3,735
|
|
|
17,188
|
Dry Hole Costs
|
|
14,317
|
|
|
30,265
|
Mark-to-Market Commodity
Derivative Contracts
|
|
|
|
|
|
Total Gains
|
|
(56,954)
|
|
|
(84,119)
|
Net Cash Received from (Payments for) Settlements of Commodity
Derivative Contracts
|
|
661,021
|
|
|
(188,937)
|
Excess Tax Benefits from
Stock-Based Compensation
|
|
(24,219)
|
|
|
(87,827)
|
Other, Net
|
|
8,904
|
|
|
8,701
|
Changes in Components of
Working Capital and Other Assets and Liabilities
|
|
|
|
|
|
Accounts Receivable
|
|
448,311
|
|
|
(341,043)
|
Inventories
|
|
27,007
|
|
|
(119,166)
|
Accounts Payable
|
|
(1,310,211)
|
|
|
566,753
|
Accrued Taxes Payable
|
|
77,575
|
|
|
176,412
|
Other Assets
|
|
146,965
|
|
|
(61,966)
|
Other Liabilities
|
|
(15,683)
|
|
|
66,618
|
Changes in Components of
Working Capital Associated with Investing and
Financing
|
|
|
|
|
|
Activities
|
|
519,203
|
|
|
(108,568)
|
Net Cash Provided
by Operating Activities
|
|
2,979,352
|
|
|
6,538,717
|
|
|
|
|
|
|
Investing Cash
Flows
|
|
|
|
|
|
Additions to Oil and Gas
Properties
|
|
(3,918,065)
|
|
|
(5,653,035)
|
Additions to Other Property,
Plant and Equipment
|
|
(252,295)
|
|
|
(587,178)
|
Proceeds from Sales of
Assets
|
|
144,285
|
|
|
91,335
|
Changes in Restricted
Cash
|
|
-
|
|
|
(91,238)
|
Changes in Components of
Working Capital Associated with Investing Activities
|
|
(519,323)
|
|
|
108,999
|
Net Cash Used in
Investing Activities
|
|
(4,545,398)
|
|
|
(6,131,117)
|
|
|
|
|
|
|
Financing Cash
Flows
|
|
|
|
|
|
Net Commercial Paper
Borrowings
|
|
29,700
|
|
|
-
|
Long-Term Debt
Borrowings
|
|
990,225
|
|
|
496,220
|
Long-Term Debt
Repayments
|
|
(500,000)
|
|
|
(500,000)
|
Settlement of Foreign
Currency Swap
|
|
-
|
|
|
(31,573)
|
Dividends Paid
|
|
(274,577)
|
|
|
(187,670)
|
Excess Tax Benefits from
Stock-Based Compensation
|
|
24,219
|
|
|
87,827
|
Treasury Stock
Purchased
|
|
(43,419)
|
|
|
(114,824)
|
Proceeds from Stock Options
Exercised and Employee Stock Purchase Plan
|
|
14,967
|
|
|
11,740
|
Debt Issuance
Costs
|
|
(5,933)
|
|
|
(895)
|
Repayment of Capital Lease
Obligation
|
|
(4,599)
|
|
|
(4,457)
|
Other, Net
|
|
120
|
|
|
(431)
|
Net Cash Provided
by (Used in) Financing Activities
|
|
230,703
|
|
|
(244,063)
|
|
|
|
|
|
|
Effect of Exchange
Rate Changes on Cash
|
|
(9,181)
|
|
|
(601)
|
|
|
|
|
|
|
Increase
(Decrease) in Cash and Cash Equivalents
|
|
(1,344,524)
|
|
|
162,936
|
Cash and Cash
Equivalents at Beginning of Period
|
|
2,087,213
|
|
|
1,318,209
|
Cash and Cash
Equivalents at End of Period
|
$
|
742,689
|
|
$
|
1,481,145
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Adjusted Net Income (Non-GAAP)
|
to Net Income
(Loss) (GAAP)
|
(Unaudited; in
thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following chart
adjusts the three-month and nine-month periods ended September 30,
2015 and 2014 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 from these transactions, to eliminate the impact of the Texas
margin tax rate reduction in 2015, to eliminate the net (gains)
losses on asset dispositions, to add back severance costs
associated with EOG's North American operations in 2015 and to add
back impairment charges related to certain of EOG's assets in 2015
and 2014. EOG believes this presentation may be useful to
investors who follow the practice of some industry analysts who
adjust reported company earnings to match realizations to
production settlement months and make certain other adjustments to
