EOG
$101.66
Eog Resources
$.22
.22%
Earnings Details
3rd Quarter September 2017
Thursday, November 2, 2017 4:17:00 PM
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Summary

Eog Resources Beats

Eog Resources (EOG) reported 3rd Quarter September 2017 earnings of $0.19 per share on revenue of $2.6 billion. The consensus earnings estimate was $0.10 per share on revenue of $2.6 billion. The Earnings Whisper number was $0.13 per share. Revenue grew 24.8% on a year-over-year basis.

EOG Resources Inc explores for, develops, produces and markets crude oil and natural gas in the USA, Trinidad, United Kingdom, China, Argentina and, from time to time, select other international areas.

Results
Reported Earnings
$0.19
Earnings Whisper
$0.13
Consensus Estimate
$0.10
Reported Revenue
$2.64 Bil
Revenue Estimate
$2.57 Bil
Growth
Earnings Growth
Revenue Growth
Power Rating
Grade
Earnings Release

EOG Resources Announces Third Quarter 2017 Results; Announces Two New Premium Oil Plays Adding 800 Net Premium Well Locations and 750 MMBoe Estimated Net Resource Potential

Introduces 50,000 Net Acre Woodford Oil Window Play with 210 MMBoe Estimated Net Resource Potential and 260 Net Premium Well Locations

Adds First Bone Spring Play in Delaware Basin with 540 MMBoe Estimated Net Resource Potential and 540 Remaining Net Premium Well Locations

-- Exceeds Revised Post-Harvey Crude Oil, NGL and Natural Gas Production Targets

Delivers Per-Unit Lease and Well, Transportation and DD&A Expense Rates Below Targets

Expects to Grow 2017 U.S. Oil Production 20 Percent Within Discretionary Cash Flow Including Dividends

EOG Resources, Inc. (EOG) (EOG) today reported third quarter 2017 net income of $100.5 million, or $0.17 per share. This compares to a third quarter 2016 net loss of $190.0 million, or $0.35 per share.

Adjusted non-GAAP net income for the third quarter 2017 was $111.3 million, or $0.19 per share, compared to an adjusted non-GAAP net loss of $220.8 million, or $0.40 per share, for the same prior year period. Adjusted non-GAAP net income (loss) is calculated by matching commodity derivative contract realizations to settlement months and making certain other adjustments in order to exclude non-recurring items. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.)

Increased crude oil volumes, higher crude oil, natural gas liquids (NGLs) and natural gas prices and lower transportation expense resulted in increases to discretionary cash flow and EBITDAX during the third quarter 2017 compared to the third quarter 2016. In addition to the items listed above, lower impairment and depreciation, depletion and amortization expenses resulted in increased adjusted non-GAAP net income during the quarter. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.)

Operational Highlights In the third quarter 2017, EOG expanded its premium inventory to approximately 8,000 net drilling locations from 7,200. As a result, EOG’s total premium net resource potential increased 12 percent to 7.3 billion barrels of oil equivalent. The additional net premium locations include 540 in the Delaware Basin First Bone Spring and 260 in the Woodford Oil Window. Premium inventory is defined by well locations that generate a minimum 30 percent direct after-tax rate of return assuming a $40 crude oil price.

EOG grew third quarter total crude oil volumes 16 percent to 327,900 barrels of oil per day (Bopd). Production curtailments and completion delays due to Hurricane Harvey reduced crude oil volumes approximately 15,000 Bopd during the quarter. Natural gas and NGL production exceeded target midpoints, contributing to 8 percent total company production growth compared to the third quarter 2016.

During the third quarter 2017, lease and well expenses on a per-unit basis increased 4 percent compared to the same prior-year period, primarily because of higher per-unit operating costs from properties acquired in the Yates transaction and increased operating and maintenance expenses in the United Kingdom. Per-unit transportation costs decreased 15 percent year-over-year, due to the expiration of legacy transportation agreements and increased infrastructure to handle higher production volumes. Per-unit depreciation, depletion and amortization expenses decreased 13 percent compared to the same prior-year period due to the addition of reserves from premium wells with lower finding and development costs.

EOG now expects to complete approximately 505 net wells in 2017, an increase from its original outlook of 480 net wells. The company achieved lower completed well costs across its operations in 2017, as continued efficiencies and legacy service contract expirations offset service price increases. EOG is targeting 20 percent U.S. crude oil growth and expects to fund capital expenditures and the dividend using discretionary cash flow.

