HOUSTON, May 8, 2017 /PRNewswire/ --
- Exceeds High-End of Oil Production Forecast
- Increases Premium Net Resource Potential by 27 Percent to 6.5
BnBoe
- Reduces Completed Well Costs by 6 Percent in Major Plays
Compared to 2016
- Completes Four Record-Setting Permian Basin Horizontal Oil
Wells
EOG Resources, Inc. (NYSE: EOG) (EOG) today reported first
quarter 2017 net income of $28.5
million, or $0.05 per share.
This compares to a first quarter 2016 net loss of $471.8 million, or $0.86 per share.
Adjusted non-GAAP net income for the first quarter 2017 was
$89.4 million, or $0.15 per share, compared to an adjusted non-GAAP
net loss of $455.4 million, or
$0.83 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 one-time
items. (Please refer to the attached tables for the
reconciliation of non-GAAP measures to GAAP measures.)
Higher commodity prices, increased production volumes, well
productivity improvements and overall per-unit cost reductions
resulted in increases to adjusted non-GAAP net income,
discretionary cash flow and EBITDAX during the first quarter 2017
compared to the first quarter 2016. (Please refer to the
attached tables for the reconciliation of non-GAAP measures to GAAP
measures.)
Operational Highlights
EOG set a company record for crude oil volumes in the first
quarter 2017 by producing 315,700 barrels of oil per day (Bopd), an
18 percent increase compared to the first quarter 2016. This
strong production growth reflects the company's premium drilling
strategy and technical advances in its prolific plays across
multiple basins. EOG defines premium inventory as prospective
well locations that will earn a minimum 30 percent direct after-tax
rate of return at $40 crude oil and
$2.50 natural gas prices.
EOG continues to reduce total well costs in each of its major
plays. First quarter 2017 average completed well costs were 6
percent lower than full year 2016 averages in the Eagle Ford,
Delaware Basin and Bakken using
normalized lateral lengths. For all three plays, the overall
cost reductions were achieved in spite of service and equipment
price inflation in certain areas, which were more than offset by
continued advances in drilling and completion tools and techniques,
benefits from extended lateral lengths, and new contracts at lower
prices.
During the first quarter 2017, lease and well expenses on a
per-unit basis increased 4 percent compared to the same prior year
period primarily because of last year's disposition of natural gas
producing assets with lower per-unit operating costs, the Yates
acquisition properties with higher per-unit operating costs, and
higher production expenses in the United
Kingdom. Per-unit transportation costs decreased 8
percent and depreciation, depletion and amortization expenses
decreased 14 percent on a per-unit basis year-over-year.
Total general and administrative expenses decreased 3 percent
compared to the first quarter 2016 primarily due to expenses
related to a voluntary retirement program in 2016.
"EOG continues to lead the industry in well productivity, with
record-setting well performance driving company record crude oil
volumes," said William R. "Bill" Thomas, Chairman and Chief
Executive Officer. "During the first quarter 2017, we
increased our premium inventory by 1,200 net well locations and 1.4
BnBoe of premium net resource potential, which is approximately 2.5
times the number of wells we expect to complete during all of
2017. EOG remains committed to creating significant
shareholder value through low-cost, high-return growth and organic
resource expansion."
Delaware Basin
In the first quarter 2017, EOG continued to increase development
activity and expand resource potential in the Delaware Basin.
EOG increased its Delaware Basin
premium net locations by 700 to 4,150 locations.
EOG completed 33 wells in the Delaware Basin Wolfcamp in the first quarter
2017 with an average treated lateral length of 5,600 feet per well
and average 30-day initial production rates per well of 2,855
barrels of oil equivalent per day (Boed), or 1,850 Bopd, 450
barrels per day (Bpd) of natural gas liquids (NGLs) and 3.3 million
cubic feet per day (MMcfd) of natural gas.
Of special note is a four-well pattern in Lea County, N.M., the Whirling Wind 14 Fed Com
#701H and the Whirling Wind 11 Fed Com #702H - #704H which were
completed with an average treated lateral length of 7,100 feet per
well and average 30-day initial production rates per well of 5,060
Boed, or 3,510 Bopd, 700 Bpd of NGLs and 5.1 MMcfd of natural
gas. Each well exceeded the prior all-time industry record
for 30-day initial production from Permian Basin horizontal oil
wells.
"EOG's Whirling Wind wells shattered industry records in the
Permian Basin," said Thomas. "Our advanced technology and
proprietary techniques are leading to break-through well
performance across our diverse portfolio of premium plays."
In the Delaware Basin Bone
Spring, EOG completed three wells in the first quarter 2017 with an
average treated lateral length of 8,800 feet per well and average
30-day initial production rates per well of 3,255 Boed, or 2,525
Bopd, 335 Bpd of NGLs and 2.4 MMcfd of natural gas.
In the Delaware Basin Leonard,
EOG completed three wells in the first quarter 2017 with an average
treated lateral length of 3,800 feet per well and average 30-day
initial production rates per well of 840 Boed, or 505 Bopd, 150 Bpd
of NGLs and 1.1 MMcfd of natural gas. These first quarter
2017 completions were drilled prior to 2016.
South Texas Eagle Ford
EOG's South Texas Eagle Ford continued to be the most active
area in the company in the first quarter 2017. In addition to
significant development activity, EOG expanded its Eagle Ford
premium net locations by 500 to more than 2,400 locations.
Part of the increase in premium locations was enabled by a shift to
longer lateral drilling units. Seven wells that began
production in the first quarter 2017 had lateral lengths in excess
of 10,000 feet.
In the first quarter 2017, EOG completed 65 wells in the Eagle
Ford with an average treated lateral length of 6,500 feet per well
and average 30-day initial production rates per well of 1,390 Boed,
or 1,130 Bopd, 130 Bpd of NGLs and 0.8 MMcfd of natural gas.
South Texas Austin Chalk
In the first quarter 2017, testing continued in the South Texas
Austin Chalk. EOG completed five wells in Karnes County with an average treated lateral
length of 5,700 feet per well and average 30-day initial production
rates per well of 2,605 Boed, or 1,895 Bopd, 360 Bpd of NGLs and
2.1 MMcfd of natural gas.
Rockies and the Bakken
During the first quarter, EOG continued to develop its premium
Powder River Basin position and reduce its inventory of drilled
uncompleted wells in the Bakken.
In the Powder River Basin, EOG completed five wells in the first
quarter 2017 with an average treated lateral length of 4,900 feet
per well and average 30-day initial production rates per well of
1,160 Boed, or 950 Bopd, 75 Bpd of NGLs and 0.8 MMcfd of natural
gas.
In the North Dakota Bakken, EOG completed 27 wells in the first
quarter 2017 with an average treated lateral length of 8,500 feet
per well and average 30-day initial production rates per well of
715 Boed, or 640 Bopd, 40 Bpd of NGLs and 0.2 MMcfd of natural gas.
The first quarter 2017 completions in the Bakken included 24
wells that were drilled prior to 2016. Three wells completed
in the first quarter 2017 were the first wells completed in the
Bakken Lite area with EOG's high-density fracs. These three
wells had an average treated lateral length of 7,700 feet per well
and average 30-day initial production rates per well of 955 Boed,
or 795 Bopd, 85 Bpd of NGLs and 0.5 MMcfd of natural gas.