exclude non-recurring items. EOG management uses this
information for comparative purposes within the
industry.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Nine Months
Ended
|
|
September
30,
|
|
September
30,
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
Reported Net Income
(Loss) (GAAP)
|
$
|
(4,075,739)
|
|
$
|
1,103,618
|
|
$
|
(4,240,219)
|
|
$
|
2,470,899
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Derivative
Contracts Impact
|
|
|
|
|
|
|
|
|
|
|
|
Gains on
Mark-to-Market Commodity Derivative Contracts
|
|
(29,239)
|
|
|
(469,125)
|
|
|
(56,954)
|
|
|
(84,119)
|
Net Cash
Received from (Payments for) Settlements of Commodity
Derivative
Contracts
|
|
99,879
|
|
|
(68,037)
|
|
|
661,021
|
|
|
(188,937)
|
Subtotal
|
|
70,640
|
|
|
(537,162)
|
|
|
604,067
|
|
|
(273,056)
|
|
|
|
|
|
|
|
|
|
|
|
|
After-Tax MTM
Impact
|
|
45,457
|
|
|
(344,616)
|
|
|
388,717
|
|
|
(175,179)
|
|
|
|
|
|
|
|
|
|
|
|
|
Less: Texas Margin
Tax Rate Reduction
|
|
-
|
|
|
-
|
|
|
(19,500)
|
|
|
-
|
Less: Net (Gains)
Losses on Asset Dispositions, Net of Tax
|
|
(3,429)
|
|
|
(38,386)
|
|
|
1,694
|
|
|
(47,426)
|
Add: Severance
Costs, Net of Tax
|
|
-
|
|
|
-
|
|
|
5,473
|
|
|
-
|
Add:
Impairments of Certain Assets, Net of Tax
|
|
4,047,223
|
|
|
-
|
|
|
4,047,223
|
|
|
36,058
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Net Income
(Non-GAAP)
|
$
|
13,512
|
|
$
|
720,616
|
|
$
|
183,388
|
|
$
|
2,284,352
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) Per
Share (GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
$
|
(7.47)
|
|
$
|
2.03
|
|
$
|
(7.77)
|
|
$
|
4.55
|
Diluted
|
$
|
(7.47)
|
|
$
|
2.01
|
|
$
|
(7.77)
|
|
$
|
4.51
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Net Income
Per Share (Non-GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
$
|
0.02
|
|
$
|
1.32
|
|
$
|
0.34
|
|
$
|
4.21
|
Diluted
|
$
|
0.02
|
|
$
|
1.31
|
|
$
|
0.33
|
|
$
|
4.17
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Net Income
Per Diluted Share (Non-GAAP) -
Percentage Decrease
|
|
-98
|
%
|
|
|
|
|
-92
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Number of
Common Shares (GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
545,920
|
|
|
543,984
|
|
|
545,466
|
|
|
543,086
|
Diluted
|
|
545,920
|
|
|
549,518
|
|
|
545,466
|
|
|
548,401
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Number of
Common Shares (Non-GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
545,920
|
|
|
543,984
|
|
|
545,466
|
|
|
543,086
|
Diluted
|
|
549,434
|
|
|
549,518
|
|
|
549,414
|
|
|
548,401
|
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, 2015 and 2014 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,
|
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by
Operating Activities (GAAP)
|
$
|
1,131,432
|
|
$
|
2,336,469
|
|
$
|
2,979,352
|
|
$
|
6,538,717
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration Costs
(excluding Stock-Based Compensation Expenses)
|
|
|
25,286
|
|
|
42,220
|
|
|
95,253
|
|
|
119,003
|
Excess Tax Benefits
from Stock-Based Compensation
|
|
|
7,826
|
|
|
24,068
|
|
|
24,219
|
|
|
87,827
|
Changes in Components
of Working Capital and Other Assets and Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
Receivable
|
|
|
(150,128)
|
|
|
91,707
|
|
|
(448,311)
|
|
|
341,043
|
Inventories
|
|
|
10,602
|
|
|
9,410
|
|
|
(27,007)
|
|
|
119,166
|
Accounts
Payable
|
|
|
310,567
|
|
|
(219,214)
|
|
|