"Since the start of the year, EOG has added 2,000 net premium locations to its inventory. This is four times the number of wells we expect to complete for all of 2017," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "EOG is an organic, exploration-driven machine. We have amassed an enormous, high-quality portfolio of assets by capturing sweet-spot acreage in the best oil plays in the U.S. Combined with our consistent operational proficiency and innovative technology, this gives us great confidence in the long-term sustainability of our unique premium growth and high-return model."

Woodford Oil Window EOG added to its growing roster of premium plays with the introduction of a 50,000 net acre position in the Woodford oil window of the Eastern Anadarko Basin. Located primarily in McClain County, Oklahoma, EOG is targeting the black-oil window of the Woodford formation. The contiguous acreage position was amassed through an organic leasing program conducted over the past four years at an average cost of $750 per acre. EOG has completed three horizontal exploration wells in the play since June 2016. The most recent well, the Curry 21X #1VH, was brought to sales in the third quarter with a treated lateral length of 10,500 feet and 30-day initial production rate of 1,730 barrels of oil equivalent per day (Boed), or 1,460 Bopd, 165 barrels per day (Bpd) of NGLs and 0.6 million cubic feet per day (MMcfd) of natural gas. Completed well costs are targeted at $7.8 million for a 9,500 foot lateral. Benefiting from a shallow initial decline rate, EOG estimates reserves per well are 800 thousand barrels of oil equivalent (MBoe), net after royalty, with a 70 percent oil mix. The company has identified 260 net drilling locations with estimated net resource potential of 210 million barrels of oil equivalent (MMBoe). EOG estimates all 260 of these locations are premium, and plans to ramp activity in the play in 2018.

Delaware Basin EOG added to its inventory of prolific plays in the Delaware Basin with the introduction of the First Bone Spring. Approximately 100,000 net acres in EOG’s Northern Delaware Basin footprint are prospective for this high rate-of-return oil play. The company identified an initial 555 net locations, with estimated net resource potential of 540 MMBoe. EOG completed 15 net First Bone Spring wells in the past three years, with strong results and premium returns across a large portion of its acreage position. All 540 net remaining drilling locations have premium rate of return potential. Reserves per well are estimated to be 975 MBoe, net after royalty, with a 55 percent oil mix. Targeted well cost is $7.3 million for a 7,000 foot lateral well.

EOG continues to deepen its technical knowledge of the Delaware Basin. Drilling during the third quarter was aimed at further understanding development criteria for the large stacked-pay resource in the basin. EOG conducted a number of spacing tests to optimize development, and continued to test additional zones for future premium potential. EOG now expects to complete an additional 15 net wells in the Delaware Basin during 2017 for a total of 155 net wells, including 10 net wells in the First Bone Spring.

EOG completed 22 gross (20 net) wells in the Delaware Basin Wolfcamp in the third quarter with an average treated lateral length of 6,500 feet per well and average 30-day initial production rates per well of 2,470 Boed, or 1,620 Bopd, 380 Bpd of NGLs and 2.8 MMcfd of natural gas. In Lea County, NM, EOG completed a three-well pattern, the Antietam 9 Fed Com 701-703H, with an average treated lateral length of 7,000 feet per well and average 30-day initial production rates per well of 4,145 Boed, or 2,725 Bopd, 640 Bpd of NGLs and 4.7 MMcfd of natural gas.

In the Delaware Basin Bone Spring plays, EOG completed nine gross (six net) wells in the third quarter with an average treated lateral length of 6,800 feet per well and average 30-day initial production rates per well of 1,125 Boed, or 840 Bopd, 125 Bpd of NGLs and 0.9 MMcfd of natural gas. In Lea County, NM, EOG completed the Righteous 6 State Com 601Y, with a treated lateral length of 7,100 feet and a 30-day initial production rate of 2,160 Boed, or 1,740 Bopd, 190 Bpd of NGLs and 1.4 MMcfd of natural gas.

In the Delaware Basin Leonard, EOG completed nine gross (nine net) wells in the third quarter with an average treated lateral length of 4,800 feet per well and average 30-day initial production rates per well of 1,725 Boed, or 800 Bopd, 415 Bpd of NGLs and 3.0 MMcfd of natural gas.

