HOUSTON, Feb. 27, 2018 /PRNewswire/ --
EOG Resources, Inc. (NYSE: EOG) (EOG) today reported fourth quarter 2017 net income of $2,430 million, or $4.20 per share. This compares to a fourth quarter 2016 net loss of $142 million, or $0.25 per share. For the full year 2017, EOG reported net income of $2,583 million, or $4.46 per share, compared to a net loss of $1,097 million, or $1.98 per share, for the full year 2016.
Adjusted non-GAAP net income for the fourth quarter 2017 was $401 million, or $0.69 per share, compared to an adjusted non-GAAP net loss of $7 million, or $0.01 per share, for the same prior year period. Adjusted non-GAAP net income for the full year 2017 was $648 million, or $1.12 per share, compared to an adjusted non-GAAP net loss of $893 million, or $1.61 per share, for the full year 2016. Adjusted non-GAAP net income (loss) is calculated by matching hedge realizations to settlement months and making certain other adjustments in order to exclude non-recurring and certain other items. One of the adjusting items in the fourth quarter and full year 2017 was a non-cash reduction in income tax expense of $2.2 billion, or $3.75 per share, related to the revaluation of EOG's deferred tax liability and certain other items resulting from the Tax Cuts and Jobs Act. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
Higher commodity prices, increased production volumes, well productivity improvements and per-unit cost reductions resulted in significant increases to adjusted non-GAAP net income, discretionary cash flow and EBITDAX for the fourth quarter 2017 compared to the fourth quarter 2016. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
Operational Highlights
Crude oil and condensate volumes in the U.S. increased 20 percent in 2017 to 335,000 barrels of oil per day (Bopd). Increased development activity and well productivity improvements supported the volume increase. Total company natural gas liquids (NGLs) volumes grew 8 percent while natural gas volumes decreased 6 percent primarily due to the sale of the company's Barnett and Haynesville Shale dry gas assets in late 2016. Transportation expenses decreased 11 percent and depreciation, depletion and amortization expenses decreased 12 percent, on a per-unit basis.
Increased development activity drove substantial volume increases in the Eagle Ford and Delaware Basin during the fourth quarter. Total company crude oil and condensate volumes increased 40,200 Bopd compared to the third quarter 2017. Natural gas liquids volumes grew 15 percent while natural gas volumes increased 6 percent, compared to the third quarter 2017.
"EOG emerged from the industry downturn in 2017 with unprecedented levels of efficiency and productivity, driving oil production volumes to record levels with capital expenditures approximately one half the prior peak," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "EOG's integrated teams demonstrated superb operational performance, overcoming a major hurricane and other challenges to deliver record production volumes and cost savings which surpassed original targets set at the beginning of the year."
2018 Capital Plan
EOG's disciplined capital plan is designed to achieve strong returns on capital employed and healthy growth while spending within cash flow. The company expects to grow total company crude oil volumes by 18 percent, generate double-digit ROCE and cover capital investment and dividend payments within discretionary cash flow. EOG can deliver on its 2018 plan at oil prices below $50 and generates significant free cash flow at a $60 oil price.
EOG's return-based culture continues to drive cost reductions. The company targets lower well costs and per-unit operating expenses in 2018 despite a potentially inflationary operating environment. EOG is also focused on driving continued improvements in well productivity and pursuing exploration efforts in new plays.
Capital expenditures for 2018 are expected to range from $5.4 to $5.8 billion, including production facilities and gathering, processing and other expenditures, and excluding acquisitions. EOG expects to complete approximately 690 net wells in 2018, compared to 536 net wells in 2017. Capital will be allocated primarily to EOG's highest rate-of-return oil assets in the Delaware Basin, Eagle Ford, Rockies, Woodford and the Bakken.
At least 90 percent of the wells completed in 2018 are expected to be premium. EOG has an inventory of approximately 8,000 such wells, which have a direct after-tax rate of return of at least 30 percent assuming $40 flat crude oil prices and $2.50 flat natural gas prices.
"EOG enters 2018 better positioned than ever to generate significant shareholder value through the development of its large and diverse inventory of high rate-of-return premium wells," Thomas said. "We are determined to maintain the discipline, record-level operational efficiency and performance gained through the downturn. Our deep inventory of premium wells across the U.S. offers flexibility to adjust to changing conditions. We also see significant opportunities to increase our premium well inventory through organic exploration and development technology to further extend EOG's return on capital advantage."
Dividend Increase
The board of directors increased the cash dividend on the common stock by 10.4 percent. Effective with the dividend payable April 30, 2018, to stockholders of record as of April 16, 2018, the board declared a quarterly dividend of $0.185 per share on the common stock. The indicated annual rate is $0.74 per share.
Delaware Basin
2017 was a watershed year for EOG in the Delaware Basin, where it successfully integrated the Yates acquisition, identified 1,240 additional net premium well locations, added the First Bone Spring as its fourth premium play and reduced completed well costs by $800,000 per well. Delaware Basin crude oil and condensate volumes increased over 80 percent in 2017 and exceeded 100,000 Bopd in the fourth quarter 2017.
EOG continued active development of its 416,000 net acre position in the Delaware Basin in the fourth quarter 2017, completing 65 wells.
In the Delaware Basin Wolfcamp, in Lea County, NM, EOG completed a four-well package, the Calm Breeze 2 Fed Com #701-704H, with an average treated lateral length of 7,100 feet per well and average 30-day initial production rates per well of 2,605 Bopd, 440 barrels per day (Bpd) of NGLs and 3.7 million cubic feet per day (MMcfd) of natural gas.
In the Delaware Basin First Bone Spring, in Lea County, NM, EOG completed the Righteous 6 State Com #301H with a treated lateral length of 7,100 feet and 30-day initial production rate of 1,305 Bopd, 170 Bpd of NGLs and 1.4 MMcfd of natural gas.
In the Delaware Basin Leonard, in Loving County, TX, EOG completed a four-well package, the State Atlas A#3H – D#6H, with an average treated lateral length of 9,800 feet per well and average 30-day initial production rates per well of 1,215 Bopd, 270 Bpd of NGLs and 2.3 MMcfd of natural gas.
South Texas Eagle Ford and Austin Chalk
EOG continues to enhance the productivity of its bellwether asset in the South Texas Eagle Ford. Eight years after initiating development, EOG further reduced well costs and improved well performance during 2017 in its 520,000 net acre position in the crude oil window of this world class play. EOG also expanded its enhanced oil recovery program, adding 56 wells last year. For the full year 2017, crude oil production in the Eagle Ford and Austin Chalk increased one percent year-over-year despite interruption to producing volumes as a result of Hurricane Harvey.
In the fourth quarter, EOG completed 74 wells in the Eagle Ford. These included 13 wells with lateral lengths of more than 10,000 feet. In LaSalle County, EOG completed a four-well package, the White 5H-8H, with an average treated lateral length of 12,900 feet per well and average 30-day initial production rates per well of 1,545 Bopd, 80 Bpd of NGLs and 0.5 MMcfd of natural gas. In DeWitt County, EOG completed a four-well package, the Hendrix 8H-10H and the Hendrix 12H, with an average treated lateral length of 6,700 feet per well and average 30-day initial production rates per well of 2,545 Bopd, 420 Bpd of NGLs and 2.4 MMcfd of natural gas.
EOG continued to test its position in the South Texas Austin Chalk, a geologically complex formation which lies above the South Texas Eagle Ford, completing four net wells in the fourth quarter.
Rockies
EOG's Wyoming Powder River Basin and DJ Basin activity both contributed to the company's 2017 crude oil production growth. In the Powder River Basin, EOG continued exploration activity on its 400,000 net acre position in the core of the play. The company tested the prospectivity of multiple target zones and also tested the aerial extent of various targets in the Powder River Basin during the year. In the DJ Basin, EOG achieved significant well cost reductions during 2017 through a focus on efficiency improvements in drilling and completion operations.