1,310,211
|
|
|
(566,753)
|
Accrued Taxes
Payable
|
|
|
(13,451)
|
|
|
(60,744)
|
|
|
(77,575)
|
|
|
(176,412)
|
Other
Assets
|
|
|
(70,851)
|
|
|
(79,487)
|
|
|
(146,965)
|
|
|
61,966
|
Other
Liabilities
|
|
|
(33,165)
|
|
|
(9,517)
|
|
|
15,683
|
|
|
(66,618)
|
Changes in Components
of Working Capital Associated with Investing and
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing
Activities
|
|
|
(349,401)
|
|
|
76,924
|
|
|
(519,203)
|
|
|
108,568
|
|
Discretionary Cash
Flow (Non-GAAP)
|
|
$
|
868,717
|
|
$
|
2,211,836
|
|
$
|
3,205,657
|
|
$
|
6,566,507
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discretionary Cash
Flow (Non-GAAP) - Percentage Decrease
|
|
|
-61
|
%
|
|
|
|
|
-51
|
%
|
|
|
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 Income (Loss) Before Interest Expense and Income Taxes
(GAAP)
|
(Unaudited; in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
The following chart
adjusts the three-month and nine-month periods ended September 30,
2015 and 2014 reported Income (Loss) Before Interest Expense and
Income Taxes (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 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 Income (Loss) Before Interest Expense and Income
Taxes (GAAP) to add back 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
items. EOG management uses this information for comparative
purposes within the industry.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Nine Months
Ended
|
|
September
30,
|
|
September
30,
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) Before
Interest Expense and Income Taxes (GAAP)
|
$
|
(6,214,350)
|
|
$
|
1,764,824
|
|
$
|
(6,348,330)
|
|
$
|
3,998,445
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, Depletion and
Amortization
|
|
722,172
|
|
|
1,040,018
|
|
|
2,544,187
|
|
|
2,983,111
|
Exploration Costs
|
|
31,344
|
|
|
48,955
|
|
|
114,548
|
|
|
139,221
|
Dry Hole Costs
|
|
198
|
|
|
16,359
|
|
|
14,317
|
|
|
30,265
|
Impairments
|
|
6,307,420
|
|
|
55,542
|
|
|
6,445,375
|
|
|
207,938
|
EBITDAX (Non-GAAP)
|
|
846,784
|
|
|
2,925,698
|
|
|
2,770,097
|
|
|
7,358,980
|
Total Gains on MTM Commodity
Derivative Contracts
|
|
(29,239)
|
|
|
(469,125)
|
|
|
(56,954)
|
|
|
(84,119)
|
Net Cash Received from
(Payments for) Settlements of
Commodity Derivative
Contracts
|
|
99,879
|
|
|
(68,037)
|
|
|
661,021
|
|
|
(188,937)
|
(Gains) Losses on Asset
Dispositions, Net
|
|
1,185
|
|
|
(60,346)
|
|
|
5,142
|
|
|
(75,700)
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX
(Non-GAAP)
|
$
|
918,609
|
|
$
|
2,328,190
|
|
$
|
3,379,306
|
|
$
|
7,010,224
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX
(Non-GAAP) - Percentage Decrease
|
|
-61
|
%
|
|
|
|
|
-52
|
%
|
|
|
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,
|
|
|
2015
|
|
2014
|
|
|
|
|
|
|
|
|
Total Stockholders'
Equity - (a)
|
$
|
13,284
|
|
$
|
17,713
|
|
|
|
|
|
|
|
|
Current and Long-Term
Debt (GAAP) - (b)
|
|
6,430
|
|
|
5,910
|
|
Less:
Cash
|
|
(743)
|
|
|
(2,087)
|
|
Net Debt (Non-GAAP) -
(c)
|
|
5,687
|
|
|
3,823
|
|
|
|
|
|
|
|
|
Total Capitalization
(GAAP) - (a) + (b)
|
$
|
19,714
|
|
$
|
23,623
|
|
|
|
|
|
|
|
|
Total Capitalization
(Non-GAAP) - (a) + (c)
|
$
|
18,971
|
|
$
|
21,536
|
|
|
|
|
|
|
|
|
Debt-to-Total
Capitalization (GAAP) - (b) / [(a) + (b)]
|
|
33
|
%
|
|
25
|
%
|
|
|
|
|
|
|
|
Net Debt-to-Total
Capitalization (Non-GAAP) - (c) / [(a) + (c)]
|
|
30
|
%
|
|
18
|
%
|
EOG RESOURCES,
INC.