Hedging Activity
For the period June 1 through November
30, 2017, EOG has natural gas financial price swap contracts
in place for 30,000 million British thermal units (MMBtu) per day
at a weighted average price of $3.10
per MMBtu. For the period March 1
through November 30, 2018, EOG has natural gas financial
price swap contracts in place for 35,000 MMBtu per day at a
weighted average price of $3.00 per
MMBtu.
For the period June 1 through November
30, 2017, EOG has sold natural gas call option contracts for
213,750 MMBtu per day at an average strike price of $3.44 per MMBtu. For the period
March 1 through November 30, 2018,
EOG has sold natural gas call option contracts for 120,000 MMBtu
per day at an average strike price of $3.38 per MMBtu.
For the period June 1 through November
30, 2017, EOG has purchased natural gas put option contracts
for 171,000 MMBtu per day at an average strike price of
$2.92 per MMBtu. For the period
March 1 through November 30, 2018,
EOG has purchased natural gas put option contracts for 96,000 MMBtu
per day at an average strike price of $2.94 per MMBtu.
For the period June 1 through November
30, 2017, EOG has natural gas collar contracts for 80,000
MMBtu per day at an average ceiling price of $3.69 per MMBtu and an average floor price of
$3.20 per MMBtu.
EOG did not have a net crude oil hedge position as of
March 31, 2017.
A comprehensive summary of crude oil and natural gas derivative
contracts is provided in the attached tables.
Capital Structure and Asset Sales
At March 31, 2017, EOG's total
debt outstanding was $7.0 billion for
a debt-to-total capitalization ratio of 33 percent. Considering
cash on the balance sheet at the end of the first quarter, EOG's
net debt was $5.4 billion for a net
debt-to-total capitalization ratio of 28 percent. For a
reconciliation of non-GAAP measures to GAAP measures, please refer
to the attached tables.
Proceeds from asset sales year-to-date 2017 totaled $118 million. This includes proceeds from
two transactions that closed in the second quarter 2017.
Conference Call May 9,
2017
EOG's first quarter 2017 results conference call will be
available via live audio webcast at 9 a.m.
Central time (10 a.m. Eastern
time) on Tuesday, May 9, 2017.
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 May 23, 2017.
EOG Resources, Inc. is one of the largest independent
(non-integrated) crude oil and natural gas companies in
the United States with proved
reserves in the United States,
Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on
the New York Stock Exchange and is traded under the ticker symbol
"EOG."
This press release includes forward-looking statements within
the meaning of Section 27A of the Securities Act of 1933, as
amended, and Section 21E of the Securities Exchange Act of 1934, as
amended. All statements, other than statements of historical
facts, including, among others, statements and projections
regarding EOG's future financial position, operations, performance,
business strategy, returns, budgets, reserves, levels of
production, costs and asset sales, statements regarding future
commodity prices and statements regarding the plans and objectives
of EOG's management for future operations, are forward-looking
statements. EOG typically uses words such as "expect,"
"anticipate," "estimate," "project," "strategy," "intend," "plan,"
"target," "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 to which EOG is successful in its completion of
planned asset dispositions;
- the extent and effect of any hedging activities engaged in by
EOG;
- the timing and extent of changes in foreign currency exchange
rates, interest rates, inflation rates, global and domestic
financial market conditions and global and domestic general
economic conditions;
- political conditions and developments around the world (such as
political instability and armed conflict), including in the areas
in which EOG operates;
- the use of competing energy sources and the development of
alternative energy sources;
- the extent to which EOG incurs uninsured losses and liabilities
or losses and liabilities in excess of its insurance coverage;
- acts of war and terrorism and responses to these acts;
- physical, electronic and cyber security breaches; and
- the other factors described under ITEM 1A, Risk Factors, on
pages 13 through 22 of EOG's Annual Report on Form 10-K for the
fiscal year ended December 31, 2016,
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, 2016, 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
|
|
W. John
Wagner
|
|
(713)
571-4404
|
|
|
|
Media and
Investors
|
|
Kimberly M.
Ehmer
|
|
(713)
571-4676
|
EOG RESOURCES,
INC.
|
Financial
Report
|
(Unaudited; in
millions, except per share data)
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
March
31,
|
|
2017
|
|
2016
|
|
|
|
|
|
|
Net Operating
Revenues
|
$
|
2,610.6
|
|
$
|
1,354.3
|
Net Income
(Loss)
|
$
|
28.5
|
|
$
|
(471.8)
|
Net Income (Loss) Per
Share
|
|
|
|
|
|
Basic
|
$
|
0.05
|
|
$
|
(0.86)
|
Diluted
|
$
|
0.05
|
|
$
|
(0.86)
|
Average Number of
Common Shares
|
|
|
|
|
|
Basic
|
|
573.9
|
|
|
546.7
|
Diluted
|
|
578.6
|
|
|
546.7
|
|
|
|
|
|
|
|
|
|
|
|
|
Summary Income
Statements
|
(Unaudited; in
thousands, except per share data)
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
March
31,
|
|
2017
|
|
2016
|
Net Operating
Revenues
|
|
|
|
Crude Oil
and Condensate
|
$
|
1,430,061
|
|
$
|
753,711
|
Natural
Gas Liquids
|
|
153,444
|
|
|
75,319
|
Natural
Gas
|
|
230,602
|
|
|
165,503
|
Gains on
Mark-to-Market Commodity
|
|
|
|
|
|
Derivative Contracts
|
|
62,020
|
|
|
5,435
|
Gathering,
Processing and Marketing
|
|
726,537
|
|
|
333,953
|
Gains
(Losses) on Asset Dispositions, Net
|
|
(16,758)
|
|
|
9,147
|
Other,
Net
|
|
24,659
|
|
|
11,281
|
Total
|
|
2,610,565
|
|
|
1,354,349
|
Operating
Expenses
|
|
|
|
|
|
Lease and
Well
|
|
255,777
|
|
|
240,865
|
Transportation Costs
|
|
178,714
|
|
|
190,454
|
Gathering
and Processing Costs
|
|
38,144
|
|
|
28,524
|
Exploration Costs
|
|
56,894
|
|
|
29,829
|
Dry Hole
Costs
|
|
-
|
|
|
246
|
Impairments
|
|
193,187
|
|
|
71,617
|
Marketing
Costs
|
|
736,536
|
|
|
340,854
|
Depreciation, Depletion and Amortization
|
|
816,036
|
|
|
928,891
|
General
and Administrative
|
|
97,238
|
|
|
100,531
|
Taxes
Other Than Income
|
|
130,293
|
|
|
60,679
|
Total
|
|
2,502,819
|
|
|
1,992,490
|
|
|
|
|
|
|
Operating Income
(Loss)
|
|
107,746
|
|
|
(638,141)
|
|
|
|
|
|
|
Other Income
(Expense), Net
|
|
3,151
|
|
|
(4,437)
|
|
|
|
|
|
|
Income (Loss) Before
Interest Expense and Income Taxes
|
110,897
|
|
|
(642,578)
|
|
|
|
|
|
|
Interest Expense,
Net
|
|
71,515
|
|
|
68,390
|
|
|
|
|
|
|
Income (Loss) Before
Income Taxes
|
|
39,382
|
|
|
(710,968)
|
|
|
|
|
|
|
Income Tax Provision
(Benefit)
|
|
10,865
|
|
|
(239,192)
|
|
|
|
|
|
|
Net Income
(Loss)
|
$
|
28,517
|
|
$
|
(471,776)
|
|
|
|
|
|
|
Dividends Declared
per Common Share
|
$
|
0.1675
|
|
$
|
0.1675
|
|
|
EOG RESOURCES,
INC.