In the fourth quarter, EOG completed nine wells in the Powder River Basin. In Converse County, EOG completed the Mary's Draw 453-0310H and 455-0310H wells with an average treated lateral length of 7,300 feet per well and average 30-day initial production rates per well of 1,280 Bopd, 610 Bpd of NGLs and 7.6 MMcfd of natural gas. In the DJ Basin, EOG completed three wells in the fourth quarter. This included the Big Sandy 522-2536H with a treated lateral length of 8,800 feet and 30-day initial production rate of 1,100 Bopd, 110 Bpd of NGLs and 0.2 MMcfd of natural gas.
Reserves
At year-end 2017, total company net proved reserves were 2,527 million barrels of oil equivalent (MMBoe), an increase of 18 percent compared to year-end 2016. Net proved reserve additions from all sources, excluding revisions due to price, replaced 201 percent of EOG's 2017 production at a finding and development cost of $8.71 per barrel of oil equivalent. Revisions due to price increased net proved reserves by 154 MMBoe and asset divestitures decreased net proved reserves by 21 MMBoe. (For more reserves detail and a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.)
For the 30th consecutive year, internal reserves estimates were within 5 percent of estimates independently prepared by DeGolyer and MacNaughton.
Hedging Activity
During the fourth quarter ended December 31, 2017, EOG entered into crude oil financial price swap contracts and differential basis swap contracts. A comprehensive summary of crude oil and natural gas derivative contracts is provided in the attached tables.
Capital Structure and Asset Sales
At December 31, 2017, EOG's total debt outstanding was $6.4 billion with a debt-to-total capitalization ratio of 28 percent. Considering cash on the balance sheet at the end of the fourth quarter, EOG's net debt was $5.6 billion with a net debt-to-total capitalization ratio of 25 percent. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
Proceeds from asset sales for the full year 2017 totaled $227 million.
Conference Call February 28, 2018
EOG's fourth quarter and full year 2017 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Wednesday, February 28, 2018. To access the live audio webcast and related presentation materials, log on to the Investors Overview page on the EOG website at http://investors.eogresources.com/overview.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." For additional information about EOG, please visit www.eogresources.com.
This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production, 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. Furthermore, EOG has presented or referenced herein or in its accompanying disclosures certain forward-looking, non-GAAP financial measures, such as free cash flow and discretionary cash flow, and certain related estimates regarding future performance, results and financial position. These forward-looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented. EOG's actual results may differ materially from the measure and estimates presented or referenced herein. 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:
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, 2017, 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 |
|
Neel Panchal |
|
(713) 571-4884 |
|
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 |
Twelve Months Ended |
||||||||||
December 31, |
December 31, |
||||||||||
2017 |
2016 |
2017 |
2016 |
||||||||
Net Operating Revenues and Other |
$ |
3,340.4 |
$ |
2,402.0 |
$ |
11,208.3 |
$ |
7,650.6 |
|||
Net Income (Loss) |
$ |
2,430.5 |
$ |
(142.4) |
$ |
2,582.6 |
$ |
(1,096.7) |
|||
Net Income (Loss) Per Share |
|||||||||||
Basic |
$ |
4.22 |
$ |
(0.25) |
$ |
4.49 |
$ |
(1.98) |
|||
Diluted |
$ |
4.20 |
$ |
(0.25) |
$ |
4.46 |
$ |
(1.98) |
|||
Average Number of Common Shares |
|||||||||||
Basic |
575.4 |
567.3 |
574.6 |
553.4 |
|||||||
Diluted |
579.2 |
567.3 |
578.7 |
553.4 |
|||||||
Summary Income Statements |
|||||||||||
(Unaudited; in thousands, except per share data) |
|||||||||||
Three Months Ended |
Twelve Months Ended |
||||||||||
December 31, |
December 31, |
||||||||||
2017 |
2016 |
2017 |
2016 |
||||||||
Net Operating Revenues and Other |
|||||||||||
Crude Oil and Condensate |
$ |
1,929,471 |
$ |
1,366,223 |
$ |
6,256,396 |
$ |
4,317,341 |
|||
Natural Gas Liquids |
249,172 |
137,849 |
729,561 |
437,250 |
|||||||
Natural Gas |
246,922 |
215,373 |
921,934 |
742,152 |
|||||||
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts |
(45,032) |
(65,787) |
19,828 |
(99,608) |
|||||||
Gathering, Processing and Marketing |
1,008,385 |
614,594 |
3,298,087 |
1,966,259 |
|||||||
Gains (Losses) on Asset Dispositions, Net |
(65,220) |
104,034 |
(99,096) |
205,835 |
|||||||
Other, Net |
16,741 |
29,753 |
81,610 |
81,403 |
|||||||
Total |
3,340,439 |
2,402,039 |
11,208,320 |
7,650,632 |
|||||||
Operating Expenses |
|||||||||||
Lease and Well |
281,941 |
241,846 |
1,044,847 |
927,452 |
|||||||
Transportation Costs |
191,717 |
193,319 |
740,352 |
764,106 |
|||||||
Gathering and Processing Costs |
43,295 |
32,516 |
148,775 |
122,901 |
|||||||
Exploration Costs |
22,941 |
39,110 |
145,342 |
124,953 |
|||||||
Dry Hole Costs |
4,532 |
193 |
4,609 |
10,657 |
|||||||
Impairments |
153,442 |
297,946 |
479,240 |
620,267 |
|||||||
Marketing Costs |
1,009,566 |
634,248 |
3,330,237 |
2,007,635 |
|||||||
Depreciation, Depletion and Amortization |
881,745 |
862,524 |
3,409,387 |
3,553,417 |
|||||||
General and Administrative |
117,005 |
102,182 |
434,467 |
394,815 |
|||||||
Taxes Other Than Income |
158,343 |
103,642 |
544,662 |
349,710 |
|||||||
Total |
2,864,527 |
2,507,526 |
10,281,918 |
8,875,913 |
|||||||
Operating Income (Loss) |
475,912 |
(105,487) |
926,402 |
(1,225,281) |
|||||||
Other Income (Expense), Net |
803 |
(17,198) |
9,152 |
(50,543) |
|||||||
Income (Loss) Before Interest Expense and Income Taxes |
476,715 |
(122,685) |
935,554 |
(1,275,824) |
|||||||
Interest Expense, Net |
63,362 |
71,325 |
274,372 |
281,681 |
|||||||
Income (Loss) Before Income Taxes |
413,353 |
(194,010) |
661,182 |