|
Crude Oil and
Natural Gas Financial
|
Commodity
Derivative Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
Presented below is a
comprehensive summary of EOG's crude oil and natural gas derivative
contracts at November 5, 2015, with notional volumes expressed in
Bbld and MMBtud and prices and premiums expressed in $/Bbl and
$/MMBtu. EOG accounts for financial commodity derivative
contracts using the mark-to-market accounting method.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Price
Swap Contracts
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Volume
|
|
Average
Price
|
|
|
|
|
|
|
|
|
|
(Bbld)
|
|
($/Bbl)
|
2015
|
|
|
|
|
|
|
|
January 1, 2015
through June 30, 2015 (closed)
|
|
|
|
|
47,000
|
|
$
|
91.22
|
July 1, 2015 through
October 31, 2015 (closed)
|
|
|
|
|
10,000
|
|
89.98
|
November 1, 2015
through December 31, 2015
|
|
|
|
|
10,000
|
|
89.98
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Put
Option Contracts
|
|
|
|
|
|
|
|
|
|
Average
|
|
Strike
|
|
|
|
|
|
|
|
Volume
|
|
Premium
|
|
Price
|
|
|
|
|
|
|
|
(Bbld)
|
|
($/Bbl)
|
|
($/Bbl)
|
2015
(1)
|
|
|
|
|
|
|
|
September 1, 2015
through October 31, 2015 (closed)
|
|
|
82,500
|
|
$
|
1.75
|
|
$
|
45.00
|
November
2015
|
|
|
|
|
|
82,500
|
|
1.75
|
|
45.00
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
EOG has purchased put
options which establish a floor price for the sale of certain
notional volumes of crude oil 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 average
NYMEX West Texas Intermediate crude oil price for the contract
month (Index Price), in the event the Index Price is below the put
option strike price. If the Index Price is above the put
option strike price, EOG is only required to pay the put option
premium.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Price
Swap Contracts
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Volume
|
|
Average
Price
|
|
|
|
|
|
|
|
|
|
(MMBtud)
|
|
($/MMBtu)
|
2015
(2)
|
|
|
|
|
|
|
|
|
|
|
January 1, 2015
through February 28, 2015 (closed)
|
|
|
|
|
235,000
|
|
$
|
4.47
|
March 2015
(closed)
|
|
|
|
|
225,000
|
|
4.48
|
April 2015
(closed)
|
|
|
|
|
195,000
|
|
4.49
|
May 2015
(closed)
|
|
|
|
|
235,000
|
|
4.13
|
June 1, 2015 through
July 31, 2015 (closed)
|
|
|
|
|
275,000
|
|
3.98
|
August 1, 2015
through November 30, 2015 (closed)
|
|
|
|
|
175,000
|
|
4.51
|
December
2015
|
|
|
|
|
175,000
|
|
4.51
|
|
|
|
|
|
|
|
|
|
|
|
(2)
|
EOG has entered into
natural gas price swap contracts which give counterparties the
option of entering into price swap contracts at future dates.
All such options are exercisable monthly up until the settlement
date of each monthly contract. If the counterparties exercise
all such options, the notional volume of EOG's existing natural gas
price swap contracts will increase by 175,000 MMBtud at an average
price of $4.51 per MMBtu for the month of December 2015.
|
|
$/Bbl
Dollars per barrel
|
$/MMBtu Dollars per
million British thermal units
|
Bbld
Barrels per day
|
MMBtu
Million British thermal units
|
MMBtud Million
British thermal units per day
|
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 (GAAP),
Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP),
Respectively
|
(Unaudited; in
millions, except ratio data)
|
|
|
|
|
|
|
|
|
|
The following chart
reconciles Net Interest Expense (GAAP), Net Income (GAAP), Current
and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to
After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income
(Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization
(Non-GAAP), respectively, as used in the Return on Capital Employed
(ROCE) and Return on Equity (ROE) calculations. EOG believes
this presentation may be useful to investors who follow the
practice of some industry analysts who utilize After-Tax Net
Interest Expense, Adjusted Net Income, Net Debt and Total
Capitalization (Non-GAAP) in their ROCE and ROE calculations.
