HOUSTON, Feb. 26, 2019 /PRNewswire/ --
EOG Resources, Inc. (EOG) today reported fourth quarter 2018 net income of $893 million, or $1.54 per share. This compares to fourth quarter 2017 net income of $2.4 billion, or $4.20 per share. For the full year 2018, EOG reported a company record net income of $3.4 billion, or $5.89 per share, compared to $2.6 billion, or $4.46 per share, for the full year 2017. Net cash from operating activities for the fourth quarter and full year 2018 was $2.1 billion and $7.8 billion, respectively.
Adjusted non-GAAP net income for the fourth quarter 2018 was $718 million, or $1.24 per share, compared to adjusted non-GAAP net income of $401 million, or $0.69 per share, for the same prior year period. Adjusted non-GAAP net income for the full year 2018 was $3.2 billion, or $5.54 per share, compared to adjusted non-GAAP net income of $648 million, or $1.12 per share, for the full year 2017. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.
Fourth Quarter and Full Year 2018 Review
EOG delivered exceptional financial and operating performance in 2018. The company generated record net income and free cash flow, while ending the year with strong improvements in well productivity and additional cost reductions. Total company crude oil volumes grew 19 percent to 399,900 barrels of oil per day (Bopd). Natural gas liquids production increased 31 percent, while natural gas volumes grew 11 percent, contributing to total company production growth of 18 percent.
In the fourth quarter 2018, EOG exceeded the high end of its target range for U.S. crude oil volumes by producing 430,300 Bopd, an increase of 17 percent compared to the same prior year period. Per-unit operating expenses declined during the fourth quarter 2018 compared to the same prior year period. Lower general and administrative expenses, transportation costs and depreciation, depletion and amortization expenses each contributed to the overall cost reduction.
EOG generated $2.1 billion of discretionary cash flow and incurred total expenditures of $1.5 billion in the fourth quarter 2018. After considering cash exploration and development expenditures, excluding acquisitions, of $1.3 billion and dividend payments of $127 million, the company generated free cash flow during the fourth quarter of $637 million. For the full year 2018 EOG generated a company record $1.7 billion of free cash flow. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.
"Our goal at EOG is to be one of the best companies in the S&P 500. Our stellar 2018 performance delivered a premium combination of high returns and double-digit production growth while generating record free cash flow," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "Our 2018 results show that we can be competitive with the best companies across all sectors, and we remain relentlessly focused on further improving our cost structure and operating performance."
2019 Capital Plan
EOG's capital plan is custom-designed each year to increase returns and capital efficiencies. In 2019, EOG is allocating more capital to opportunistic, high quality new drilling potential and somewhat less capital to drilling in established areas. The company's disciplined growth strategy emphasizes generating free cash flow while lowering well costs and per-unit operating expenses and driving improvement in well productivity. Retaining high-quality equipment and crews during the fourth quarter of 2018 positioned the company to further improve efficiencies and returns in 2019.
EOG expects to grow U.S. crude oil production by 12 to 16 percent, fund capital investment and pay the dividend with net cash from operating activities in 2019 at $50 oil. Exploration and development expenditures for 2019 are expected to range from $6.1 to $6.5 billion, including facilities and gathering, processing and other expenditures, excluding acquisitions and non-cash exchanges.
EOG expects to complete approximately 740 net wells in 2019 compared to 763 net wells in 2018. Activity will remain focused in EOG's highest rate-of-return oil assets in the Delaware Basin, Eagle Ford, Rockies, Woodford and Bakken. The company's investment in new potential areas in the United States includes spending for leasing and related infrastructure to drill wells in a number of new prospects in 2019.
"EOG's disciplined 2019 capital plan delivers improved capital efficiency and strong high-return growth while making investments in new organic high-quality drilling potential to improve the future performance of the company," Thomas said. "Our focus on innovation and operational execution, as well as our investment in new drilling potential, will continue to increase the quality of EOG's premium portfolio. EOG is poised to further improve its position as one of the lowest cost oil producers in the global market, able to create shareholder value through commodity price cycles."
Operating Highlights
EOG completed 262 net wells in the Delaware Basin and increased crude oil production 47% to 126,800 Bopd in 2018. The company made significant progress during 2018 in improving well productivity and reducing well costs. EOG refined spacing and development patterns, reduced drilling days and applied new completion technology designed to lower costs and improve well productivity.