(1,557,505) |
|||||||
Income Tax Benefit |
(2,017,115) |
(51,658) |
(1,921,397) |
(460,819) |
|||||||
Net Income (Loss) |
$ |
2,430,468 |
$ |
(142,352) |
$ |
2,582,579 |
$ |
(1,096,686) |
|||
Dividends Declared per Common Share |
$ |
0.1675 |
$ |
0.1675 |
$ |
0.6700 |
$ |
0.6700 |
EOG RESOURCES, INC. |
|||||||||||
Operating Highlights |
|||||||||||
(Unaudited) |
|||||||||||
Three Months Ended |
Twelve Months Ended |
||||||||||
December 31, |
December 31, |
||||||||||
2017 |
2016 |
2017 |
2016 |
||||||||
Wellhead Volumes and Prices |
|||||||||||
Crude Oil and Condensate Volumes (MBbld) (A) |
|||||||||||
United States |
366.9 |
306.0 |
335.0 |
278.3 |
|||||||
Trinidad |
1.1 |
0.9 |
0.9 |
0.8 |
|||||||
Other International (B) |
0.1 |
4.8 |
0.8 |
3.4 |
|||||||
Total |
368.1 |
311.7 |
336.7 |
282.5 |
|||||||
Average Crude Oil and Condensate Prices ($/Bbl) (C) |
|||||||||||
United States |
$ |
56.95 |
$ |
47.93 |
$ |
50.91 |
$ |
41.84 |
|||
Trinidad |
46.56 |
40.04 |
42.30 |
33.76 |
|||||||
Other International (B) |
45.72 |
38.96 |
57.20 |
36.72 |
|||||||
Composite |
56.97 |
47.76 |
50.91 |
41.76 |
|||||||
Natural Gas Liquids Volumes (MBbld) (A) |
|||||||||||
United States |
100.6 |
80.9 |
88.4 |
81.6 |
|||||||
Other International (B) |
- |
- |
- |
- |
|||||||
Total |
100.6 |
80.9 |
88.4 |
81.6 |
|||||||
Average Natural Gas Liquids Prices ($/Bbl) (C) |
|||||||||||
United States |
$ |
26.92 |
$ |
18.51 |
$ |
22.61 |
$ |
14.63 |
|||
Other International (B) |
- |
- |
- |
- |
|||||||
Composite |
26.92 |
18.51 |
22.61 |
14.63 |
|||||||
Natural Gas Volumes (MMcfd) (A) |
|||||||||||
United States |
829 |
800 |
765 |
810 |
|||||||
Trinidad |
299 |
323 |
313 |
340 |
|||||||
Other International (B) |
32 |
22 |
25 |
25 |
|||||||
Total |
1,160 |
1,145 |
1,103 |
1,175 |
|||||||
Average Natural Gas Prices ($/Mcf) (C) |
|||||||||||
United States |
$ |
2.17 |
$ |
2.05 |
$ |
2.20 |
$ |
1.60 |
|||
Trinidad |
2.52 |
1.89 |
2.38 |
1.88 |
|||||||
Other International (B) |
4.23 |
3.85 |
3.89 |
3.64 |
|||||||
Composite |
2.31 |
2.04 |
2.29 |
1.73 |
|||||||
Crude Oil Equivalent Volumes (MBoed) (D) |
|||||||||||
United States |
605.6 |
520.3 |
551.0 |
494.9 |
|||||||
Trinidad |
51.0 |
54.6 |
53.0 |
57.5 |
|||||||
Other International (B) |
5.4 |
8.6 |
4.9 |
7.6 |
|||||||
Total |
662.0 |
583.5 |
608.9 |
560.0 |
|||||||
Total MMBoe (D) |
60.9 |
53.7 |
222.3 |
205.0 |
|||||||
(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) |
|||||
December 31, |
December 31, |
||||
2017 |
2016 |
||||
ASSETS |
|||||
Current Assets |
|||||
Cash and Cash Equivalents |
$ |
834,228 |
$ |
1,599,895 |
|
Accounts Receivable, Net |
1,597,494 |
1,216,320 |
|||
Inventories |
483,865 |
350,017 |
|||
Assets from Price Risk Management Activities |
7,699 |
- |
|||
Income Taxes Receivable |
113,357 |
12,305 |
|||
Other |
242,465 |
206,679 |
|||
Total |
3,279,108 |
3,385,216 |
|||
Property, Plant and Equipment |
|||||
Oil and Gas Properties (Successful Efforts Method) |
52,555,741 |
49,592,091 |
|||
Other Property, Plant and Equipment |
3,960,759 |
4,008,564 |
|||
Total Property, Plant and Equipment |
56,516,500 |
53,600,655 |
|||
Less: Accumulated Depreciation, Depletion and Amortization |
(30,851,463) |
(27,893,577) |
|||
Total Property, Plant and Equipment, Net |
25,665,037 |
25,707,078 |
|||
Deferred Income Taxes |
17,506 |
16,140 |
|||
Other Assets |
871,427 |
190,767 |
|||
Total Assets |
$ |
29,833,078 |
$ |
29,299,201 |
|
LIABILITIES AND STOCKHOLDERS' EQUITY |
|||||
Current Liabilities |
|||||
Accounts Payable |
$ |
1,847,131 |
$ |
1,511,826 |
|
Accrued Taxes Payable |
148,874 |
118,411 |
|||
Dividends Payable |
96,410 |
96,120 |
|||
Liabilities from Price Risk Management Activities |
50,429 |
61,817 |
|||
Current Portion of Long-Term Debt |
356,235 |
6,579 |
|||
Other |
226,463 |
232,538 |
|||
Total |
2,725,542 |
2,027,291 |
|||
Long-Term Debt |
6,030,836 |
6,979,779 |
|||
Other Liabilities |
1,275,213 |
1,282,142 |
|||
Deferred Income Taxes |
3,518,214 |
5,028,408 |
|||
Commitments and Contingencies |
|||||
Stockholders' Equity |
|||||
Common Stock, $0.01 Par, 1,280,000,000 Shares and 640,000,000 |
205,788 |
205,770 |
|||
Additional Paid in Capital |
5,536,547 |
5,420,385 |
|||
Accumulated Other Comprehensive Loss |
(19,297) |
(19,010) |
|||
Retained Earnings |
10,593,533 |
8,398,118 |
|||
Common Stock Held in Treasury, 350,961 Shares and 250,155 Shares at December 31, 2017 and 2016, respectively |
(33,298) |
(23,682) |
|||
Total Stockholders' Equity |
16,283,273 |
13,981,581 |
|||
Total Liabilities and Stockholders' Equity |
$ |
29,833,078 |
$ |
29,299,201 |
EOG RESOURCES, INC. |
|||||
Summary Statements of Cash Flows |
|||||
(Unaudited; in thousands) |
|||||
Twelve Months Ended |
|||||
December 31, |
|||||
2017 |
2016 |
||||
Cash Flows from Operating Activities |
|||||
Reconciliation of Net Income (Loss) to Net Cash Provided by Operating Activities: |
|||||
Net Income (Loss) |
$ |
2,582,579 |
(1,096,686) |
||
Items Not Requiring (Providing) Cash |
|||||
Depreciation, Depletion and Amortization |
3,409,387 |
3,553,417 |
|||
Impairments |
479,240 |
620,267 |
|||
Stock-Based Compensation Expenses |
133,849 |
128,090 |
|||
Deferred Income Taxes |
(1,473,872) |
(515,206) |
|||
(Gains) Losses on Asset Dispositions, Net |
99,096 |
(205,835) |
|||
Other, Net |
6,546 |
61,690 |
|||
Dry Hole Costs |
4,609 |
10,657 |
|||
Mark-to-Market Commodity Derivative Contracts |
|||||
Total (Gains) Losses |
(19,828) |
99,608 |
|||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts |
7,438 |
(22,219) |
|||
Excess Tax Benefits from Stock-Based Compensation |
- |
(29,357) |
|||
Other, Net |
1,204 |
10,971 |
|||
Changes in Components of Working Capital and Other Assets and Liabilities |
|||||
Accounts Receivable |
(392,131) |
(232,799) |
|||
Inventories |
(174,548) |
170,694 |
|||
Accounts Payable |
324,192 |
(74,048) |
|||
Accrued Taxes Payable |
(63,937) |
92,782 |
|||
Other Assets |
(658,609) |
(40,636) |
|||
Other Liabilities |
(89,871) |
(16,225) |
|||
Changes in Components of Working Capital Associated with Investing and Financing Activities |