Bakken and Rockies EOG completed 20 gross (19 net) wells in the Powder River Basin Turner during the third quarter, with an average treated lateral length of 7,600 feet per well and average 30-day initial production rates per well of 1,630 Boed, or 1,040 Bopd, 185 Bpd of NGLs and 2.4 MMcfd of natural gas. Encouraging tests of new targets and ongoing delineation of its 400,000 net acre position have prompted EOG to increase its activity, with five additional wells planned during 2017 for a total of 35 net wells. The combination of low completed well costs, robust well productivity and moderate initial decline rates make the Powder River Basin competitive with the best performing assets at EOG.

In the DJ Basin, EOG completed seven gross (two net) wells targeting the Codell formation in the third quarter with an average treated lateral length of 9,400 feet per well and average 30-day initial production rates per well of 790 Boed, or 665 Bopd, 75 Bpd of NGLs and 0.3 MMcfd of natural gas.

EOG completed its planned 35 net well program in the North Dakota Bakken in the first half of 2017, and limited drilling activity is scheduled for the remainder of 2017.

South Texas Eagle Ford EOG’s South Texas Eagle Ford remained resilient during the third quarter, as robust infrastructure and comprehensive technology and communication assets enabled EOG to manage operations in a safe and efficient manner during Hurricane Harvey. Ongoing efficiency improvements have enabled EOG to add five net wells to its planned 2017 completions, for a total of 200 net wells.

In the third quarter, EOG completed 44 gross (39 net) 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 1,685 Boed, or 1,340 Bopd, 175 Bpd of NGLs and 1.0 MMcfd of natural gas. In Gonzales County, EOG completed a four-well pattern, the Angus Unit 6H-9H, with an average treated lateral length of 5,700 feet per well and average 30-day initial production rates per well of 3,945 Boed, or 2,995 Bopd, 480 Bpd of NGLs and 2.8 MMcfd of natural gas.

South Texas Austin Chalk In the third quarter, EOG continued to delineate the South Texas Austin Chalk. EOG completed eight gross (eight net) wells in Karnes County with an average treated lateral length of 6,000 feet per well and average 30-day initial production rates per well of 4,440 Boed, or 3,195 Bopd, 630 Bpd of NGLs and 3.7 MMcfd of natural gas. Notably, EOG completed the Elbrus Unit 103H with a lateral length of 3,700 feet and 30-day initial production rate of 7,760 Boed, or 5,425 Bopd, 1,185 Bpd of NGLs and 6.9 MMcfd of natural gas.

Hedging Activity During the third quarter ended September 30, 2017, EOG did not enter into any additional crude oil or natural gas derivative contracts.

A comprehensive summary of EOG’s crude oil and natural gas derivative contracts is provided in the attached tables.

Capital Structure and Asset Sales At September 30, 2017, EOG’s total debt outstanding was $6.4 billion for a debt-to-total capitalization ratio of 31 percent. Considering cash on the balance sheet at the end of the third quarter, EOG’s net debt was $5.5 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 in the first nine months of 2017 totaled $192 million.

Conference Call November 3, 2017 EOG’s third quarter 2017 results conference call will be available via live audio webcast at 9 a.m. Central time (10 a.m. Eastern time) on Friday, November 3, 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 for one year.

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 and costs, statements regarding future commodity prices and statements regarding the plans and objectives of EOG’s management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG’s future operating results and returns or EOG’s ability to replace or increase reserves, increase production, reduce or otherwise control operating and capital costs, generate income or cash flows or pay dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG’s forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG’s control. Important factors that could cause EOG’s actual results to differ materially from the expectations reflected in EOG’s forward-looking statements include, among others:

the timing, extent and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities;

the extent to which EOG is successful in its efforts to acquire or discover additional reserves;

the extent to which EOG is successful in its efforts to economically develop its acreage in, produce reserves and achieve anticipated production levels from, and maximize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects;

the extent to which EOG is successful in its efforts to market its crude oil and condensate, natural gas liquids, natural gas and related commodity production;

the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, transportation and refining facilities;

the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights-of-way, and EOG’s ability to retain mineral licenses and leases;

the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations; environmental, health and safety laws and regulations relating to air emissions, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;

EOG’s ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties;

the extent to which EOG’s third-party-operated crude oil and natural gas properties are operated successfully and economically;

competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties, employees and other personnel, facilities, equipment, materials and services;

the availability and cost of employees and other personnel, facilities, equipment, materials (such as water) and services;

the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;

weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression and transportation facilities;

the ability of EOG’s customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;

EOG’s ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;