|
Operating
Highlights
|
(Unaudited)
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
March
31,
|
|
2017
|
|
2016
|
Wellhead Volumes
and Prices
|
|
Crude Oil and
Condensate Volumes (MBbld) (A)
|
|
United
States
|
|
312.5
|
|
|
265.8
|
Trinidad
|
|
0.8
|
|
|
0.7
|
Other International
(B)
|
|
2.4
|
|
|
1.4
|
Total
|
|
315.7
|
|
|
267.9
|
|
|
|
|
|
|
Average Crude Oil and
Condensate Prices ($/Bbl) (C)
|
|
|
|
|
|
United
States
|
$
|
50.38
|
|
$
|
30.87
|
Trinidad
|
|
41.56
|
|
|
22.78
|
Other International
(B)
|
|
47.77
|
|
|
32.33
|
Composite
|
|
50.34
|
|
|
30.85
|
|
|
|
|
|
|
Natural Gas Liquids
Volumes (MBbld) (A)
|
|
|
|
|
|
United
States
|
|
78.8
|
|
|
79.4
|
Other International
(B)
|
|
-
|
|
|
-
|
Total
|
|
78.8
|
|
|
79.4
|
|
|
|
|
|
|
Average Natural Gas
Liquids Prices ($/Bbl) (C)
|
|
|
|
|
|
United
States
|
$
|
21.63
|
|
$
|
10.41
|
Other International
(B)
|
|
-
|
|
|
-
|
Composite
|
|
21.63
|
|
|
10.41
|
|
|
|
|
|
|
Natural Gas Volumes
(MMcfd) (A)
|
|
|
|
|
|
United
States
|
|
728
|
|
|
829
|
Trinidad
|
|
308
|
|
|
361
|
Other International
(B)
|
|
22
|
|
|
25
|
Total
|
|
1,058
|
|
|
1,215
|
|
|
|
|
|
|
Average Natural Gas
Prices ($/Mcf) (C)
|
|
|
|
|
|
United
States
|
$
|
2.32
|
|
$
|
1.27
|
Trinidad
|
|
2.57
|
|
|
1.88
|
Other International
(B)
|
|
3.76
|
|
|
3.63
|
Composite
|
|
2.42
|
|
|
1.50
|
|
|
|
|
|
|
Crude Oil Equivalent
Volumes (MBoed) (D)
|
|
|
|
|
|
United
States
|
|
512.6
|
|
|
483.6
|
Trinidad
|
|
52.2
|
|
|
60.8
|
Other International
(B)
|
|
5.9
|
|
|
5.5
|
Total
|
|
570.7
|
|
|
549.9
|
|
|
|
|
|
|
Total MMBoe
(D)
|
|
51.4
|
|
|
50.0
|
|
(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. The Argentina operations were sold in
the third quarter of 2016.
|
(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)
|
|
|
|
|
|
|
|
March
31,
|
|
December
31,
|
|
2017
|
|
2016
|
ASSETS
|
Current
Assets
|
|
|
|
|
|
Cash and Cash
Equivalents
|
$
|
1,546,566
|
|
$
|
1,599,895
|
Accounts Receivable,
Net
|
|
1,187,112
|
|
|
1,216,320
|
Inventories
|
|
314,194
|
|
|
350,017
|
Assets from Price Risk
Management Activities
|
|
1,142
|
|
|
-
|
Income Taxes
Receivable
|
|
80,503
|
|
|
12,305
|
Other
|
|
264,559
|
|
|
206,679
|
Total
|
|
3,394,076
|
|
|
3,385,216
|
|
|
|
|
|
|
Property, Plant
and Equipment
|
|
|
|
|
|
Oil and Gas Properties
(Successful Efforts Method)
|
|
50,195,608
|
|
|
49,592,091
|
Other Property, Plant and
Equipment
|
|
3,977,721
|
|
|
4,008,564
|
Total Property, Plant and Equipment
|
|
54,173,329
|
|
|
53,600,655
|
Less: Accumulated
Depreciation, Depletion and Amortization
|
|
(28,566,869)
|
|
|
(27,893,577)
|
Total Property, Plant and Equipment, Net
|
|
25,606,460
|
|
|
25,707,078
|
Deferred Income
Taxes
|
|
16,232
|
|
|
16,140
|
Other
Assets
|
|
195,206
|
|
|
190,767
|
Total
Assets
|
$
|
29,211,974
|
|
$
|
29,299,201
|
|
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS' EQUITY
|
Current
Liabilities
|
|
|
|
|
|
Accounts Payable
|
$
|
1,556,875
|
|
$
|
1,511,826
|
Accrued Taxes
Payable
|
|
143,710
|
|
|
118,411
|
Dividends Payable
|
|
96,155
|
|
|
96,120
|
Liabilities from Price Risk
Management Activities
|
|
7,636
|
|
|
61,817
|
Current Portion of Long-Term
Debt
|
|
6,579
|
|
|
6,579
|
Other
|
|
221,052
|
|
|
232,538
|
Total
|
|
2,032,007
|
|
|
2,027,291
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term
Debt
|
|
6,980,008
|
|
|
6,979,779
|
Other
Liabilities
|
|
1,248,102
|
|
|
1,282,142
|
Deferred Income
Taxes
|
|
5,023,626
|
|
|
5,028,408
|
Commitments and
Contingencies
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders'
Equity
|
|
|
|
|
|
Common Stock, $0.01
Par, 640,000,000 Shares Authorized and
|
|
|
|
|
|
577,636,588Shares Issued at March 31, 2017 and
576,950,272
|
|
|
|
|
|
Shares
Issued at December 31, 2016
|
|
205,776
|
|
|
205,770
|
Additional Paid in
Capital
|
|
5,447,291
|
|
|
5,420,385
|
Accumulated Other
Comprehensive Loss
|
|
(18,664)
|
|
|
(19,010)
|
Retained Earnings
|
|
8,329,951
|
|
|
8,398,118
|
Common Stock Held in Treasury, 378,442 Shares at March 31,
2017
|
|
|
|
|
|
and 250,155 Shares at December 31, 2016
|
|
(36,123)
|
|
|
(23,682)
|
Total Stockholders' Equity
|
|
13,928,231
|
|
|
13,981,581
|
Total Liabilities
and Stockholders' Equity
|
$
|
29,211,974
|
|
$
|
29,299,201
|
|
|
EOG RESOURCES,
INC.