89,992 |
(156,102) |
|||
Net Cash Provided by Operating Activities |
4,265,336 |
2,359,063 |
|||
Investing Cash Flows |
|||||
Additions to Oil and Gas Properties |
(3,950,918) |
(2,489,756) |
|||
Additions to Other Property, Plant and Equipment |
(173,324) |
(93,039) |
|||
Proceeds from Sales of Assets |
226,768 |
1,119,215 |
|||
Net Cash Received from Yates Transaction |
- |
54,534 |
|||
Changes in Components of Working Capital Associated with Investing Activities |
(89,935) |
156,102 |
|||
Net Cash Used in Investing Activities |
(3,987,409) |
(1,252,944) |
|||
Financing Cash Flows |
|||||
Net Commercial Paper Repayments |
- |
(259,718) |
|||
Long-Term Debt Borrowings |
- |
991,097 |
|||
Long-Term Debt Repayments |
(600,000) |
(563,829) |
|||
Dividends Paid |
(386,531) |
(372,845) |
|||
Excess Tax Benefits from Stock-Based Compensation |
- |
29,357 |
|||
Treasury Stock Purchased |
(63,408) |
(82,125) |
|||
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan |
20,840 |
23,296 |
|||
Debt Issuance Costs |
- |
(1,602) |
|||
Repayment of Capital Lease Obligation |
(6,555) |
(6,353) |
|||
Other, Net |
(57) |
- |
|||
Net Cash Used in Financing Activities |
(1,035,711) |
(242,722) |
|||
Effect of Exchange Rate Changes on Cash |
(7,883) |
17,992 |
|||
Increase (Decrease) in Cash and Cash Equivalents |
(765,667) |
881,389 |
|||
Cash and Cash Equivalents at Beginning of Period |
1,599,895 |
718,506 |
|||
Cash and Cash Equivalents at End of Period |
$ |
834,228 |
$ |
1,599,895 |
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 twelve-month periods ended December 31, 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 and state apportionment change related to the Yates transaction in 2016, to add back an early lease termination payment as the result of a legal settlement in 2017, to add back the transaction costs for the formation of a joint venture in 2017, to add back joint interest billings deemed uncollectible in 2017, and to eliminate the impact of tax reform 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 |
||||||||||||||
December 31, 2017 |
December 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) |
$ 413,353 |
$2,017,115 |
$ 2,430,468 |
$ 4.20 |
$ (194,010) |
$ 51,658 |
$ (142,352) |
$ (0.25) |
|||||||
Adjustments: |
|||||||||||||||
(Gains) Losses on Mark-to-Market Commodity |
45,032 |
(16,142) |
28,890 |
0.05 |
65,787 |
(23,583) |
42,204 |
0.07 |
|||||||
Net Cash Received from (Payments for) Settlements of Commodity Derivative |
2,708 |
(971) |
1,737 |
- |
- |
29 |
29 |
- |
|||||||
Add: Net (Gains) Losses on Asset Dispositions |
65,220 |
(23,315) |
41,905 |
0.07 |
(104,034) |
36,856 |
(67,178) |
(0.12) |
|||||||
Add: Impairments |
100,304 |
(35,954) |
64,350 |
0.11 |
217,839 |
(76,728) |
141,111 |
0.25 |
|||||||
Add: Voluntary Retirement Expense |
- |
- |
- |
- |
- |
(57) |
(57) |
- |
|||||||
Add: Acquisition - State Apportionment Change |
- |
- |
- |
- |
- |
16,424 |
16,424 |
0.03 |
|||||||
Add: Acquisition Costs |
- |
- |
- |
- |
2,173 |
955 |
3,128 |
0.01 |
|||||||
Add: Joint Interest Billings Deemed Uncollectible |
4,528 |
(1,623) |
2,905 |
0.01 |
- |
- |
- |
- |
|||||||
Less: Tax Reform Impact |
- |
(2,169,376) |
(2,169,376) |
(3.75) |
- |
- |
- |
- |
|||||||
Adjustments to Net Income (Loss) |
217,792 |
(2,247,381) |
(2,029,589) |
(3.51) |
181,765 |
(46,104) |
135,661 |
0.24 |
|||||||
Adjusted Net Income (Loss) (Non-GAAP) |
$ 631,145 |
$ (230,266) |
$ 400,879 |
$ 0.69 |
$ (12,245) |
$ 5,554 |
$ (6,691) |
$ (0.01) |
|||||||
Average Number of Common Shares (GAAP) |
|||||||||||||||
Basic |
575,394 |
567,337 |
|||||||||||||
Diluted |
579,203 |
567,337 |
|||||||||||||
Twelve Months Ended |
Twelve Months Ended |
||||||||||||||
December 31, 2017 |
December 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) |
$ 661,182 |
$1,921,397 |
$ 2,582,579 |
$ 4.46 |
$(1,557,505) |
$ 460,819 |
$(1,096,686) |
$ (1.98) |
|||||||
Adjustments: |
|||||||||||||||
(Gains) Losses on Mark-to-Market Commodity |
(19,828) |
7,107 |
(12,721) |
(0.02) |
99,608 |
(35,640) |
63,968 |
0.12 |
|||||||
Net Cash Received from (Payments for) |
7,438 |
(2,666) |
4,772 |
0.01 |
(22,219) |
7,950 |
(14,269) |
(0.03) |
|||||||
Add: Net (Gains) Losses on Asset Dispositions |
99,096 |
(35,270) |
63,826 |
0.11 |
(205,835) |
61,491 |
(144,344) |
(0.26) |
|||||||
Add: Impairments |
261,452 |
(93,718) |
167,734 |
0.29 |
320,617 |
(113,368) |
207,249 |
0.37 |
|||||||
Add: Trinidad Tax Settlement |
- |
- |
- |
- |
- |
43,000 |
43,000 |
0.08 |
|||||||
Add: Voluntary Retirement Expense |
- |
- |
- |
- |
42,054 |
(15,047) |
27,007 |
0.05 |
|||||||
Add: Acquisition - State Apportionment Change |
- |
- |
- |
- |
- |
16,424 |
16,424 |
0.03 |
|||||||
Add: Acquisition Costs |
- |
- |
- |
- |
5,100 |
(88) |
5,012 |
0.01 |
|||||||
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 |
- |
- |
- |
- |
- |
|||||||
Add: Joint Interest Billings Deemed Uncollectible |
4,528 |
(1,623) |
2,905 |
0.01 |
- |
- |
- |
- |
|||||||
Less: Tax Reform Impact |
- |
(2,169,376) |
(2,169,376) |
(3.75) |
- |
- |
- |
- |
|||||||
Adjustments to Net Income (Loss) |
365,944 |
(2,300,298) |
(1,934,354) |
(3.34) |
239,325 |
(35,278) |
204,047 |
0.37 |
|||||||
Adjusted Net Income (Loss) (Non-GAAP) |
$ 1,027,126 |
$ (378,901) |
$ 648,225 |
$ 1.12 |
$(1,318,180) |
$ 425,541 |
$ (892,639) |
$ (1.61) |
|||||||
Average Number of Common Shares (GAAP) |
|||||||||||||||
Basic |
574,620 |
553,384 |
|||||||||||||
Diluted |
578,693 |
553,384 |
EOG RESOURCES, INC. |
||||||||||||
Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP) |
||||||||||||
To Net Cash Provided By Operating Activities (GAAP) |
||||||||||||
(Unaudited; in thousands) |
||||||||||||
Calculation of Free Cash Flow (Non-GAAP) |
||||||||||||
(Unaudited; in thousands) |
||||||||||||