-- the extent 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
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
Nine Months Ended
September 30,
September 30,
2017
2016
2017
2016
Net Operating Revenues and Other
$
2,644.8
$
2,118.5
$
7,867.9
$
5,248.6
Net Income (Loss)
$
100.5
$
(190.0)
$
152.1
$
(954.3)
Net Income (Loss) Per Share
Basic
$
0.17
$
(0.35)
$
0.26
$
(1.74)
Diluted
$
0.17
$
(0.35)
$
0.26
$
(1.74)
Average Number of Common Shares
Basic
574.8
547.8
574.4
547.3
Diluted
578.7
547.8
578.5
547.3
Summary Income Statements
(Unaudited; in thousands, except per share data)
Three Months Ended
Nine Months Ended
September 30,
September 30,
2017
2016
2017
2016
Net Operating Revenues and Other
Crude Oil and Condensate
$
1,451,410
$
1,137,717
$
4,326,925
$
2,951,118
Natural Gas Liquids
180,038
112,439
480,389
299,401
Natural Gas
220,402
205,293
675,012
526,779
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts
(6,606)
5,117
64,860
(33,821)
Gathering, Processing and Marketing
784,368
532,456
2,289,702
1,351,665
Gains (Losses) on Asset Dispositions, Net
(8,202)
108,204
(33,876)
101,801
Other, Net
23,434
17,278
64,869
51,650
Total
2,644,844
2,118,504
7,867,881
5,248,593
Operating Expenses
Lease and Well
251,943
226,348
762,906
685,606
Transportation Costs
183,565
200,862
548,635
570,787
Gathering and Processing Costs
32,590
32,635
105,480
90,385
Exploration Costs
30,796
25,455
122,401
85,843
Dry Hole Costs
50
10,390
77
10,464
Impairments
53,677
177,990
325,798
322,321
Marketing Costs
793,536
552,487
2,320,671
1,373,387
Depreciation, Depletion and Amortization
846,222
899,511
2,527,642
2,690,893
General and Administrative
111,717
94,397
317,462
292,633
Taxes Other Than Income
125,912
91,909
386,319
246,068
Total
2,430,008
2,311,984
7,417,391
6,368,387
Operating Income (Loss)
214,836
(193,480)
450,490
(1,119,794)
Other Income (Expense), Net
226
(7,912)
8,349
(33,345)
Income (Loss) Before Interest Expense and Income Taxes
215,062
(201,392)
458,839
(1,153,139)
Interest Expense, Net
69,082
70,858
211,010
210,356
Income (Loss) Before Income Taxes
145,980
(272,250)
247,829
(1,363,495)
Income Tax Provision (Benefit)
45,439
(82,250)
95,718
(409,161)
Net Income (Loss)
$
100,541
$
(190,000)
$
152,111
$
(954,334)
Dividends Declared per Common Share
$
0.1675
$
0.1675
$
0.5025
$
0.5025
EOG RESOURCES, INC.
Operating Highlights
(Unaudited)
Three Months Ended
Nine Months Ended
September 30,
September 30,
2017
2016
2017
2016
Wellhead Volumes and Prices
Crude Oil and Condensate Volumes (MBbld) (A)
United States
327.1
275.7
324.3
269.0
Trinidad
0.8
0.7
0.8
0.8
Other International (B)
-
6.2
1.0
3.0
Total
327.9
282.6
326.1
272.8
Average Crude Oil and Condensate Prices ($/Bbl) (C)
United States
$
48.06
$
43.66
$
48.61
$
39.53
Trinidad
39.42
34.81
40.24
31.36
Other International (B)
-
43.53
51.55
35.30
Composite
48.11
43.63
48.60
39.46
Natural Gas Liquids Volumes (MBbld) (A)
United States
87.4
81.9
84.3
81.9
Other International (B)
-
-
-
-
Total
87.4
81.9
84.3
81.9
Average Natural Gas Liquids Prices ($/Bbl) (C)
United States
$
22.38
$
14.92
$
20.87
$
13.34
Other International (B)
-
-
-
-
Composite
22.38
14.92
20.87
13.34
Natural Gas Volumes (MMcfd) (A)
United States
748
791
744
813
Trinidad
323
329
317
346
Other International (B)
25
24
22
25
Total
1,096
1,144
1,083
1,184
Average Natural Gas Prices ($/Mcf) (C)
United States
$
2.20
$
1.94
$
2.22
$
1.46
Trinidad
2.04
1.86
2.33
1.88
Other International (B)
3.74
3.74
3.72
3.57
Composite
2.19
1.95
2.28
1.62
Crude Oil Equivalent Volumes (MBoed) (D)
United States
539.2
489.4
532.6
486.4
Trinidad
54.6
55.6
53.6
58.5
Other International (B)
4.3
10.2
4.8
7.2
Total
598.1
555.2
591.0
552.1
Total MMBoe (D)
55.0
51.1
161.3
151.3
(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)
September 30,
December 31,
2017
2016
ASSETS
Current Assets
Cash and Cash Equivalents