|
Summary Statements
of Cash Flows
|
(Unaudited; in
thousands)
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
March
31,
|
|
2017
|
|
2016
|
Cash Flows from
Operating Activities
|
|
|
|
|
|
Reconciliation of Net
Income (Loss) to Net Cash Provided by Operating
Activities:
|
|
|
|
|
|
Net Income (Loss)
|
$
|
28,517
|
|
$
|
(471,776)
|
Items Not Requiring
(Providing) Cash
|
|
|
|
|
|
Depreciation, Depletion and Amortization
|
|
816,036
|
|
|
928,891
|
Impairments
|
|
193,187
|
|
|
71,617
|
Stock-Based Compensation Expenses
|
|
30,460
|
|
|
32,380
|
Deferred Income Taxes
|
|
694
|
|
|
(196,696)
|
(Gains) Losses on Asset Dispositions, Net
|
|
16,758
|
|
|
(9,147)
|
Other, Net
|
|
(3,052)
|
|
|
5,442
|
Dry Hole Costs
|
|
-
|
|
|
246
|
Mark-to-Market Commodity
Derivative Contracts
|
|
|
|
|
|
Total Gains
|
|
(62,020)
|
|
|
(5,435)
|
Net Cash Received from Settlements of Commodity Derivative
Contracts
|
|
1,912
|
|
|
17,687
|
Other, Net
|
|
(428)
|
|
|
1,407
|
Changes in Components of
Working Capital and Other Assets and Liabilities
|
|
|
|
|
|
Accounts Receivable
|
|
28,688
|
|
|
132,398
|
Inventories
|
|
24,736
|
|
|
57,578
|
Accounts Payable
|
|
20,426
|
|
|
(289,627)
|
Accrued Taxes Payable
|
|
(38,613)
|
|
|
2,460
|
Other Assets
|
|
(44,677)
|
|
|
3,946
|
Other Liabilities
|
|
(51,251)
|
|
|
7,992
|
Changes in Components of
Working Capital Associated with Investing and Financing
|
|
|
|
|
|
Activities
|
|
(63,324)
|
|
|
2,228
|
Net Cash Provided
by Operating Activities
|
|
898,049
|
|
|
291,591
|
|
|
|
|
|
|
Investing Cash
Flows
|
|
|
|
|
|
Additions to Oil and Gas
Properties
|
|
(912,227)
|
|
|
(547,399)
|
Additions to Other Property,
Plant and Equipment
|
|
(34,336)
|
|
|
(25,792)
|
Proceeds from Sales of
Assets
|
|
46,812
|
|
|
6,667
|
Changes in Components of
Working Capital Associated with Investing Activities
|
|
63,324
|
|
|
(2,228)
|
Net Cash Used in
Investing Activities
|
|
(836,427)
|
|
|
(568,752)
|
|
|
|
|
|
|
Financing Cash
Flows
|
|
|
|
|
|
Net Commercial Paper
Repayments
|
|
-
|
|
|
(259,718)
|
Long-Term Debt
Borrowings
|
|
-
|
|
|
991,097
|
Long-Term Debt
Repayments
|
|
-
|
|
|
(400,000)
|
Dividends Paid
|
|
(96,707)
|
|
|
(92,170)
|
Treasury Stock
Purchased
|
|
(18,628)
|
|
|
(12,672)
|
Proceeds from Stock Options
Exercised and Employee Stock Purchase Plan
|
|
2,356
|
|
|
2,688
|
Debt Issuance
Costs
|
|
-
|
|
|
(1,592)
|
Repayment of Capital Lease
Obligation
|
|
(1,619)
|
|
|
(1,569)
|
Net Cash (Used in)
Provided by Financing Activities
|
|
(114,598)
|
|
|
226,064
|
|
|
|
|
|
|
Effect of Exchange
Rate Changes on Cash
|
|
(353)
|
|
|
1,072
|
|
|
|
|
|
|
Decrease in Cash
and Cash Equivalents
|
|
(53,329)
|
|
|
(50,025)
|
Cash and Cash
Equivalents at Beginning of Period
|
|
1,599,895
|
|
|
718,506
|
Cash and Cash
Equivalents at End of Period
|
$
|
1,546,566
|
|
$
|
668,481
|
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 periods ended March 31, 2017 and 2016
reported Net Income (Loss) (GAAP) to reflect actual net cash
received from settlements of commodity derivative contracts by
eliminating the unrealized mark-to-market gains from these
transactions, to eliminate the net (gains) losses on asset
dispositions in 2017 and 2016, to add back impairment charges
related to certain of EOG's assets in 2017 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
|
|
March 31,
2017
|
|
March 31,
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
$
39,382
|
|
$(10,865)
|
|
$28,517
|
|
$
0.05
|
|
$(710,968)
|
|
$239,192
|
|
$(471,776)
|
|
$
(0.86)
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains on
Mark-to-Market Commodity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Contracts
|
(62,020)
|
|
22,191
|
|
(39,829)
|
|
(0.07)
|
|
(5,435)
|
|
1,938
|
|
(3,497)
|
|
(0.01)
|
Net Cash
Received from Settlements of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
Derivative Contracts
|
1,912
|
|
(684)
|
|
1,228
|
|
-
|
|
17,687
|
|
(6,306)
|
|
11,381
|
|
0.02
|
Add: Net
(Gains) Losses on Asset Dispositions
|
16,758
|
|
(5,736)
|
|
11,022
|
|
0.02
|
|
(9,147)
|
|
3,210
|
|
(5,937)
|
|
(0.01)
|
Add:
Impairments
|
137,751
|
|
(49,287)
|
|
88,464
|
|
0.15
|
|
-
|
|
-
|
|
-
|
|
-
|
Add: Voluntary
Retirement Expense
|
-
|
|
-
|
|
-
|
|
-
|
|
22,391
|
|
(7,982)
|
|
14,409
|
|
0.03
|
Adjustments to Net
Income (Loss)
|
94,401
|
|
(33,516)
|
|
60,885
|
|
0.10
|
|
25,496
|
|
(9,140)
|
|
16,356
|
|
0.03
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Net
Income (Loss) (Non-GAAP)
|
$133,783
|
|
$(44,381)
|
|
$89,402
|
|
$
0.15
|
|
$(685,472)
|
|
$230,052
|
|
$(455,420)
|
|
$
(0.83)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Number of
Common Shares (GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
573,935
|
|
|
|
|
|
|
|
546,715
|
Diluted
|
|
|
|
|
|
|
578,593
|
|
|
|
|
|
|
|
546,715
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Number of
Common Shares (Non-GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
573,935
|
|
|
|
|
|
|
|
546,715
|
Diluted
|
|
|
|
|
|
|
578,593
|
|
|
|
|
|
|
|
546,715
|
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 periods ended March 31, 2017 and 2016
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
|
|
March
31,
|
|
2017
|
|
2016
|
|
|
|
|
|
|
Net Cash Provided by
Operating Activities (GAAP)
|
$
|
898,049
|
|
$
|
291,591
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