EOG management uses this information for comparative purposes
within the industry.
|
|
|
|
|
|
|
|
|
|
|
|
2014
|
|
|
2013
|
|
|
2012
|
Return on Capital
Employed (ROCE) (Non-GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Interest Expense
(GAAP)
|
$
|
201
|
|
$
|
235
|
|
|
|
Tax Benefit Imputed
(based on 35%)
|
|
(70)
|
|
|
(82)
|
|
|
|
After-Tax Net
Interest Expense (Non-GAAP) - (a)
|
$
|
131
|
|
$
|
153
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (GAAP) -
(b)
|
$
|
2,915
|
|
$
|
2,197
|
|
|
|
|
|
|
|
|
|
|
|
|
Add: After-Tax
Mark-to-Market Commodity Derivative Contracts Impact
|
|
(515)
|
|
|
182
|
|
|
|
Add:
Impairments of Certain Assets, Net of Tax
|
|
553
|
|
|
4
|
|
|
|
Add: Tax
Expense Related to the Repatriation of Accumulated
Foreign Earnings in Future Years
|
|
250
|
|
|
-
|
|
|
|
Less: Net Gains on
Asset Dispositions, Net of Tax
|
|
(487)
|
|
|
(137)
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Net Income
(Non-GAAP) - (c)
|
$
|
2,716
|
|
$
|
2,246
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Stockholders'
Equity - (d)
|
$
|
17,713
|
|
$
|
15,418
|
|
$
|
13,285
|
|
|
|
|
|
|
|
|
|
Average Total
Stockholders' Equity * - (e)
|
$
|
16,566
|
|
$
|
14,352
|
|
|
|
|
|
|
|
|
|
|
|
|
Current and Long-Term
Debt (GAAP) - (f)
|
$
|
5,910
|
|
$
|
5,913
|
|
$
|
6,312
|
Less:
Cash
|
|
(2,087)
|
|
|
(1,318)
|
|
|
(876)
|
Net Debt (Non-GAAP) -
(g)
|
$
|
3,823
|
|
$
|
4,595
|
|
$
|
5,436
|
|
|
|
|
|
|
|
|
|
Total Capitalization
(GAAP) - (d) + (f)
|
$
|
23,623
|
|
$
|
21,331
|
|
$
|
19,597
|
|
|
|
|
|
|
|
|
|
Total Capitalization
(Non-GAAP) - (d) + (g)
|
$
|
21,536
|
|
$
|
20,013
|
|
$
|
18,721
|
|
|
|
|
|
|
|
|
|
Average Total
Capitalization (Non-GAAP) * - (h)
|
$
|
20,775
|
|
$
|
19,367
|
|
|
|
|
|
|
|
|
|
|
|
|
ROCE (GAAP Net
Income) - [(a) + (b)] /
(h)
|
|
14.7
|
%
|
|
12.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
ROCE (Non-GAAP
Adjusted Net Income) - [(a) + (c)] /
(h)
|
|
13.7
|
%
|
|
12.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
Return on Equity
(ROE) (Non-GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROE (GAAP Net
Income) - (b) / (e)
|
|
17.6
|
%
|
|
15.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
ROE (Non-GAAP
Adjusted Net Income) - (c) / (e)
|
|
16.4
|
%
|
|
15.6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
* Average for the
current and immediately preceding year
|
|
|
|
|
|
|
|
|
EOG RESOURCES,
INC.
|
Fourth Quarter and
Full Year 2015 Forecast and Benchmark Commodity
Pricing
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Fourth Quarter and
Full Year 2015 Forecast
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The forecast items
for the fourth quarter and full year 2015 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 2015
|
|
|
|
Full Year
2015
|
|
Daily
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil and Condensate
Volumes (MBbld)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
274.0
|
|
-
|
|
280.0
|
|
|
|
281.8
|
|
-
|
|
283.3
|
|
Trinidad
|
|
0.8
|
|
-
|
|
1.0
|
|
|
|
0.8
|
|
-
|
|
1.0
|
|
Other International
|
|
0.0
|
|
-
|
|
5.0
|
|
|
|
0.1
|
|
-
|
|
1.4
|
|
Total
|
|
274.8
|
|
-
|
|
286.0
|
|
|
|
282.7
|
|
-
|
|
285.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids Volumes
(MBbld)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
72.0
|
|
-
|
|
78.0
|
|
|
|
75.2
|
|
-
|
|
76.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Volumes
(MMcfd)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
840
|
|
-
|
|
880
|
|
|
|
881
|
|
-
|
|
891
|
|
Trinidad
|
|
350
|
|
-
|
|
370
|
|
|
|
344
|
|
-
|
|
349
|
|
Other International
|
|
24
|
|
-
|
|
30
|
|
|
|
29
|
|
-
|
|
31
|
|
Total
|
|
1,214
|
|
-
|
|
1,280
|
|
|
|
1,254
|
|
-
|
|
1,271