The following chart reconciles the three-month and twelve-month periods ended December 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, Other Non-Current Taxes,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 defines Free Cash Flow (Non-GAAP) for a given period as Discretionary Cash Flow (Non-GAAP) (see below reconciliation) for such period less the total cash capital expenditures excluding acquisitions incurred (Non-GAAP) during such period and dividends paid (GAAP) during such period, as is illustrated below for the twelve months ended December 31, 2017. EOG management uses this information for comparative purposes within the industry. |
||||||||||||
Three Months Ended |
Twelve Months Ended |
|||||||||||
December 31, |
December 31, |
|||||||||||
2017 |
2016 |
2017 |
2016 |
|||||||||
Net Cash Provided by Operating Activities (GAAP) |
$ |
1,327,548 |
$ |
804,745 |
$ |
4,265,336 |
$ |
2,359,063 |
||||
Adjustments: |
||||||||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) |
16,420 |
33,931 |
122,688 |
104,199 |
||||||||
Excess Tax Benefits from Stock-Based Compensation |
- |
7,286 |
- |
29,357 |
||||||||
Other Non-Current Taxes (Non-Current Impact of the Tax Cut Jobs Act) |
(513,404) |
- |
(513,404) |
- |
||||||||
Changes in Components of Working Capital and Other Assets and Liabilities |
||||||||||||
Accounts Receivable |
366,686 |
220,939 |
392,131 |
232,799 |
||||||||
Inventories |
156,874 |
(33,131) |
174,548 |
(170,694) |
||||||||
Accounts Payable |
(211,298) |
(127,165) |
(324,192) |
74,048 |
||||||||
Accrued Taxes Payable |
13,970 |
21,214 |
63,937 |
(92,782) |
||||||||
Other Assets |
574,669 |
28,110 |
658,609 |
40,636 |
||||||||
Other Liabilities |
20,647 |
53,024 |
89,871 |
16,225 |
||||||||
Changes in Components of Working Capital Associated with Investing and Financing Activities |
(210,365) |
36,342 |
(89,992) |
156,102 |
||||||||
Discretionary Cash Flow (Non-GAAP) |
$ |
1,541,747 |
$ |
1,045,295 |
$ |
4,839,532 |
$ |
2,748,953 |
||||
Discretionary Cash Flow (Non-GAAP) - Percentage Increase |
47% |
76% |
||||||||||
Discretionary Cash Flow (Non-GAAP) |
$ |
4,839,532 |
||||||||||
Less: |
||||||||||||
Total Cash Expenditures Excluding Acquisitions (Non-GAAP)(a) |
(4,228,859) |
|||||||||||
Dividends Paid (GAAP) |
(386,531) |
|||||||||||
Free Cash Flow (Non-GAAP) |
$ |
224,142 |
||||||||||
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Expenditures Excluding Acquisitions (Non-GAAP) for the twelve months ended December 31, 2017: |
||||||||||||
Total Expenditures (GAAP) |
$ |
4,612,746 |
||||||||||
Less: |
||||||||||||
Asset Retirement Costs |
(55,592) |
|||||||||||
Non-Cash Acquisition Costs of Unproved Properties |
(255,711) |
|||||||||||
Acquisition Costs of Proved Properties |
(72,584) |
|||||||||||
Total Cash Expenditures Excluding Acquisitions (Non-GAAP) |
$ |
4,228,859 |
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 twelve-month periods ended December 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 (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 |
Twelve Months Ended |
||||||||||
December 31, |
December 31, |
||||||||||
2017 |
2016 |
2017 |
2016 |
||||||||
Net Income (Loss) (GAAP) |
$ |
2,430,468 |
$ |
(142,352) |
$ |
2,582,579 |
$ |
(1,096,686) |
|||
Adjustments: |
|||||||||||
Interest Expense, Net |
63,362 |
71,325 |
274,372 |
281,681 |
|||||||
Income Tax Provision (Benefit) |
(2,017,115) |
(51,658) |
(1,921,397) |
(460,819) |
|||||||
Depreciation, Depletion and Amortization |
881,745 |
862,524 |
3,409,387 |
3,553,417 |
|||||||
Exploration Costs |
22,941 |
39,110 |
145,342 |
124,953 |
|||||||
Dry Hole Costs |
4,532 |
193 |
4,609 |
10,657 |
|||||||
Impairments |
153,442 |
297,946 |
479,240 |
620,267 |
|||||||
EBITDAX (Non-GAAP) |
1,539,375 |
1,077,088 |
4,974,132 |
3,033,470 |
|||||||
Total (Gains) Losses on MTM Commodity Derivative Contracts |
45,032 |
65,787 |
(19,828) |
99,608 |
|||||||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts |
2,708 |
- |
7,438 |
(22,219) |
|||||||
(Gains) Losses on Asset Dispositions, Net |
65,220 |
(104,034) |
99,096 |
(205,835) |
|||||||
Adjusted EBITDAX (Non-GAAP) |
$ |
1,652,335 |
$ |
1,038,841 |
$ |
5,060,838 |
$ |
2,905,024 |
|||
Adjusted EBITDAX (Non-GAAP) - Percentage Increase |
59% |
74% |
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 |
||||
December 31, |
December 31, |
||||
2017 |
2016 |
||||
Total Stockholders' Equity - (a) |
$ |
16,283 |
$ |
13,982 |
|
Current and Long-Term Debt (GAAP) - (b) |
6,387 |
6,986 |
|||
Less: Cash |
(834) |
(1,600) |
|||
Net Debt (Non-GAAP) - (c) |
5,553 |
5,386 |
|||
Total Capitalization (GAAP) - (a) + (b) |
$ |
22,670 |
$ |
20,968 |
|
Total Capitalization (Non-GAAP) - (a) + (c) |
$ |
21,836 |
$ |
19,368 |
|
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] |
28% |
33% |
|||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] |
25% |
28% |
EOG RESOURCES, INC. |
||||||||
Reserves Supplemental Data |
||||||||
(Unaudited) |
||||||||
2017 NET PROVED RESERVES RECONCILIATION SUMMARY |
||||||||
United |
Other |
|||||||
States |
Trinidad |
International |
Total |
|||||
CRUDE OIL & CONDENSATE (MMBbl) |
||||||||
Beginning Reserves |
1,168.5 |
0.8 |
8.3 |
1,177.6 |
||||
Revisions |
58.0 |
0.1 |
(0.2) |
57.9 |
||||
Purchases in place |
1.1 |
- |
- |
1.1 |
||||
Extensions, discoveries and other additions |
207.1 |
0.3 |
0.1 |
207.5 |
||||
Sales in place |
(8.4) |
- |
- |
(8.4) |
||||
Production |
(122.2) |
(0.3) |
(0.2) |
(122.7) |
||||
Ending Reserves |
1,304.1 |
0.9 |
8.0 |
1,313.0 |
||||
NATURAL GAS LIQUIDS (MMBbl) |
||||||||
Beginning Reserves |
416.4 |
- |
- |
416.4 |
||||
Revisions |
46.9 |
- |
- |
46.9 |
||||
Purchases in place |
0.4 |
- |
- |
0.4 |
||||
Extensions, discoveries and other additions |
75.0 |
- |
- |
75.0 |
||||
Sales in place |
(2.9) |
- |
- |
(2.9) |
||||
Production |
(32.3) |
- |
- |
(32.3) |
||||
Ending Reserves |
503.5 |
- |
- |
503.5 |
||||
NATURAL GAS (Bcf) |
||||||||
Beginning Reserves |
3,021.2 |
280.9 |
15.8 |
3,317.9 |
||||
Revisions |
602.8 |
(27.4) |
8.6 |
584.0 |
||||
Purchases in place |
4.8 |
- |
- |
4.8 |
||||
Extensions, discoveries and other additions |
619.3 |
174.2 |
35.9 |
829.4 |
||||
Sales in place |
(56.4) |
- |
- |
(56.4) |
||||
Production |
(293.2) |
(114.3) |
(9.1) |
(416.6) |
||||
Ending Reserves |
3,898.5 |
313.4 |
51.2 |
4,263.1 |
||||
OIL EQUIVALENTS (MMBoe) |
||||||||
Beginning Reserves |
2,088.4 |