EOG continues to drive growth and operating efficiencies in its premier South Texas Eagle Ford asset. In 2018, the company grew crude oil production 9% to 171,000 Bopd. Of the 304 net wells completed in 2018, EOG drilled a total of 65 wells with lateral lengths greater than 10,000 feet. These wells included the Slytherin C#3H, which, at 13,500 feet, was a company record in the Eagle Ford.
EOG's Powder River Basin and Wyoming DJ Basin activity both contributed to the company's 2018 crude oil production growth. In the Powder River Basin, the company brought eight wells on line during the fourth quarter targeting the Turner, Mowry and Parkman formations. The company plans to add infrastructure and further delineate the field and test additional targets in 2019 to be positioned to execute a more robust development program in the Niobrara and Mowry in 2020 and beyond. In the Wyoming DJ Basin, EOG generated further cost reductions during 2018 through efficiency improvements in drilling, completion and production operations. The company brought 20 wells to sales in the fourth quarter, all targeting the Codell formation. EOG expects further crude oil production growth from its high rate of return drilling in the DJ Basin in 2019.
EOG continued development of its premium play in the Eastern Anadarko Basin Woodford Oil Window, where it brought five wells on line in the fourth quarter. The company made significant progress in reducing well costs during 2018, and, as a result, has lowered its 2019 well cost target to $7.6 million.
In the Williston Basin, EOG realized significant operational improvements in 2018. The company drilled 20 net wells with an average treated lateral length of 9,500 feet per well. Efficient drilling performance delivered, on average, an additional 1,000 feet of lateral length per well in 2018 for the same cost as 2017. EOG's Austin 45-1113H well set a company record in the basin with a spud-to-total depth time of 8.4 days.
Reserves
At year-end 2018, total company net proved reserves were 2,928 million barrels of oil equivalent (MMBoe), an increase of 16 percent compared to year-end 2017. Net proved reserve additions from all sources, excluding revisions due to price, replaced 238 percent of EOG's 2018 production at a finding and development cost of $9.33 per barrel of oil equivalent. Revisions due to price increased net proved reserves by 35 MMBoe and asset divestitures decreased net proved reserves by 11 MMBoe. For more reserves detail and a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
For the 31st consecutive year, internal reserves estimates were within five percent of estimates independently prepared by DeGolyer and MacNaughton.
Financial Review
At December 31, 2018, EOG's total debt outstanding was $6.1 billion for a debt-to-total capitalization ratio of 24 percent. Considering cash on the balance sheet at the end of the fourth quarter, EOG's net debt was $4.5 billion for a net debt-to-total capitalization ratio of 19 percent. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
EOG completed its previously announced agreement to divest all of its U.K. operations in the fourth quarter 2018. Proceeds from the U.K. divestment and other asset sales in 2018 totaled $227 million.
Fourth Quarter 2018 Results Webcast
Wednesday, February 27, 2019, 9:00 a.m. Central time (10:00 a.m. Eastern time)
Webcast will be available on EOG website for one year.
http://investors.eogresources.com/Investors
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad, and China. To learn more visit www.eogresources.com .