$
846,138
$
1,599,895
Accounts Receivable, Net
1,243,535
1,216,320
Inventories
344,016
350,017
Assets from Price Risk Management Activities
3,297
-
Income Taxes Receivable
126,881
12,305
Other
200,096
206,679
Total
2,763,963
3,385,216
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)
51,716,999
49,592,091
Other Property, Plant and Equipment
3,934,137
4,008,564
Total Property, Plant and Equipment
55,651,136
53,600,655
Less:
Accumulated Depreciation, Depletion and Amortization
(29,926,547)
(27,893,577)
Total Property, Plant and Equipment, Net
25,724,589
25,707,078
Deferred Income Taxes
17,406
16,140
Other Assets
299,347
190,767
Total Assets
$
28,805,305
$
29,299,201
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable
$
1,635,711
$
1,511,826
Accrued Taxes Payable
180,277
118,411
Dividends Payable
96,349
96,120
Liabilities from Price Risk Management Activities
2,827
61,817
Current Portion of Long-Term Debt
6,579
6,579
Other
258,281
232,538
Total
2,180,024
2,027,291
Long-Term Debt
6,380,427
6,979,779
Other Liabilities
1,215,113
1,282,142
Deferred Income Taxes
5,107,477
5,028,408
Commitments and Contingencies
Stockholders’ Equity
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized at September 30,
2017, 640,000,000 Shares Authorized at December 31, 2016, 578,570,621 Shares Issued at September 30, 2017 and 576,950,272 Shares Issued at December 31, 2016
205,786
205,770
Additional Paid in Capital
5,513,631
5,420,385
Accumulated Other Comprehensive Loss
(17,160)
(19,010)
Retained Earnings
8,259,971
8,398,118
Common Stock Held in Treasury, 429,424 Shares at September 30, 2017 and 250,155 Shares at December 31, 2016
(39,964)
(23,682)
Total Stockholders’ Equity
13,922,264
13,981,581
Total Liabilities and Stockholders’ Equity
$
28,805,305
$
29,299,201
EOG RESOURCES, INC.
Summary Statements of Cash Flows
(Unaudited; in thousands)
Nine Months Ended
September 30,
2017
2016
Cash Flows from Operating Activities
Reconciliation of Net Income (Loss) to Net Cash Provided by Operating Activities:
Net Income (Loss)
$
152,111
$
(954,334)
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization
2,527,642
2,690,893
Impairments
325,798
322,321
Stock-Based Compensation Expenses
101,537
97,072
Deferred Income Taxes
114,850
(492,489)
(Gains) Losses on Asset Dispositions, Net
33,876
(101,801)
Other, Net
(4,514)
42,149
Dry Hole Costs
77
10,464
Mark-to-Market Commodity Derivative Contracts
Total (Gains) Losses
(64,860)
33,821
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts
4,730
(22,219)
Excess Tax Benefits from Stock-Based Compensation
-
(22,071)
Other, Net
270
7,513
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable
(25,445)
(11,860)
Inventories
(17,674)
137,563
Accounts Payable
112,894
(201,213)
Accrued Taxes Payable
(49,967)
113,996
Other Assets
(83,940)
(12,526)
Other Liabilities
(69,224)
36,799
Changes in Components of Working Capital Associated with Investing and Financing Activities
(120,373)
(119,760)
Net Cash Provided by Operating Activities
2,937,788
1,554,318
Investing Cash Flows
Additions to Oil and Gas Properties
(2,927,988)
(1,781,547)
Additions to Other Property, Plant and Equipment
(139,558)
(60,343)
Proceeds from Sales of Assets
191,593
457,665
Changes in Components of Working Capital Associated with Investing Activities
120,469
120,614
Net Cash Used in Investing Activities
(2,755,484)
(1,263,611)
Financing Cash Flows
Net Commercial Paper Repayments
-
(259,718)
Long-Term Debt Borrowings
-
991,097
Long-Term Debt Repayments
(600,000)
(400,000)
Dividends Paid
(289,261)
(276,726)
Excess Tax Benefits from Stock-Based Compensation
-
22,071
Treasury Stock Purchased
(50,374)
(55,641)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan
11,174
14,283
Debt Issuance Costs
-
(1,602)
Repayment of Capital Lease Obligation
(4,897)
(4,746)
Other, Net
(96)
(854)