Exploration Costs
(excluding Stock-Based Compensation Expenses)
|
|
50,734
|
|
|
23,357
|
Changes in Components
of Working Capital and Other Assets
|
|
|
|
|
|
and
Liabilities
|
|
|
|
|
|
Accounts
Receivable
|
|
(28,688)
|
|
|
(132,398)
|
Inventories
|
|
(24,736)
|
|
|
(57,578)
|
Accounts
Payable
|
|
(20,426)
|
|
|
289,627
|
Accrued Taxes
Payable
|
|
38,613
|
|
|
(2,460)
|
Other
Assets
|
|
44,677
|
|
|
(3,946)
|
Other
Liabilities
|
|
51,251
|
|
|
(7,992)
|
Changes in Components
of Working Capital Associated with
|
|
|
|
|
|
Investing and
Financing Activities
|
|
63,324
|
|
|
(2,228)
|
|
Discretionary Cash
Flow (Non-GAAP)
|
$
|
1,072,798
|
|
$
|
397,973
|
|
|
|
|
|
|
Discretionary Cash
Flow (Non-GAAP) - Percentage Increase
|
|
170%
|
|
|
|
|
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Adjusted Earnings Before Interest Expense,
Net,
|
Income Taxes,
Depreciation, Depletion and Amortization, Exploration
Costs,
|
Dry Hole Costs,
Impairments and Additional Items (Adjusted EBITDAX)
|
(Non-GAAP)
to Net Income (Loss) (GAAP)
|
(Unaudited; in
thousands)
|
|
|
|
|
|
|
|
The following chart
adjusts the three-month periods ended March 31, 2017 and 2016
reported Net Income (Loss) (GAAP) to Earnings Before Interest
Expense, Net, Income Taxes (Income Tax Provision (Benefit)),
Depreciation, Depletion and Amortization, Exploration Costs, Dry
Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts
such amount to reflect actual net cash received from 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 Net Income
(Loss) (GAAP) to add back Interest Expense, Net, Income Taxes
(Income Tax Provision (Benefit)), Depreciation, Depletion and
Amortization, Exploration Costs, Dry Hole Costs and Impairments and
further adjust such amount to match realizations to production
settlement months and make certain other adjustments to exclude
non-recurring and certain other items. EOG management uses
this information for purposes of comparing its financial
performance with the financial performance of other companies in
the industry.
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
|
March
31,
|
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
Net Income (Loss)
(GAAP)
|
$
|
28,517
|
|
$
|
(471,776)
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
Interest Expense,
Net
|
|
71,515
|
|
|
68,390
|
|
Income Tax Provision
(Benefit)
|
|
10,865
|
|
|
(239,192)
|
|
Depreciation, Depletion and
Amortization
|
|
816,036
|
|
|
928,891
|
|
Exploration Costs
|
|
56,894
|
|
|
29,829
|
|
Dry Hole Costs
|
|
-
|
|
|
246
|
|
Impairments
|
|
193,187
|
|
|
71,617
|
|
EBITDAX (Non-GAAP)
|
|
1,177,014
|
|
|
388,005
|
|
Total Gains on MTM Commodity
Derivative Contracts
|
|
(62,020)
|
|
|
(5,435)
|
|
Net Cash Received from
Settlements of Commodity
|
|
|
|
|
|
|
Derivative Contracts
|
|
1,912
|
|
|
17,687
|
|
(Gains) Losses on Asset
Dispositions, Net
|
|
16,758
|
|
|
(9,147)
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX
(Non-GAAP)
|
$
|
1,133,664
|
|
$
|
391,110
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX
(Non-GAAP) - Percentage Increase
|
|
190%
|
|
|
|
|
|
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Net Debt (Non-GAAP) and Total
|
Capitalization
(Non-GAAP) as Used in the Calculation of
|
The Net
Debt-to-Total Capitalization Ratio (Non-GAAP) to
|
Current and
Long-Term Debt (GAAP) and Total Capitalization
(GAAP)
|
(Unaudited; in
millions, except ratio data)
|
|
|
|
|
|
|
The following chart
reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP)
and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP),
as used in the Net Debt-to-Total Capitalization ratio
calculation. A portion of the cash is associated with
international subsidiaries; tax considerations may impact debt
paydown. EOG believes this presentation may be useful to
investors who follow the practice of some industry analysts who
utilize Net Debt and Total Capitalization (Non-GAAP) in their Net
Debt-to-Total Capitalization ratio calculation. EOG
management uses this information for comparative purposes within
the industry.
|
|
|
|
|
|
|
|
At
|
|
At
|
|
March
31,
|
|
December
31,
|
|
2017
|
|
2016
|
|
|
|
|
|
|
Total Stockholders'
Equity - (a)
|
$
|
13,928
|
|
$
|
13,982
|
|
|
|
|
|
|
Current and Long-Term
Debt (GAAP) - (b)
|
|
6,987
|
|
|
6,986
|
Less:
Cash
|
|
(1,547)
|
|
|
(1,600)
|
Net Debt (Non-GAAP) -
(c)
|
|
5,440
|
|
|
5,386
|
|
|
|
|
|
|
Total Capitalization
(GAAP) - (a) + (b)
|
$
|
20,915
|
|
$
|
20,968
|
|
|
|
|
|
|
Total Capitalization
(Non-GAAP) - (a) + (c)
|
$
|
19,368
|
|
$
|
19,368
|
|
|
|
|
|
|
Debt-to-Total
Capitalization (GAAP) - (b) / [(a) + (b)]
|
|
33%
|
|
|
33%
|
|
|
|
|
|
|
Net Debt-to-Total
Capitalization (Non-GAAP) - (c) / [(a) + (c)]
|
|
28%
|
|
|
28%
|
EOG RESOURCES,
INC.
|
Crude Oil and
Natural Gas Financial Commodity
|
Derivative
Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
EOG accounts for
financial commodity derivative contracts using the mark-to-market
accounting method. On March 14, 2017, EOG executed the
optional early termination provision granting EOG the right to
terminate certain crude oil price swaps with notional volumes of
30,000 Bbld at a weighted average price of $50.05 per Bbl for the
period March 1, 2017 through June 30, 2017. EOG received cash
of $4.6 million for the early termination of these contracts.