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
John Wagner 713-571-4404
Media and Investor Contact
Kimberly Ehmer 713-571-4676
This press release may include 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, capital expenditures, 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," "aims," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, generate returns, replace or increase drilling locations, reduce or otherwise control operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness or pay and/or increase 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, this press release and any accompanying disclosures may include or reference certain forward-looking, non-GAAP financial measures, such as free cash flow or discretionary cash flow, and certain related estimates regarding future performance, results and financial position. Any such 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 such measures and estimates. 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 or 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 or resource estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves, "resource potential" and/or other estimated reserves or estimated resources 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, 2018, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
EOG RESOURCES, INC. |
|||||||||||
Financial Report |
|||||||||||
(Unaudited; in millions, except per share data) |
|||||||||||
Three Months Ended |
Twelve Months Ended |
||||||||||
December 31, |
December 31, |
||||||||||
2018 |
2017 |
2018 |
2017 |
||||||||
Operating Revenues and Other |
$ |
4,574.5 |
$ |
3,340.4 |
$ |
17,275.4 |
$ |
11,208.3 |
|||
Net Income |
$ |
892.8 |
$ |
2,430.5 |
$ |
3,419.0 |
$ |
2,582.6 |
|||
Net Income Per Share |
|||||||||||
Basic |
$ |
1.55 |
$ |
4.22 |
$ |
5.93 |
$ |
4.49 |
|||
Diluted |
$ |
1.54 |
$ |
4.20 |
$ |
5.89 |
$ |
4.46 |
|||
Average Number of Common Shares |
|||||||||||
Basic |
577.0 |
575.4 |
576.6 |
574.6 |
|||||||
Diluted |
580.3 |
579.2 |
580.4 |
578.7 |
|||||||
Summary Income Statements |
|||||||||||
(Unaudited; in thousands, except per share data) |
|||||||||||
Three Months Ended |
Twelve Months Ended |
||||||||||
December 31, |
December 31, |
||||||||||
2018 |
2017 |
2018 |
2017 |
||||||||
Operating Revenues and Other |
|||||||||||
Crude Oil and Condensate |
$ |
2,383,326 |
$ |
1,929,471 |
$ |
9,517,440 |
$ |
6,256,396 |
|||
Natural Gas Liquids |
266,037 |
249,172 |
1,127,510 |
729,561 |
|||||||
Natural Gas |
389,213 |
246,922 |
1,301,537 |
921,934 |
|||||||
Gains (Losses) on Mark-to-Market Commodity |
132,095 |
(45,032) |
(165,640) |
19,828 |
|||||||
Gathering, Processing and Marketing |
1,331,105 |
1,008,385 |
5,230,355 |
3,298,087 |
|||||||
Gains (Losses) on Asset Dispositions, Net |
79,904 |
(65,220) |
174,562 |
(99,096) |
|||||||
Other, Net |
(7,144) |
16,741 |
89,635 |
81,610 |
|||||||
Total |
4,574,536 |
3,340,439 |
17,275,399 |
11,208,320 |
|||||||
Operating Expenses |
|||||||||||
Lease and Well |
346,442 |
281,941 |
1,282,678 |
1,044,847 |
|||||||
Transportation Costs |
196,095 |
191,717 |
746,876 |
740,352 |
|||||||
Gathering and Processing Costs |
112,396 |
43,295 |
436,973 |
148,775 |
|||||||
Exploration Costs |
33,862 |
22,941 |
148,999 |
145,342 |
|||||||
Dry Hole Costs |
145 |
4,532 |
5,405 |
4,609 |
|||||||
Impairments |
186,087 |
153,442 |
347,021 |
479,240 |
|||||||
Marketing Costs |
1,349,416 |
1,009,566 |
5,203,243 |
3,330,237 |
|||||||
Depreciation, Depletion and Amortization |
919,963 |
881,745 |
3,435,408 |
3,409,387 |
|||||||
General and Administrative |
116,904 |
117,005 |
426,969 |
434,467 |
|||||||
Taxes Other Than Income |
190,086 |
158,343 |
772,481 |