47.7 |
10.9 |
2,147.0 |
||||
Revisions |
205.3 |
(4.5) |
1.2 |
202.0 |
||||
Purchases in place |
2.3 |
- |
- |
2.3 |
||||
Extensions, discoveries and other additions |
385.4 |
29.3 |
6.1 |
420.8 |
||||
Sales in place |
(20.7) |
- |
- |
(20.7) |
||||
Production |
(203.4) |
(19.4) |
(1.6) |
(224.4) |
||||
Ending Reserves |
2,457.3 |
53.1 |
16.6 |
2,527.0 |
||||
Net Proved Developed Reserves (MMBoe) |
||||||||
At December 31, 2016 |
1,038.5 |
44.5 |
10.9 |
1,093.9 |
||||
At December 31, 2017 |
1,300.7 |
50.8 |
12.8 |
1,364.3 |
||||
2017 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ Millions) |
||||||||
United |
Other |
|||||||
States |
Trinidad |
International |
Total |
|||||
Acquisition Cost of Unproved Properties |
$ 424.1 |
$ 2.4 |
$ - |
$ 426.5 |
||||
Exploration Costs |
144.5 |
62.6 |
16.5 |
223.6 |
||||
Development Costs |
3,540.7 |
107.2 |
13.2 |
3,661.1 |
||||
Total Drilling |
4,109.3 |
172.2 |
29.7 |
4,311.2 |
||||
Acquisition Cost of Proved Properties |
72.6 |
- |
- |
72.6 |
||||
Asset Retirement Costs |
50.2 |
2.3 |
3.1 |
55.6 |
||||
Total Exploration & Development Expenditures |
4,232.1 |
174.5 |
32.8 |
4,439.4 |
||||
Gathering, Processing and Other |
173.0 |
0.1 |
0.2 |
173.3 |
||||
Total Expenditures |
4,405.1 |
174.6 |
33.0 |
4,612.7 |
||||
Proceeds from Sales in Place |
(226.6) |
- |
- |
(226.6) |
||||
Net Expenditures |
$ 4,178.5 |
$ 174.6 |
$ 33.0 |
$ 4,386.1 |
||||
RESERVE REPLACEMENT COSTS ($ / Boe ) * |
||||||||
All-in Total, Net of Revisions |
$ 6.58 |
$ 6.94 |
$ 4.07 |
$ 6.56 |
||||
All-in Total, Excluding Revisions Due to Price |
$ 8.88 |
$ 6.94 |
$ 4.07 |
$ 8.71 |
||||
RESERVE REPLACEMENT * |
||||||||
Drilling Only |
190% |
151% |
381% |
188% |
||||
All-in Total, Net of Revisions & Dispositions |
281% |
128% |
456% |
269% |
||||
All-in Total, Excluding Revisions Due to Price |
206% |
128% |
456% |
201% |
||||
All-in Total, Liquids |
244% |
133% |
-50% |
244% |
||||
* See attached reconciliation schedule for calculation methodology |
EOG RESOURCES, INC. |
||||||||
Quantitative Reconciliation of Total Exploration and Development Expenditures (Non-GAAP) |
||||||||
As Used in the Calculation of Reserve Replacement Costs ($ / BOE) |
||||||||
To Total Costs Incurred in Exploration and Development Activities (GAAP) |
||||||||
(Unaudited; in millions, except ratio information) |
||||||||
The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Reserve Replacement Costs per Boe. There are numerous ways that industry participants present Reserve Replacement Costs, including an "All-In" calculation, which reflects total exploration and development expenditures divided by total net proved reserve additions from all sources. Combined with Reserve Replacement, these statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry. Please note that the actual cost of adding reserves will vary from the reported statistics due to timing differences in reserve bookings and capital expenditures. Accordingly, some analysts use three or five year averages of reported statistics, while others prefer to estimate future costs. EOG has not included future capital costs to develop proved undeveloped reserves in exploration and development expenditures. |
||||||||
For the Twelve Months Ended December 31, 2017 |
||||||||
United |
Other |
|||||||
States |
Trinidad |
International |
Total |
|||||
Total Costs Incurred in Exploration and Development Activities (GAAP) |
$ 4,232.1 |
$ 174.5 |
$ 32.8 |
$ 4,439.4 |
||||
Less: Asset Retirement Costs |
(50.2) |
(2.3) |
(3.1) |
(55.6) |
||||
Non-Cash Acquisition Costs of Unproved Properties |
(255.7) |
- |
- |
(255.7) |
||||
Non-Cash Acquisition Costs of Proved Properties |
(26.2) |
- |
- |
(26.2) |
||||
Total Exploration & Development Expenditures (Non-GAAP) (a) |
$ 3,900.0 |
$ 172.2 |
$ 29.7 |
$ 4,101.9 |
||||
Total Expenditures (GAAP) |
$ 4,405.1 |
$ 174.6 |
$ 33.0 |
$ 4,612.7 |
||||
Less: Asset Retirement Costs |
(50.2) |
(2.3) |
(3.1) |
(55.6) |
||||
Non-Cash Acquisition Costs of Unproved Properties |
(255.7) |
- |
- |
(255.7) |
||||
Non-Cash Acquisition Costs of Proved Properties |
(26.2) |
- |
- |
(26.2) |
||||
Total Cash Expenditures (Non-GAAP) |
$ 4,073.0 |
$ 172.3 |
$ 29.9 |
$ 4,275.2 |
||||
Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe) |
||||||||
Revisions due to price (b) |
154.0 |
- |
- |
154.0 |
||||
Revisions other than price |
51.3 |
(4.5) |
1.2 |
48.0 |
||||
Purchases in place |
2.3 |
- |
- |
2.3 |
||||
Extensions, discoveries and other additions (c) |
385.4 |
29.3 |
6.1 |
420.8 |
||||
Total Proved Reserve Additions (d) |
593.0 |
24.8 |
7.3 |
625.1 |
||||
Sales in place |
(20.7) |
- |
- |
(20.7) |
||||
Net Proved Reserve Additions From All Sources (e) |
572.3 |
24.8 |
7.3 |
604.4 |
||||
Production (f) |
203.4 |
19.4 |
1.6 |
224.4 |
||||
RESERVE REPLACEMENT COSTS ($ / Boe) |
||||||||
All-in Total, Net of Revisions (a / d) |
$ 6.58 |
$ 6.94 |
$ 4.07 |
$ 6.56 |
||||
All-in Total, Excluding Revisions Due to Price (a / (d - b)) |
$ 8.88 |
$ 6.94 |
$ 4.07 |
$ 8.71 |
||||
RESERVE REPLACEMENT |
||||||||
Drilling Only (c / f) |
190% |
151% |
381% |
188% |
||||
All-in Total, Net of Revisions & Dispositions (e / f) |
281% |
128% |
456% |
269% |
||||
All-in Total, Excluding Revisions Due to Price ((e - b ) / f) |
206% |
128% |
456% |
201% |
||||
Net Proved Reserve Additions From All Sources - Liquids (MMBbl) |
||||||||
Revisions |
104.9 |
0.1 |
(0.2) |
104.8 |
||||
Purchases in place |
1.5 |
- |
- |
1.5 |
||||
Extensions, discoveries and other additions (g) |
282.1 |
0.3 |
0.1 |
282.5 |
||||
Total Proved Reserve Additions |
388.5 |
0.4 |
(0.1) |
388.8 |
||||
Sales in place |
(11.3) |
- |
- |
(11.3) |
||||
Net Proved Reserve Additions From All Sources (h) |
377.2 |
0.4 |
(0.1) |
377.5 |
||||
Production (i) |
154.5 |
0.3 |
0.2 |
155.0 |
||||
RESERVE REPLACEMENT - LIQUIDS |
||||||||
Drilling Only (g / i) |
183% |
100% |
50% |
182% |
||||
All-in Total, Net of Revisions & Dispositions (h / i) |
244% |
133% |
-50% |
244% |
||||
EOG RESOURCES, INC. |
||||||||
Quantitative Reconciliation of Drillbit Exploration and Development Expenditures (Non-GAAP) |