Presented below is a comprehensive summary of EOG's crude oil price
swap contracts through May 8, 2017, with notional volumes expressed
in Bbld and prices expressed in $/Bbl.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Price
Swap Contracts
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Volume
|
|
Average
Price
|
|
|
|
|
|
|
|
|
|
(Bbld)
|
|
($/Bbl)
|
2017
|
|
|
|
|
|
|
|
|
|
|
January 1, 2017
through February 28, 2017 (closed)
|
|
|
|
|
|
|
35,000
|
|
$
50.04
|
March 1, 2017 through
June 30, 2017 (closed)
|
|
|
|
|
|
|
30,000
|
|
50.05
|
|
|
|
|
|
|
|
|
|
|
|
|
On March 14, 2017,
EOG entered into a crude oil price swap contract for the period
March 1, 2017 through June 30, 2017, with notional volumes of 5,000
Bbld at a price of $48.81 per Bbl. This contract offsets the
remaining crude oil price swap contract for the same time period
with notional volumes of 5,000 Bbld at a price of $50.00 per
Bbl. The net cash EOG will receive for settling these
contracts is $0.7 million. The offsetting contracts were
excluded from the above table.
|
|
|
|
|
|
|
|
|
|
|
|
|
Presented below is a
comprehensive summary of EOG's natural gas price swap contracts
through May 8, 2017, with notional volumes expressed in MMBtud and
prices expressed in $/MMBtu.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Price
Swap Contracts
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Volume
|
|
Average
Price
|
|
|
|
|
|
|
|
|
|
(MMBtud)
|
|
($/MMBtu)
|
2017
|
|
|
|
|
|
|
|
|
|
|
March 1, 2017 through
May 31, 2017 (closed)
|
|
|
|
|
|
|
30,000
|
|
$
3.10
|
June 1, 2017 through
November 30, 2017
|
|
|
|
|
|
|
30,000
|
|
3.10
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
March 1, 2018 through
November 30, 2018
|
|
|
|
|
|
|
35,000
|
|
$
3.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EOG has sold call
options which establish a ceiling price for the sale of notional
volumes of natural gas as specified in the call option
contracts. The call options require that EOG pay the
difference between the call option strike price and either the
average or last business day NYMEX Henry Hub natural gas price for
the contract month (Henry Hub Index Price) in the event the Henry
Hub Index Price is above the call option strike price. In
addition, EOG has purchased put options which establish a floor
price for the sale of notional volumes of natural gas as specified
in the put option contracts. The put options grant EOG the
right to receive the difference between the put option strike price
and the Henry Hub Index Price in the event the Henry Hub Index
Price is below the put option strike price. Presented below
is a comprehensive summary of EOG's natural gas call and put option
contracts through May 8, 2017, with notional volumes expressed in
MMBtud and prices expressed in $/MMbtu.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Option
Contracts
|
|
|
|
|
|
Call Options
Sold
|
|
Put Options
Purchased
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
Weighted
|
|
|
|
|
|
Volume
|
|
Average
Price
|
|
Volume
|
|
Average
Price
|
|
|
|
|
|
(MMBtud)
|
|
($/MMBtu)
|
|
(MMBtud)
|
|
($/MMBtu)
|
2017
|
|
|
|
|
|
|
|
|
|
|
March 1, 2017 through
May 31, 2017 (closed)
|
|
|
213,750
|
|
$
3.44
|
|
171,000
|
|
$
2.92
|
June 1, 2017 through
November 30, 2017
|
|
|
213,750
|
|
3.44
|
|
171,000
|
|
2.92
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
March 1, 2018 through
November 30, 2018
|
|
|
120,000
|
|
$
3.38
|
|
96,000
|
|
$
2.94
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EOG has also entered
into natural gas collar contracts, which establish ceiling and
floor prices for the sale of notional volumes of natural gas as
specified in the collar contracts. The collars require that
EOG pay the difference between the ceiling price and the Henry Hub
Index Price in the event the Henry Hub Index Price is above the
ceiling price. The collars grant EOG the right to receive the
difference between the floor price and the Henry Hub Index Price in
the event the Henry Hub Index Price is below the floor price.
Presented below is a comprehensive summary of EOG's natural gas
collar contracts through May 8, 2017, with notional volumes
expressed in MMBtud and prices expressed in
$/MMbtu.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Collar
Contracts
|
|
|
|
|
|
|
|
|
|
Weighted Average
Price ($/MMBtu)
|
|
|
|
|
|
|
|
Volume
(MMBtud)
|
|
Ceiling
Price
|
|
Floor
Price
|
2017
|
|
|
|
|
|
|
|
|
|
|
March 1, 2017 through
May 31, 2017 (closed)
|
|
|
|
|
80,000
|
|
$
3.69
|
|
$
3.20
|
June 1, 2017 through
November 30, 2017
|
|
|
|
|
80,000
|
|
3.69
|
|
3.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Definitions
|
|
|
|
|
|
|
|
|
|
|
Bbld
|
Barrels per
day
|
|
|
|
|
|
|
|
|
|
$/Bbl
|
Dollars per
barrel
|
|
|
|
|
|
|
|
|
|
MMBtud
|
Million British
thermal units per day
|
|
|
|
|
|
|
|
|
|
$/MMBtu
|
Dollars per million
British thermal units
|
|
|
|
|
|
|
|
|
|
NYMEX
|
New York Mercantile
Exchange
|
|
|
|
|
|
|
|
|
|
EOG RESOURCES,
INC.
|
Direct After-Tax
Rate of Return (ATROR)
|
|
The calculation of
our direct after-tax rate of return (ATROR) with respect to our
capital expenditure program for a particular play or well is based
on the estimated proved reserves ("net" to EOG's interest) for all
wells in such play or such well (as the case may be), the estimated
net present value (NPV) of the future net cash flows from such
reserves (for which we utilize certain assumptions regarding future
commodity prices and operating costs) and our direct net costs
incurred in drilling or acquiring (as the case may be) such wells
or well (as the case may be). As such, our direct ATROR with
respect to our capital expenditures for a particular play or well
cannot be calculated from our consolidated financial
statements.
|
|
|
Direct
ATROR
|
Based on Cash Flow
and Time Value of Money
|
- Estimated
future commodity prices and operating costs
|
- Costs
incurred to drill, complete and equip a well, including
facilities
|
Excludes Indirect
Capital
|
- Gathering
and Processing and other Midstream
|
- Land,
Seismic, Geological and Geophysical
|
|
Payback ~12 Months on
100% Direct ATROR Wells
|
First Five Years ~1/2
Estimated Ultimate Recovery Produced but ~3/4 of NPV
Captured
|
|
|
Return on Equity /
Return on Capital Employed
|
Based on GAAP Accrual
Accounting
|
Includes All Indirect
Capital and Growth Capital for Infrastructure
|
- Eagle Ford,
Bakken, Permian Facilities
|
- Gathering
and Processing
|
Includes Legacy Gas
Capital and Capital from Mature Wells
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of After-Tax Net Interest Expense (Non-GAAP),
Adjusted Net Income (Loss)
|
(Non-GAAP), Net
Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the
Calculations of
|
Return on Capital
Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest
Expense (GAAP),
|
Net Income (Loss)
(GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization
(GAAP), Respectively
|
(Unaudited; in
millions, except ratio data)
|
|
|
|
|
|
|
|
|
|
|
|
|
The following chart
reconciles Net Interest Expense (GAAP), Net Income (Loss) (GAAP),
Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP)
to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income
(Loss) (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization
(Non-GAAP), respectively, as used in the Return on Capital Employed
(ROCE) and Return on Equity (ROE) calculations. EOG believes
this presentation may be useful to investors who follow the
practice of some industry analysts who utilize After-Tax Net
Interest Expense, Adjusted Net Income (Loss), Net Debt and Total
Capitalization (Non-GAAP) in their ROCE and ROE calculations.