544,662 |
|||||||
Total |
3,451,396 |
2,864,527 |
12,806,053 |
10,281,918 |
|||||||
Operating Income |
1,123,140 |
475,912 |
4,469,346 |
926,402 |
|||||||
Other Income, Net |
21,220 |
803 |
16,704 |
9,152 |
|||||||
Income Before Interest Expense and Income Taxes |
1,144,360 |
476,715 |
4,486,050 |
935,554 |
|||||||
Interest Expense, Net |
56,020 |
63,362 |
245,052 |
274,372 |
|||||||
Income Before Income Taxes |
1,088,340 |
413,353 |
4,240,998 |
661,182 |
|||||||
Income Tax Provision (Benefit) |
195,572 |
(2,017,115) |
821,958 |
(1,921,397) |
|||||||
Net Income |
$ |
892,768 |
$ |
2,430,468 |
$ |
3,419,040 |
$ |
2,582,579 |
|||
Dividends Declared per Common Share |
$ |
0.2200 |
$ |
0.1675 |
$ |
0.8100 |
$ |
0.6700 |
|||
EOG RESOURCES, INC. |
|||||||||||
Operating Highlights |
|||||||||||
(Unaudited) |
|||||||||||
Three Months Ended |
Twelve Months Ended |
||||||||||
December 31, |
December 31, |
||||||||||
2018 |
2017 |
2018 |
2017 |
||||||||
Wellhead Volumes and Prices |
|||||||||||
Crude Oil and Condensate Volumes (MBbld) (A) |
|||||||||||
United States |
430.3 |
366.9 |
394.8 |
335.0 |
|||||||
Trinidad |
0.8 |
1.1 |
0.8 |
0.9 |
|||||||
Other International (B) |
4.5 |
0.1 |
4.3 |
0.8 |
|||||||
Total |
435.6 |
368.1 |
399.9 |
336.7 |
|||||||
Average Crude Oil and Condensate Prices ($/Bbl) (C) |
|||||||||||
United States |
$ |
59.37 |
$ |
56.95 |
$ |
65.16 |
$ |
50.91 |
|||
Trinidad |
51.80 |
46.56 |
57.26 |
42.30 |
|||||||
Other International (B) |
70.44 |
45.72 |
71.45 |
57.20 |
|||||||
Composite |
59.47 |
56.97 |
65.21 |
50.91 |
|||||||
Natural Gas Liquids Volumes (MBbld) (A) |
|||||||||||
United States |
122.8 |
100.6 |
116.1 |
88.4 |
|||||||
Other International (B) |
- |
- |
- |
- |
|||||||
Total |
122.8 |
100.6 |
116.1 |
88.4 |
|||||||
Average Natural Gas Liquids Prices ($/Bbl) (C) |
|||||||||||
United States |
$ |
23.54 |
$ |
26.92 |
$ |
26.60 |
$ |
22.61 |
|||
Other International (B) |
- |
- |
- |
- |
|||||||
Composite |
23.54 |
26.92 |
26.60 |
22.61 |
|||||||
Natural Gas Volumes (MMcfd) (A) |
|||||||||||
United States |
974 |
829 |
923 |
765 |
|||||||
Trinidad |
230 |
299 |
266 |
313 |
|||||||
Other International (B) |
32 |
32 |
30 |
25 |
|||||||
Total |
1,236 |
1,160 |
1,219 |
1,103 |
|||||||
Average Natural Gas Prices ($/Mcf) (C) |
|||||||||||
United States |
$ |
3.50 |
$ |
2.17 |
$ |
2.88 |
$ |
2.20 |
|||
Trinidad |
3.03 |
2.52 |
2.94 |
2.38 |
|||||||
Other International (B) |
4.02 |
4.23 |
4.08 |
3.89 |
|||||||
Composite |
3.42 |
(D) |
2.31 |
2.92 |
(D) |
2.29 |
|||||
Crude Oil Equivalent Volumes (MBoed) (E) |
|||||||||||
United States |
715.5 |
605.6 |
664.7 |
551.0 |
|||||||
Trinidad |
39.0 |
51.0 |
45.1 |
53.0 |
|||||||
Other International (B) |
10.0 |
5.4 |
9.4 |
4.9 |
|||||||
Total |
764.5 |
662.0 |
719.2 |
608.9 |
|||||||
Total MMBoe (E) |
70.3 |
60.9 |
262.5 |
222.3 |
(A) Thousand barrels per day or million cubic feet per day, as applicable. |
|||||||||||
(B) Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018. |
|||||||||||
(C) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 12 to the Consolidated Financial Statements in EOG's Annual Report on Form 10-K for the year ended December 31, 2018). |
|||||||||||
(D) Includes positive revenue adjustments of $0.49 per Mcf and $0.44 per Mcf for the three and twelve months ended December 31, 2018, respectively, related to the adoption of ASU 2014-09, "Revenue From Contracts with Customers" (ASU 2014-09). (see Note 1 to the Consolidated Financial Statements in EOG's Annual Report on Form 10-K for the year ended December 31, 2018). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees for certain processing and marketing agreements as Gathering and Processing Costs, instead of as a deduction to Natural Gas Revenues. |