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Equivalent Volumes
(MBoed)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
486.0
|
|
-
|
|
504.7
|
|
|
|
503.8
|
|
-
|
|
508.5
|
|
Trinidad
|
|
59.1
|
|
-
|
|
62.7
|
|
|
|
58.1
|
|
-
|
|
59.2
|
|
Other International
|
|
4.0
|
|
-
|
|
10.0
|
|
|
|
4.9
|
|
-
|
|
6.6
|
|
Total
|
|
549.1
|
|
-
|
|
577.4
|
|
|
|
566.8
|
|
-
|
|
574.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit Costs
($/Boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease and Well
|
$
|
5.30
|
|
-
|
$
|
6.10
|
|
|
$
|
5.79
|
|
-
|
$
|
5.99
|
|
Transportation Costs
|
$
|
3.80
|
|
-
|
$
|
4.70
|
|
|
$
|
4.02
|
|
-
|
$
|
4.24
|
|
Depreciation, Depletion and Amortization
|
$
|
14.50
|
|
-
|
$
|
15.50
|
|
|
$
|
15.79
|
|
-
|
$
|
16.02
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses
($MM)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration, Dry Hole and
Impairment (A)
|
$
|
140
|
|
-
|
$
|
160
|
|
|
$
|
501
|
|
-
|
$
|
521
|
|
General and
Administrative
|
$
|
90
|
|
-
|
$
|
98
|
|
|
$
|
348
|
|
-
|
$
|
356
|
|
Gathering and
Processing
|
$
|
32
|
|
-
|
$
|
36
|
|
|
$
|
139
|
|
-
|
$
|
143
|
|
Capitalized
Interest
|
$
|
10
|
|
-
|
$
|
11
|
|
|
$
|
43
|
|
-
|
$
|
44
|
|
Net Interest
|
$
|
59
|
|
-
|
$
|
60
|
|
|
$
|
233
|
|
-
|
$
|
234
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Taxes Other Than
Income (% of Wellhead Revenue)
|
|
6.2
|
%
|
-
|
|
6.6
|
%
|
|
|
6.5
|
%
|
-
|
|
6.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective
Rate
|
|
5
|
%
|
-
|
|
15
|
%
|
|
|
33
|
%
|
-
|
|
36
|
%
|
Current Taxes
($MM)
|
$
|
15
|
|
-
|
$
|
30
|
|
|
$
|
110
|
|
-
|
$
|
125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures
(Excluding Acquisitions, $MM)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and Development,
Excluding Facilities
|
|
|
|
|
|
|
|
|
$
|
3,700
|
|
-
|
$
|
3,800
|
|
Exploration and Development
Facilities
|
|
|
|
|
|
|
|
|
$
|
725
|
|
-
|
$
|
775
|
|
Gathering, Processing and
Other
|
|
|
|
|
|
|
|
|
$
|
275
|
|
-
|
$
|
325
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pricing - (Refer to
Benchmark Commodity Pricing in text)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil and Condensate
($/Bbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Differentials
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States - above (below) WTI
|
$
|
(2.00)
|
|
-
|
$
|
0.00
|
|
|
$
|
(1.27)
|
|
-
|
$
|
(0.78)
|
|
Trinidad - above (below) WTI
|
$
|
(10.50)
|
|
-
|
$
|
(9.50)
|
|
|
$
|
(9.25)
|
|
-
|
$
|
(9.00)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
Liquids
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realizations as % of WTI
|
|
27
|
%
|
-
|
|
31
|
%
|
|
|
29
|
%
|
-
|
|
30
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
($/Mcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Differentials
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States - above (below) NYMEX Henry Hub
|
$
|
(0.90)
|
|
-
|
$
|
(0.45)
|
|
|
$
|
(0.71)
|
|
-
|
$
|
(0.60)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realizations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trinidad
|
$
|
2.40
|
|
-
|
$
|
2.90
|
|
|
$
|
2.85
|
|
-
|
$
|
2.98
|
|
Other International
|
$
|
3.25
|
|
-
|
$
|
3.75
|
|
|
$
|
4.31
|
|
-
|
$
|
4.42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(A) Excludes
the impairments of proved oil and gas properties, other property,
plant and equipment and other assets in the third quarter of 2015
of $6,213 million.
|
|
Definitions
|
|
$/Bbl
|
U.S. Dollars per
barrel
|
$/Boe
|
U.S. Dollars per
barrel of oil equivalent
|
$/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-reports-third-quarter-2015-results-increases-delaware-basin-net-resource-potential-by-10-bnboe-300173633.html
SOURCE EOG Resources, Inc.