Net Cash (Used in) Provided by Financing Activities
(933,454)
28,164
Effect of Exchange Rate Changes on Cash
(2,607)
11,350
Increase (Decrease) in Cash and Cash Equivalents
(753,757)
330,221
Cash and Cash Equivalents at Beginning of Period
1,599,895
718,506
Cash and Cash Equivalents at End of Period
$
846,138
$
1,048,727
EOG RESOURCES, INC.
Quantitative Reconciliation of Adjusted Net Income (Loss) (Non-GAAP)
To Net Income (Loss) (GAAP)
(Unaudited; in thousands, except per share data)
The following chart adjusts the three-month and nine-month periods ended September 30, 2017 and 2016 reported Net Income (Loss) (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net (gains) losses on asset dispositions in 2017 and 2016, to add back impairment charges related to certain of EOG’s assets in 2017 and 2016, to eliminate the impact of the Trinidad tax settlement in 2016, to add back certain voluntary retirement expense in 2016, to add back acquisition costs related to the Yates Transaction in 2016, to add back an early lease termination payment as the result of a legal settlement in 2017 and to add back the transaction costs for the formation of a joint venture in 2017.
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
September 30, 2017
September 30, 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)
$145,980
$
(45,439)
$100,541
$
0.17
$
(272,250)
$
82,250
$(190,000)
$
(0.35)
Adjustments:
(Gains) Losses on Mark-to-Market Commodity Derivative Contracts
6,606
(2,368)
4,238
0.01
(5,117)
1,824
(3,293)
(0.01)
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts 2,139
(767)
1,372
-
(25,071)
8,938
(16,133)
(0.03)
Add:
Net (Gains) Losses on Asset Dispositions
8,202
(3,068)
5,134
0.01
(108,204)
28,802
(79,402)
(0.13)
Add:
Impairments
-
-
-
-
102,778
(36,640)
66,138
0.12
Add:
Acquisition Costs
-
-
-
-
2,927
(1,043)
1,884
-
Adjustments to Net Income (Loss)
16,947
(6,203)
10,744
0.02
(32,687)
1,881
(30,806)
(0.05)
Adjusted Net Income (Loss) (Non-GAAP)
$162,927
$
(51,642)
$111,285
$
0.19
$
(304,937)
$
84,131
$(220,806)
$
(0.40)
Average Number of Common Shares (GAAP)
Basic
574,783
547,838
Diluted
578,736
547,838
Average Number of Common Shares (Non-GAAP)
Basic
574,783
547,838
Diluted
578,736
547,838
Nine Months Ended
Nine Months Ended
September 30, 2017
September 30, 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)
$247,829
$
(95,718)
$152,111
$
0.26
$(1,363,495)
$409,161
$(954,334)
$
(1.74)
Adjustments:
(Gains) Losses on Mark-to-Market Commodity Derivative Contracts
(64,860)
23,249
(41,611)
(0.07)
33,821
(12,057)
21,764
0.04
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts 4,730
(1,695)
3,035
0.01
(22,219)
7,921
(14,298)
(0.03)
Add:
Net (Gains) Losses on Asset Dispositions
33,876
(11,955)
21,921
0.04
(101,801)
24,635
(77,166)
(0.14)
Add:
Impairments
161,148
(57,764)
103,384
0.18
102,778
(36,640)
66,138
0.12
Add:
Trinidad Tax Settlement
-
-
-
-
-
43,000
43,000
0.08
Add:
Voluntary Retirement Expense
-
-
-
-
42,054
(14,992)
27,062
0.05
Add:
Acquisition Costs
-
-
-
-
2,927
(1,043)
1,884
-
Add:
Legal Settlement - Early Lease Termination
10,202
(3,657)
6,545
0.01
-
-
-
-
Add:
Joint Venture Transaction Costs
3,056
(1,095)
1,961
-
-
-
-
-
Adjustments to Net Income (Loss)
148,152
(52,917)
95,235
0.17
57,560
10,824
68,384
0.12
Adjusted Net Income (Loss) (Non-GAAP)
$395,981
$(148,635)
$247,346
$
0.43
$(1,305,935)
$419,985
$(885,950)
$
(1.62)
Average Number of Common Shares (GAAP)
Basic
574,370
547,295
Diluted
578,453
547,295
Average Number of Common Shares (Non-GAAP)
Basic
574,370
547,295
Diluted
578,453
547,295
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, 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
Nine Months Ended
September 30,
September 30,
2017
2016
2017
2016
Net Cash Provided by Operating Activities (GAAP)
$
961,363
$
759,581
$
2,937,788
$
1,554,318
Adjustments:
Exploration Costs (excluding Stock-Based Compensation Expenses)
26,132
21,384
106,268
70,268
Excess Tax Benefits from Stock-Based Compensation
-
10,260
-
22,071
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable
129,231
(10,712)
25,445
11,860
Inventories
11,545
(41,750)
17,674
(137,563)
Accounts Payable
(36,190)
(2,145)
(112,894)
201,213
Accrued Taxes Payable
10,843
(20,676)
49,967
(113,996)
Other Assets
22,851
(21,063)
83,940
12,526
Other Liabilities
2,355
(35,234)
69,224
(36,799)
Changes in Components of Working Capital Associated with Investing and Financing Activities
41,235
65,307
120,373
119,760
Discretionary Cash Flow (Non-GAAP)
$
1,169,365
$
724,952
$
3,297,785
$
1,703,658
Discretionary Cash Flow (Non-GAAP) - Percentage Increase
61%
94%
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 and nine-month periods ended September 30, 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 (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the net (gains) losses on asset dispositions (Net).
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
Nine Months Ended
September 30,
September 30,
2017
2016
2017
2016
Net Income (Loss) (GAAP)
$
100,541
$
(190,000)
$
152,111
$
(954,334)
Adjustments:
Interest Expense, Net
69,082
70,858
211,010
210,356
Income Tax Provision (Benefit)
45,439
(82,250)
95,718
(409,161)
Depreciation, Depletion and Amortization
846,222
899,511
2,527,642
2,690,893
Exploration Costs
30,796
25,455
122,401
85,843
Dry Hole Costs
50
10,390
77
10,464
Impairments
53,677
177,990
325,798
322,321
EBITDAX (Non-GAAP)
1,145,807
911,954
3,434,757
1,956,382
Total (Gains) Losses on MTM Commodity Derivative Contracts
6,606
(5,117)
(64,860)
33,821
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts
2,139
(25,071)
4,730
(22,219)
(Gains) Losses on Asset Dispositions, Net
8,202
(108,204)
33,876
(101,801)
Adjusted EBITDAX (Non-GAAP)
$
1,162,754
$
773,562
$
3,408,503
$
1,866,183
Adjusted EBITDAX (Non-GAAP) - Percentage Increase
50%
83%
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,
2017
2016
Total Stockholders’ Equity - (a)
$
13,922
$
13,982
Current and Long-Term Debt (GAAP) - (b)
6,387
6,986
Less: Cash
(846)
(1,600)
Net Debt (Non-GAAP) - (c)
5,541
5,386
Total Capitalization (GAAP) - (a) + (b)
$
20,309
$
20,968
Total Capitalization (Non-GAAP) - (a) + (c)
$
19,463
$
19,368
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]
31%
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.
Prices received by EOG for its crude oil production generally vary from NYMEX West Texas Intermediate prices due to adjustments for delivery location (basis) and other factors.
EOG entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma.
Presented below is a comprehensive summary of EOG’s crude oil basis swap contracts through November 2, 2017.
The weighted average price differential expressed in $/Bbl represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts.
Crude Oil Basis Swap Contracts
Weighted
Average Price
Volume
Differential
(Bbld)
($/Bbl)
2018
January 1, 2018 through December 31, 2018
15,000
$
1.063
2019
January 1, 2019 through December 31, 2019
20,000
$
1.075
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, which are included in the below table.
Presented below is a comprehensive summary of EOG’s crude oil price swap contracts through November 2, 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 received for settling these contracts was $0.7 million.
The offsetting contracts are excluded from the above table.
Presented below is a comprehensive summary of EOG’s natural gas price swap contracts through November 2, 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 November 30, 2017 (closed)
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 November 2, 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 November 30, 2017 (closed)