|||||||||||
(E) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs 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, |
||||
2018 |
2017 |
||||
ASSETS |
|||||
Current Assets |
|||||
Cash and Cash Equivalents |
$ |
1,555,634 |
$ |
834,228 |
|
Accounts Receivable, Net |
1,915,215 |
1,597,494 |
|||
Inventories |
859,359 |
483,865 |
|||
Assets from Price Risk Management Activities |
23,806 |
7,699 |
|||
Income Taxes Receivable |
427,909 |
113,357 |
|||
Other |
275,467 |
242,465 |
|||
Total |
5,057,390 |
3,279,108 |
|||
Property, Plant and Equipment |
|||||
Oil and Gas Properties (Successful Efforts Method) |
57,330,016 |
52,555,741 |
|||
Other Property, Plant and Equipment |
4,220,665 |
3,960,759 |
|||
Total Property, Plant and Equipment |
61,550,681 |
56,516,500 |
|||
Less: Accumulated Depreciation, Depletion and Amortization |
(33,475,162) |
(30,851,463) |
|||
Total Property, Plant and Equipment, Net |
28,075,519 |
25,665,037 |
|||
Deferred Income Taxes |
777 |
17,506 |
|||
Other Assets |
800,788 |
871,427 |
|||
Total Assets |
$ |
33,934,474 |
$ |
29,833,078 |
|
LIABILITIES AND STOCKHOLDERS' EQUITY |
|||||
Current Liabilities |
|||||
Accounts Payable |
$ |
2,239,850 |
$ |
1,847,131 |
|
Accrued Taxes Payable |
214,726 |
148,874 |
|||
Dividends Payable |
126,971 |
96,410 |
|||
Liabilities from Price Risk Management Activities |
- |
50,429 |
|||
Current Portion of Long-Term Debt |
913,093 |
356,235 |
|||
Other |
233,724 |
226,463 |
|||
Total |
3,728,364 |
2,725,542 |
|||
Long-Term Debt |
5,170,169 |
6,030,836 |
|||
Other Liabilities |
1,258,355 |
1,275,213 |
|||
Deferred Income Taxes |
4,413,398 |
3,518,214 |
|||
Commitments and Contingencies |
|||||
Stockholders' Equity |
|||||
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and |
205,804 |
205,788 |
|||
Additional Paid in Capital |
5,658,794 |
5,536,547 |
|||
Accumulated Other Comprehensive Loss |
(1,358) |
(19,297) |
|||
Retained Earnings |
13,543,130 |
10,593,533 |
|||
Common Stock Held in Treasury, 385,042 Shares and 350,961 Shares at |
(42,182) |
(33,298) |
|||
Total Stockholders' Equity |
19,364,188 |
16,283,273 |
|||
Total Liabilities and Stockholders' Equity |
$ |
33,934,474 |
$ |
29,833,078 |
EOG RESOURCES, INC. |
|||||
Summary Statements of Cash Flows |
|||||
(Unaudited; in thousands) |
|||||
Twelve Months Ended |
|||||
December 31, |
|||||
2018 |
2017 |
||||
Cash Flows from Operating Activities |
|||||
Reconciliation of Net Income to Net Cash Provided by Operating Activities: |
|||||
Net Income |
$ |
3,419,040 |
$ |
2,582,579 |
|
Items Not Requiring (Providing) Cash |
|||||
Depreciation, Depletion and Amortization |
3,435,408 |
3,409,387 |
|||
Impairments |
347,021 |
479,240 |
|||
Stock-Based Compensation Expenses |
155,337 |
133,849 |
|||
Deferred Income Taxes |
894,156 |
(1,473,872) |
|||
(Gains) Losses on Asset Dispositions, Net |
(174,562) |
99,096 |
|||
Other, Net |
7,066 |
6,546 |
|||
Dry Hole Costs |
5,405 |
4,609 |
|||
Mark-to-Market Commodity Derivative Contracts |
|||||
Total (Gains) Losses |
165,640 |
(19,828) |
|||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts |
(258,906) |
7,438 |
|||
Other, Net |
3,108 |
1,204 |
|||
Changes in Components of Working Capital and Other Assets and Liabilities |
|||||
Accounts Receivable |
(368,180) |
(392,131) |
|||
Inventories |
(395,408) |
(174,548) |
|||
Accounts Payable |
439,347 |
324,192 |
|||
Accrued Taxes Payable |
(92,461) |
(63,937) |
|||
Other Assets |
(125,435) |
(658,609) |
|||
Other Liabilities |
10,949 |
(89,871) |
|||
Changes in Components of Working Capital Associated with Investing and Financing |
301,083 |
89,992 |
|||