||||||||
As Used in the Calculation of Proved Developed Reserve Replacement Costs ($ / BOE) |
||||||||
To Total Costs Incurred in Exploration and Development Activities (GAAP) |
||||||||
(Unaudited; in millions, except ratio information) |
||||||||
The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Drillbit Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Proved Developed Reserve Replacement Costs per Boe. These statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry. |
||||||||
For the Twelve Months Ended December 31, 2017 |
||||||||
Total |
||||||||
PROVED DEVELOPED RESERVE REPLACEMENT COSTS ($ / Boe) |
||||||||
Total Costs Incurred in Exploration and Development Activities (GAAP) |
$ 4,439.4 |
|||||||
Less: Asset Retirement Costs |
(55.6) |
|||||||
Acquisition Costs of Unproved Properties |
(426.5) |
|||||||
Acquisition Cost of Proved Properties |
(72.6) |
|||||||
Drillbit Exploration & Development Expenditures (Non-GAAP) (j) |
$ 3,884.7 |
|||||||
Total Proved Reserves - Extensions, discoveries and other additions (MMBoe) |
420.8 |
|||||||
Add: Conversion of proved undeveloped reserves to proved developed |
152.6 |
|||||||
Less: Proved undeveloped extensions and discoveries |
(237.4) |
|||||||
Proved Developed Reserves - Extensions and discoveries (MMBoe) |
336.0 |
|||||||
Total Proved Reserves - Revisions (MMBoe) |
202.0 |
|||||||
Less: Proved Undeveloped Reserves - Revisions |
(33.1) |
|||||||
Proved Developed - Revisions due to price |
(143.0) |
|||||||
Proved Developed Reserves - Revisions other than price (MMBoe) |
25.9 |
|||||||
Proved Developed Reserves - Extensions and discoveries plus revisions other than price (MMBoe) (k) |
361.9 |
|||||||
Proved Developed Reserve Replacement Cost Excluding Revisions Due to Price ($ / Boe) (j / k) |
$ 10.73 |
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 has entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma (Midland Differential). Presented below is a comprehensive summary of EOG's Midland Differential basis swap contracts through February 20, 2018. The weighted average price differential expressed in $/Bbl represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. |
|||||||||||
Midland Differential Basis Swap Contracts |
|||||||||||
Weighted |
|||||||||||
Average Price |
|||||||||||
Volume |
Differential |
||||||||||
(Bbld) |
($/Bbl) |
||||||||||
2018 |
|||||||||||
January 1, 2018 through February 28, 2018 (closed) |
15,000 |
$ 1.063 |
|||||||||
March 1, 2018 through December 31, 2018 |
15,000 |
1.063 |
|||||||||
2019 |
|||||||||||
January 1, 2019 through December 31, 2019 |
20,000 |
$ 1.075 |
|||||||||
EOG has entered into additional crude oil basis swap contracts in order to fix the differential between pricing in the U.S. Gulf Coast and Cushing, Oklahoma (Gulf Coast Differential). Presented below is a comprehensive summary of EOG's Gulf Coast Differential basis swap contracts through February 20, 2018. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. |
|||||||||||
Gulf Coast Differential Basis Swap Contracts |
|||||||||||
Weighted |
|||||||||||
Average Price |
|||||||||||
Volume |
Differential |
||||||||||
(Bbld) |
($/Bbl) |
||||||||||
2018 |
|||||||||||
January 1, 2018 through February 28, 2018 (closed) |
37,000 |
$ 3.818 |
|||||||||
March 1, 2018 through December 31, 2018 |
37,000 |
3.818 |
|||||||||
On March 14, 2017, EOG executed the optional early termination provision granting EOG the right to terminate certain 2017 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 table below. Presented below is a comprehensive summary of EOG's crude oil price swap contracts through February 20, 2018, 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 |
|||||||||
2018 |
|||||||||||
January 2018 (closed) |
134,000 |
$ 60.04 |
|||||||||
February 1, 2018 through December 31, 2018 |
134,000 |
60.04 |
|||||||||
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 offset the remaining 2017 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 February 20, 2018, 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 February 20, 2018, 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 February 20, 2018, 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. |
||||||||||||||
2017 |
2016 |
2015 |
2014 |
2013 |
||||||||||
Return on Capital Employed (ROCE) (Non-GAAP) |
||||||||||||||
Net Interest Expense (GAAP) |
$ |
274 |
$ |
282 |
$ |
237 |
$ |
201 |
||||||
Tax Benefit Imputed (based on 35%) |
(96) |
(99) |
(83) |
(70) |
||||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
$ |
178 |
$ |
183 |
$ |
154 |
$ |
131 |
||||||
Net Income (Loss) (GAAP) - (b) |
$ |
2,583 |
$ |
(1,097) |
$ |
(4,525) |
$ |
2,915 |
||||||
Adjustments to Net Income (Loss), Net of Tax (See Accompanying Schedules) |
(1,934) |
(a) |
204 |
(b) |
4,559 |
(c) |
(199) |
(d) |
||||||
Adjusted Net Income (Loss) (Non-GAAP) - (c) |
$ |
649 |
$ |
(893) |
$ |
34 |
$ |
2,716 |
||||||
Total Stockholders' Equity Before Retained Earnings Adjustment (GAAP) - (d) |
$ |
16,283 |
$ |
13,982 |
$ |
12,943 |
$ |
17,713 |
$ |
15,418 |
||||
Less: Tax Reform Impact |
(2,169) |
- |
- |
- |
- |
|||||||||
Total Stockholders' Equity (Non-GAAP) - (e) |
$ |
14,114 |
$ |
13,982 |
$ |
12,943 |
$ |
17,713 |
$ |
15,418 |
||||
Average Total Stockholders' Equity (GAAP) * - (f) |
$ |
15,133 |
$ |
13,463 |
$ |
15,328 |
$ |
16,566 |
||||||
Average Total Stockholders' Equity (Non-GAAP) * - (g) |
$ |
14,048 |
$ |
13,463 |
$ |
15,328 |
$ |
16,566 |
||||||
Current and Long-Term Debt (GAAP) - (h) |
$ |
6,387 |
$ |
6,986 |
$ |
6,655 |
$ |
5,906 |
$ |
5,909 |
||||
Less: Cash |
(834) |
(1,600) |
(719) |
(2,087) |
(1,318) |
|||||||||
Net Debt (Non-GAAP) - (i) |
$ |
5,553 |
$ |
5,386 |
$ |
5,936 |
$ |
3,819 |
$ |
4,591 |
||||
Total Capitalization (GAAP) - (d) + (h) |
$ |
22,670 |
$ |
20,968 |
$ |
19,598 |
$ |
23,619 |
$ |
21,327 |
||||
Total Capitalization (Non-GAAP) - (e) + (i) |
$ |
19,667 |
$ |
19,368 |
$ |
18,879 |
$ |
21,532 |
$ |
20,009 |
||||
Average Total Capitalization (Non-GAAP) * - (j) |
$ |
19,518 |
$ |
19,124 |
$ |
20,206 |
$ |
20,771 |
||||||