EOG management uses this information for purposes of comparing its
financial performance with the financial performance of other
companies in the industry.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
2013
|
Return on Capital
Employed (ROCE) (Non-GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Interest Expense
(GAAP)
|
$
|
282
|
|
$
|
237
|
|
$
|
201
|
|
|
|
Tax Benefit Imputed
(based on 35%)
|
|
(99)
|
|
|
(83)
|
|
|
(70)
|
|
|
|
After-Tax Net
Interest Expense (Non-GAAP) - (a)
|
$
|
183
|
|
$
|
154
|
|
$
|
131
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
(GAAP) -
(b)
|
$
|
(1,097)
|
|
$
|
(4,525)
|
|
$
|
2,915
|
|
|
|
Adjustments to Net
Income (Loss), Net of Tax (See Accompanying Schedules)
|
204
|
(a)
|
|
4,559
|
(b)
|
|
(199)
|
(c)
|
|
|
Adjusted Net Income
(Loss) (Non-GAAP) - (c)
|
$
|
(893)
|
|
$
|
34
|
|
$
|
2,716
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Stockholders'
Equity - (d)
|
$
|
13,982
|
|
$
|
12,943
|
|
$
|
17,713
|
|
$
|
15,418
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Total
Stockholders' Equity * - (e)
|
$
|
13,463
|
|
$
|
15,328
|
|
$
|
16,566
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current and Long-Term
Debt (GAAP) - (f)
|
$
|
6,986
|
|
$
|
6,655
|
|
$
|
5,906
|
|
$
|
5,909
|
Less:
Cash
|
|
(1,600)
|
|
|
(719)
|
|
|
(2,087)
|
|
|
(1,318)
|
Net Debt (Non-GAAP) -
(g)
|
$
|
5,386
|
|
$
|
5,936
|
|
$
|
3,819
|
|
$
|
4,591
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
(GAAP) - (d) + (f)
|
$
|
20,968
|
|
$
|
19,598
|
|
$
|
23,619
|
|
$
|
21,327
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
(Non-GAAP) - (d) + (g)
|
$
|
19,368
|
|
$
|
18,879
|
|
$
|
21,532
|
|
$
|
20,009
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Total
Capitalization (Non-GAAP) * - (h)
|
$
|
19,124
|
|
$
|
20,206
|
|
$
|
20,771
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROCE (GAAP Net
Income) - [(a) + (b)] /
(h)
|
|
-4.8%
|
|
|
-21.6%
|
|
|
14.7%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROCE (Non-GAAP
Adjusted Net Income) - [(a) + (c)] /
(h)
|
|
-3.7%
|
|
|
0.9%
|
|
|
13.7%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Return on Equity
(ROE)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROE
(GAAP) (GAAP Net Income) - (b) / (e)
|
|
-8.1%
|
|
|
-29.5%
|
|
|
17.6%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROE (Non-GAAP)
(Non-GAAP Adjusted Net Income) - (c) / (e)
|
|
-6.6%
|
|
|
0.2%
|
|
|
16.4%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* Average for the
current and immediately preceding year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments to Net
Income (Loss) (GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) See below
schedule for detail of adjustments to Net Income (Loss) (GAAP) in
2016:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31, 2016
|
|
|
|
|
|
Before
|
|
|
Income
Tax
|
|
|
After
|
|
|
|
|
|
Tax
|
|
|
Impact
|
|
|
Tax
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
Add:
|
Mark-to-Market
Commodity Derivative Contracts Impact
|
$
|
77
|
|
$
|
(28)
|
|
$
|
49
|
|
|
|
Add:
|
Impairments of
Certain Assets
|
|
321
|
|
|
(113)
|
|
|
208
|
|
|
|
Less:
|
Net Gains on Asset
Dispositions
|
|
(206)
|
|
|
62
|
|
|
(144)
|
|
|
|
Add:
|
Trinidad Tax
Settlement
|
|
-
|
|
|
43
|
|
|
43
|
|
|
|
Add:
|
Voluntary Retirement
Expense
|
|
42
|
|
|
(15)
|
|
|
27
|
|
|
|
Add:
|
Acquisition - State
Apportionment Change
|
|
-
|
|
|
16
|
|
|
16
|
|
|
|
Add:
|
Acquisition
Costs
|
|
5
|
|
|
-
|
|
|
5
|
|
|
|
Total
|
$
|
239
|
|
$
|
(35)
|
|
$
|
204
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(b) See below
schedule for detail of adjustments to Net Income (Loss) (GAAP) in
2015:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31, 2015
|
|
|
|
|
|
Before
|
|
|
Income
Tax
|
|
|
After
|
|
|
|
|
|
Tax
|
|
|
Impact
|
|
|
Tax
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
Add:
|
Mark-to-Market
Commodity Derivative Contracts Impact
|
$
|
668
|
|
$
|
(238)
|
|
$
|
430
|
|
|
|
Add:
|
Impairments of
Certain Assets
|
|
6,308
|
|
|
(2,183)
|
|
|
4,125
|
|
|
|
Less:
|
Texas Margin Tax Rate
Reduction
|
|
-
|
|
|
(20)
|
|
|
(20)
|
|
|
|
Add:
|
Legal Settlement -
Early Leasehold Termination
|
|
19
|
|
|
(6)
|
|
|
13
|
|
|
|
Add:
|
Severance
Costs
|
|
9
|
|
|
(3)
|
|
|
6
|
|
|
|
Add:
|
Net Losses on Asset
Dispositions
|
|
9
|
|
|
(4)
|
|
|
5
|
|
|
|
Total
|
$
|
7,013
|
|
$
|
(2,454)
|
|
$
|
4,559
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(c) See below
schedule for detail of adjustments to Net Income (Loss) (GAAP) in
2014:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31, 2014
|
|
|
|
|
|
Before
|
|
|
Income
Tax
|
|
|
After
|
|
|
|
|
|
Tax
|
|
|
Impact
|
|
|
Tax
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
Less:
|
Mark-to-Market
Commodity Derivative Contracts Impact
|
$
|
(800)
|
|
$
|
285
|
|
$
|
(515)
|
|
|
|
Add:
|
Impairments of
Certain Assets
|
|
824
|
|
|
(271)
|
|
|
553
|
|
|
|
Less:
|
Net Gains on Asset
Dispositions
|
|
(508)
|
|
|
21
|
|
|
(487)
|
|
|
|
Add
|
Tax Expense Related
to the Repatriation of Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign Earnings in
Future Years
|
|
-
|
|
|
250
|
|
|
250
|
|
|
|
Total
|
$
|
(484)
|
|
$
|
285
|
|
$
|
(199)
|
|
|
|
EOG RESOURCES,
INC.