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 November 2, 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 November 30, 2017 (closed)
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
U.S. New York Mercantile Exchange
EOG RESOURCES, INC.
Direct After-Tax Rate of Return (ATROR)
The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated recoverable reserves ("net" to EOG’s interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be).
As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements.
Direct ATROR
Based on Cash Flow and Time Value of Money
- Estimated future commodity prices and operating costs
- Costs incurred to drill, complete and equip a well, including facilities
Excludes Indirect Capital
- Gathering and Processing and other Midstream
- Land, Seismic, Geological and Geophysical
Payback
12 Months on 100% Direct ATROR Wells
First Five Years
1/2 Estimated Ultimate Recovery Produced but
3/4 of NPV Captured
Return on Equity / Return on Capital Employed
Based on GAAP Accrual Accounting
Includes All Indirect Capital and Growth Capital for Infrastructure
- Eagle Ford, Bakken, Permian Facilities
- Gathering and Processing
Includes Legacy Gas Capital and Capital from Mature Wells
EOG RESOURCES, INC.
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (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.
Fourth Quarter and Full Year 2017 Forecast and Benchmark Commodity Pricing
(a)
Fourth Quarter and Full Year 2017 Forecast
The forecast items for the fourth 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)
4Q 2017
Full Year 2017
Daily Sales Volumes
Crude Oil and Condensate Volumes (MBbld)
United States
362.0
-
370.0
334.0
-
336.0
Trinidad
0.5
-
0.7
0.7
-
0.8
Other International
0.0
-
0.0
0.8
-
0.8
Total
362.5
-
370.7
335.5
-
337.6
Natural Gas Liquids Volumes (MBbld)
Total
84.0
-
94.0
84.2
-
86.8
Natural Gas Volumes (MMcfd)
United States
780
-
820
753
-
763
Trinidad
290
-
330
310
-
320
Other International
20
-
35
22
-
26
Total
1,090
-
1,185
1,085
-
1,109
Crude Oil Equivalent Volumes (MBoed)
United States
576.0
-
600.7
543.7
-
550.0
Trinidad
48.8
-
55.7
52.4
-
54.2
Other International
3.3
-
5.8
4.4
-
5.0
Total
628.1
-
662.2
600.5
-
609.2
Estimated Ranges
(Unaudited)
4Q 2017
Full Year 2017
Operating Costs
Unit Costs ($/Boe)
Lease and Well
$
4.10
- $ 4.50
$ 4.56
- $ 4.70
Transportation Costs
$
3.15
- $ 3.65
$ 3.33
- $ 3.47
Depreciation, Depletion and Amortization
$
15.15
- $ 15.70
$ 15.52
- $ 15.67
Expenses ($MM)
Exploration, Dry Hole and Impairment
$
90
- $ 120
$ 377
- $ 407
General and Administrative
$
100
- $ 110
$ 404
- $ 414
Gathering and Processing
$
35
- $ 38
$ 140
- $ 143
Capitalized Interest
$
5
- $ 7
$ 26
- $ 28
Net Interest
$
62
- $ 64
$ 273
- $ 275
Taxes Other Than Income (% of Wellhead Revenue)
6.1%
-
6.5%
6.7%
-
6.9%
Income Taxes
Effective Rate
36%
-
41%
36%
-
41%
Current Taxes ($MM)
$
(10)
- $ 25
$ (30)
- $ 5
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
$
0.25
- $ 2.25
$ (0.55)
- $ 0.00
Trinidad - above (below) WTI
$
(10.50) - $ (9.50)
$ (9.47)
- $ (9.27)
Other International - above (below) WTI
$
(5.00)
- $ (3.00)
$ (5.00)
- $ (4.50)
Natural Gas Liquids
Realizations as % of WTI
36%
-
42%
41%
-
42%
Natural Gas ($/Mcf)
Differentials
United States - above (below) NYMEX Henry Hub
$
(1.15)
- $ (0.75)
$ (0.97)
- $ (0.86)
Realizations
Trinidad
$
1.90
- $ 2.30
$ 2.22
- $ 2.32
Other International
$
3.95
- $ 4.45
$ 3.79
- $ 3.94
Definitions
$/Bbl
U.S. Dollars per barrel
$/Boe
U.S. Dollars per barrel of oil equivalent
$/Mcf
U.S. Dollars per thousand cubic feet
$MM
U.S. Dollars in millions
MBbld
Thousand barrels per day
MBoed
Thousand barrels of oil equivalent per day
MMcfd
Million cubic feet per day
NYMEX
U.S. New York Mercantile Exchange
WTI
West Texas Intermediate

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SOURCE EOG Resources, Inc.

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