ROCE (GAAP Net Income) - [(a) + (b)] / (j) |
14.1% |
-4.8% |
-21.6% |
14.7% |
||||||||||
ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (j) |
4.2% |
-3.7% |
0.9% |
13.7% |
||||||||||
Return on Equity (ROE) |
||||||||||||||
ROE (GAAP) (GAAP Net Income) - (b) / (f) |
17.1% |
-8.1% |
-29.5% |
17.6% |
||||||||||
ROE (Non-GAAP) (Non-GAAP Adjusted Net Income) - (c) / (g) |
4.6% |
-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 2017: |
||||||||||||||
Year Ended December 31, 2017 |
||||||||||||||
Before |
Income Tax |
After |
||||||||||||
Tax |
Impact |
Tax |
||||||||||||
Adjustments: |
||||||||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
(12) |
$ |
4 |
$ |
(8) |
||||||||
Add: Impairments of Certain Assets |
261 |
(93) |
168 |
|||||||||||
Add: Net Losses on Asset Dispositions |
99 |
(35) |
64 |
|||||||||||
Add: Legal Settlement - Early Lease Termination |
10 |
(4) |
6 |
|||||||||||
Add: Joint Venture Transaction Costs |
3 |
(1) |
2 |
|||||||||||
Add: Joint Interest Billings Deemed Uncollectible |
5 |
(2) |
3 |
|||||||||||
Less: Tax Reform Impact |
- |
(2,169) |
(2,169) |
|||||||||||
Total |
$ |
366 |
$ |
(2,300) |
$ |
(1,934) |
||||||||
(b) 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 |
||||||||
(c) 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 |
||||||||
(d) 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. |
|||||||||||
First Quarter and Full Year 2018 Forecast and Benchmark Commodity Pricing |
|||||||||||
(a) First Quarter and Full Year 2018 Forecast |
|||||||||||
The forecast items for the first quarter and full year 2018 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) |
|||||||||||
1Q 2018 |
Full Year 2018 |
||||||||||
Daily Sales Volumes |
|||||||||||
Crude Oil and Condensate Volumes (MBbld) |
|||||||||||
United States |
350.0 |
- |
360.0 |
387.0 |
- |
401.0 |
|||||
Trinidad |
0.5 |
- |
0.7 |
0.4 |
- |
0.6 |
|||||
Other International |
0.0 |
- |
5.0 |
2.0 |
- |
4.0 |
|||||
Total |
350.5 |
- |
365.7 |
389.4 |
- |
405.6 |
|||||
Natural Gas Liquids Volumes (MBbld) |
|||||||||||
Total |
93.0 |
- |
103.0 |
100.0 |
- |
110.0 |
|||||
Natural Gas Volumes (MMcfd) |
|||||||||||
United States |
825 |
- |
865 |
900 |
- |
950 |
|||||
Trinidad |
280 |
- |
310 |
250 |
- |
290 |
|||||
Other International |
25 |
- |
35 |
28 |
- |
38 |
|||||
Total |
1,130 |
- |
1,210 |
1,178 |
- |
1,278 |
|||||
Crude Oil Equivalent Volumes (MBoed) |
|||||||||||
United States |
580.5 |
- |
607.2 |
637.0 |
- |
669.3 |
|||||
Trinidad |
47.2 |
- |
52.4 |
42.1 |
- |
48.9 |
|||||
Other International |
4.2 |
- |
10.8 |
6.7 |
- |
10.3 |
|||||
Total |
631.9 |
- |
670.4 |
685.8 |
- |
728.5 |
|||||
Estimated Ranges |
|||||||||||
(Unaudited) |
|||||||||||
1Q 2018 |
Full Year 2018 |
||||||||||
Operating Costs |
|||||||||||
Unit Costs ($/Boe) |
|||||||||||
Lease and Well |
$ |
4.70 |
- |
$ |
5.10 |
$ |
4.20 |
- |
$ |
4.80 |
|
Transportation Costs |
$ |
3.00 |
- |
$ |
3.50 |
$ |
2.75 |
- |
$ |
3.25 |
|
Depreciation, Depletion and Amortization |
$ |
13.00 |
- |
$ |
13.40 |
$ |
13.10 |
- |
$ |
13.50 |
|
Expenses ($MM) |
|||||||||||
Exploration, Dry Hole and Impairment |
$ |
90 |
- |
$ |
120 |
$ |
375 |
- |
$ |
425 |
|
General and Administrative |
$ |
100 |
- |
$ |
110 |
$ |
415 |
- |
$ |
445 |
|
Gathering and Processing |
$ |
95 |
- |
$ |
105 |
$ |
430 |
- |
$ |
470 |
|
Capitalized Interest |
$ |
6 |
- |
$ |
8 |
$ |
27 |
- |
$ |
32 |
|
Net Interest |
$ |
60 |
- |
$ |
62 |
$ |
234 |
- |
$ |
242 |
|
Taxes Other Than Income (% of Wellhead Revenue) |
6.6% |
- |
7.0% |
6.5% |
- |
6.9% |
|||||
Income Taxes |
|||||||||||
Effective Rate |
20% |
- |
25% |
20% |
- |
25% |
|||||
Current Tax (Benefit) / Expense ($MM) |
$ |
(90) |
- |
$ |
(55) |
$ |
(310) |
- |
$ |
(270) |
|
Capital Expenditures (Excluding Acquisitions, $MM) |
|||||||||||
Exploration and Development, Excluding Facilities |
$ |
4,500 |
- |
$ |
4,800 |
||||||
Exploration and Development Facilities |
$ |
600 |
- |
$ |
650 |
||||||
Gathering, Processing and Other |
$ |
300 |
- |
$ |
350 |
||||||
Pricing - (Refer to Benchmark Commodity Pricing in text) |
|||||||||||
Crude Oil and Condensate ($/Bbl) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) WTI |
$ |
0.00 |
- |
$ |
1.50 |
$ |
(1.00) |
- |
$ |
1.00 |
|
Trinidad - above (below) WTI |
$ |
(11.00) |
- |
$ |
(9.00) |
$ |
(11.00) |
- |
$ |
(9.00) |
|
Other International - above (below) WTI |
$ |
0.00 |
- |
$ |
2.00 |
$ |
0.00 |
- |
$ |
2.00 |
|
Natural Gas Liquids |
|||||||||||
Realizations as % of WTI |
39% |
- |
45% |
40% |
- |
46% |
|||||
Natural Gas ($/Mcf) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) NYMEX Henry Hub |
$ |
(0.40) |
- |
$ |
0.00 |
$ |
(0.60) |
- |
$ |
0.00 |
|
Realizations |
|||||||||||
Trinidad |
$ |
2.50 |
- |
$ |
2.90 |
$ |
2.15 |
- |
$ |
2.75 |
|
Other International |
$ |
4.15 |
- |
$ |
4.65 |
$ |
4.00 |
- |
$ |
5.00 |
|
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 |
EOG RESOURCES, INC. |
||||||||||||||
Fourth Quarter 2017 Well Results by Play |
||||||||||||||
(Unaudited) |
||||||||||||||
Wells Completed |
Initial 30-Day Average Production Rate |
|||||||||||||
Gross |
Net |
Lateral |
Crude Oil and |
Natural Gas |
Natural Gas |
Crude Oil |
||||||||
Delaware Basin |
||||||||||||||
Wolfcamp |
51 |
45 |
6,000 |
1,410 |
310 |
2.5 |
2,145 |
|||||||
Bone Spring |
9 |
9 |
6,700 |
1,085 |
160 |
1.3 |
1,470 |
|||||||
Leonard |
5 |
5 |
8,700 |
1,230 |
265 |
2.2 |
1,865 |
|||||||
Powder River Basin Turner |
9 |
7 |
7,700 |
990 |
375 |
4.7 |
2,150 |
|||||||
DJ Basin Codell |
3 |
2 |
9,100 |
950 |
105 |
0.4 |
1,120 |
|||||||
South Texas Eagle Ford |
74 |
70 |
7,400 |
1,525 |
195 |
1.1 |
1,915 |
|||||||
South Texas Austin Chalk |
4 |
4 |
5,300 |
2,280 |
430 |
2.5 |
3,130 |
|||||||
(A) Barrels per day or million cubic feet per day, as applicable. |
||||||||||||||
(B) Barrels of oil equivalent per day; 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. |
View original content:http://www.prnewswire.com/news-releases/eog-resources-reports-fourth-quarter-and-full-year-2017-results-and-announces-2018-capital-program-300605294.html
SOURCE EOG Resources, Inc.