|
Second Quarter and
Full Year 2017 Forecast and Benchmark Commodity
Pricing
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Second Quarter and
Full Year 2017 Forecast
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The forecast items
for the second quarter and full year 2017 set forth below for EOG
Resources, Inc. (EOG) are based on current available information
and expectations as of the date of the accompanying press
release. EOG undertakes no obligation, other than as required
by applicable law, to update or revise this forecast, whether as a
result of new information, subsequent events, anticipated or
unanticipated circumstances or otherwise. This forecast,
which should be read in conjunction with the accompanying press
release and EOG's related Current Report on Form 8-K filing,
replaces and supersedes any previously issued guidance or
forecast.
|
|
|
|
|
|
|
|
|
|
|
|
|
(b) Benchmark
Commodity Pricing
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EOG bases United
States and Trinidad crude oil and condensate price differentials
upon the West Texas Intermediate crude oil price at Cushing,
Oklahoma, using the simple average of the NYMEX settlement prices
for each trading day within the applicable calendar
month.
|
|
|
|
|
|
|
|
|
|
|
|
|
EOG bases United
States natural gas price differentials upon the natural gas price
at Henry Hub, Louisiana, using the simple average of the NYMEX
settlement prices for the last three trading days of the applicable
month.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
Ranges
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
|
2Q 2017
|
|
|
Full Year
2017
|
Daily Sales
Volumes
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil and Condensate
Volumes (MBbld)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
322.0
|
-
|
|
332.0
|
|
|
320.0
|
-
|
|
335.0
|
Trinidad
|
|
0.2
|
-
|
|
0.4
|
|
|
0.3
|
-
|
|
0.5
|
Other International
|
|
0.0
|
-
|
|
0.0
|
|
|
4.0
|
-
|
|
7.0
|
Total
|
|
322.2
|
-
|
|
332.4
|
|
|
324.3
|
-
|
|
342.5
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids Volumes
(MBbld)
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
72.0
|
-
|
|
78.0
|
|
|
72.0
|
-
|
|
82.0
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Volumes
(MMcfd)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
710
|
-
|
|
750
|
|
|
725
|
-
|
|
760
|
Trinidad
|
|
280
|
-
|
|
320
|
|
|
275
|
-
|
|
315
|
Other International
|
|
18
|
-
|
|
24
|
|
|
25
|
-
|
|
30
|
Total
|
|
1,008
|
-
|
|
1,094
|
|
|
1,025
|
-
|
|
1,105
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Equivalent Volumes
(MBoed)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
512.3
|
-
|
|
535.0
|
|
|
512.8
|
-
|
|
543.7
|
Trinidad
|
|
46.9
|
-
|
|
53.7
|
|
|
46.1
|
-
|
|
53.0
|
Other International
|
|
3.0
|
-
|
|
4.0
|
|
|
8.2
|
-
|
|
12.0
|
Total
|
|
562.2
|
-
|
|
592.7
|
|
|
567.1
|
-
|
|
608.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
Ranges
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
2Q 2017
|
|
|
Full Year
2017
|
Operating
Costs
|
|
|
|
|
|
|
|
|
|
|
|
Unit Costs
($/Boe)
|
|
|
|
|
|
|
|
|
|
|
|
Lease and Well
|
$
|
4.60
|
-
|
$
|
5.00
|
|
$
|
4.25
|
-
|
$
|
4.95
|
Transportation Costs
|
$
|
3.20
|
-
|
$
|
3.60
|
|
$
|
3.10
|
-
|
$
|
3.70
|
Depreciation, Depletion and Amortization
|
$
|
15.70
|
-
|
$
|
16.10
|
|
$
|
15.50
|
-
|
$
|
16.00
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses
($MM)
|
|
|
|
|
|
|
|
|
|
|
|
Exploration, Dry Hole and
Impairment
|
$
|
95
|
-
|
$
|
125
|
|
$
|
415
|
-
|
$
|
465
|
General and
Administrative
|
$
|
85
|
-
|
$
|
95
|
|
$
|
365
|
-
|
$
|
395
|
Gathering and
Processing
|
$
|
28
|
-
|
$
|
30
|
|
$
|
125
|
-
|
$
|
145
|
Capitalized
Interest
|
$
|
6
|
-
|
$
|
8
|
|
$
|
25
|
-
|
$
|
30
|
Net Interest
|
$
|
69
|
-
|
$
|
72
|
|
$
|
273
|
-
|
$
|
283
|
|
|
|
|
|
|
|
|
|
|
|
|
Taxes Other Than
Income (% of Wellhead Revenue)
|
|
6.9%
|
-
|
|
7.3%
|
|
|
6.5%
|
-
|
|
6.9%
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Taxes
|
|
|
|
|
|
|
|
|
|
|
|
Effective
Rate
|
|
32%
|
-
|
|
37%
|
|
|
31%
|
-
|
|
36%
|
Current Taxes
($MM)
|
$
|
50
|
-
|
$
|
85
|
|
$
|
135
|
-
|
$
|
175
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures
(Excluding Acquisitions, $MM)
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and Development,
Excluding Facilities
|
|
|
|
|
|
|
$
|
3,000
|
-
|
$
|
3,350
|
Exploration and Development
Facilities
|
|
|
|
|
|
|
$
|
475
|
-
|
$
|
510
|
Gathering, Processing and
Other
|
|
|
|
|
|
|
$
|
225
|
-
|
$
|
240
|
|
|
|
|
|
|
|
|
|
|
|
|
Pricing - (Refer
toBenchmark Commodity Pricingin text)
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil and Condensate
($/Bbl)
|
|
|
|
|
|
|
|
|
|
|
|
Differentials
|
|
|
|
|
|
|
|
|
|
|
|
United States - above (below) WTI
|
$
|
(2.00)
|
-
|
$
|
0.00
|
|
$
|
(2.50)
|
-
|
$
|
(0.50)
|
Trinidad - above (below) WTI
|
$
|
(11.00)
|
-
|
$
|
(9.00)
|
|
$
|
(11.00)
|
-
|
$
|
(9.00)
|
Other International - above (below) WTI
|
$
|
(4.00)
|
-
|
$
|
2.00
|
|
$
|
(7.00)
|
-
|
$
|
1.00
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
Liquids
|
|
|
|
|
|
|
|
|
|
|
|
Realizations as % of WTI
|
|
36%
|
-
|
|
44%
|
|
|
36%
|
-
|
|
44%
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
($/Mcf)
|
|
|
|
|
|
|
|
|
|
|
|
Differentials
|
|
|
|
|
|
|
|
|
|
|
|
United States - above (below) NYMEX Henry Hub
|
$
|
(1.10)
|
-
|
$
|
(0.60)
|
|
$
|
(1.15)
|
-
|
$
|
(0.65)
|
|
|
|
|
|
|
|
|
|
|
|
|
Realizations
|
|
|
|
|
|
|
|
|
|
|
|
Trinidad
|
$
|
2.20
|
-
|
$
|
2.60
|
|
$
|
2.10
|
-
|
$
|
2.70
|
Other International
|
$
|
3.30
|
-
|
$
|
3.80
|
|
$
|
3.30
|
-
|
$
|
4.30
|
|
|
|
|
|
|
|
|
|
|
|
|
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-first-quarter-2017-results-and-converts-14-bnboe-net-resource-potential-to-premium-300453502.html
SOURCE EOG Resources, Inc.