Net Cash Provided by Operating Activities |
7,768,608 |
4,265,336 |
|||
Investing Cash Flows |
|||||
Additions to Oil and Gas Properties |
(5,839,294) |
(3,950,918) |
|||
Additions to Other Property, Plant and Equipment |
(237,181) |
(173,324) |
|||
Proceeds from Sales of Assets |
227,446 |
226,768 |
|||
Other Investing Activities |
(19,993) |
- |
|||
Changes in Components of Working Capital Associated with Investing Activities |
(301,140) |
(89,935) |
|||
Net Cash Used in Investing Activities |
(6,170,162) |
(3,987,409) |
|||
Financing Cash Flows |
|||||
Long-Term Debt Repayments |
(350,000) |
(600,000) |
|||
Dividends Paid |
(438,045) |
(386,531) |
|||
Treasury Stock Purchased |
(63,456) |
(63,408) |
|||
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan |
20,560 |
20,840 |
|||
Repayment of Capital Lease Obligation |
(8,219) |
(6,555) |
|||
Changes in Components of Working Capital Associated with Financing Activities |
57 |
(57) |
|||
Net Cash Used in Financing Activities |
(839,103) |
(1,035,711) |
|||
Effect of Exchange Rate Changes on Cash |
(37,937) |
(7,883) |
|||
Increase (Decrease) in Cash and Cash Equivalents |
721,406 |
(765,667) |
|||
Cash and Cash Equivalents at Beginning of Period |
834,228 |
1,599,895 |
|||
Cash and Cash Equivalents at End of Period |
$ |
1,555,634 |
$ |
834,228 |
EOG RESOURCES, INC. |
|||||||||||||
Fourth Quarter 2018 Well Results by Play |
|||||||||||||
(Unaudited) |
|||||||||||||
Wells Online |
Initial Gross 30-Day Average Production Rate |
||||||||||||
Gross |
Net |
Lateral |
Crude Oil and |
Natural Gas |
Natural Gas |
Crude Oil |
|||||||
Delaware Basin |
|||||||||||||
Wolfcamp |
42 |
37 |
7,000 |
1,950 |
600 |
3.7 |
3,150 |
||||||
Bone Spring |
13 |
11 |
5,300 |
1,550 |
300 |
1.9 |
2,150 |
||||||
Leonard |
2 |
1 |
4,600 |
1,200 |
550 |
3.7 |
2,350 |
||||||
South Texas Eagle Ford |
82 |
78 |
7,300 |
1,300 |
150 |
0.8 |
1,600 |
||||||
South Texas Austin Chalk |
6 |
5 |
5,500 |
2,650 |
550 |
2.6 |
3,650 |
||||||
Powder River Basin |
|||||||||||||
Turner |
4 |
3 |
9,700 |
800 |
200 |
2.4 |
1,400 |
||||||
Mowry |
2 |
2 |
9,200 |
700 |
450 |
5.5 |
2,050 |
||||||
DJ Basin Codell |
20 |
10 |
9,600 |
700 |
50 |
0.3 |
800 |
||||||
Williston Basin Bakken/Three Forks |
7 |
5 |
10,100 |
550 |
25 |
0.1 |
600 |
||||||
Anadarko Basin Woodford Oil Window |
5 |
4 |
9,200 |
600 |
75 |
0.4 |
750 |
(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. |
EOG RESOURCES, INC. |
|||||||||||||||
Quantitative Reconciliation of Adjusted Net Income (Non-GAAP) |
|||||||||||||||
To Net Income (GAAP) |
|||||||||||||||
(Unaudited; in thousands, except per share data) |
|||||||||||||||
The following chart adjusts the three-month and twelve-month periods ended December 31, 2018 and 2017 reported Net Income (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 2018 and 2017, to add back impairment charges related to certain of EOG's assets in 2018 and 2017, 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 certain joint interest billings deemed uncollectible in 2017 and to eliminate certain adjustments in 2018 and 2017 related to the 2017 U.S. tax reform. 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 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 |
Three Months Ended |
||||||||||||||
December 31, 2018 |
December 31, 2017 |
||||||||||||||
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 (GAAP) |
$ 1,088,340 |
$ (195,572) |
$ 892,768 |
$ 1.54 |
$ 413,353 |
$ 2,017,115 |
$ 2,430,468 |
$ 4.20 |
|||||||
Adjustments: |
|||||||||||||||
(Gains) Losses on Mark-to-Market Commodity |
(132,095) |
29,096 |
(102,999) |
(0.18) |
45,032 |
(16,142) |
28,890 |
0.05 |
|||||||
Net Cash Received from (Payments for) |
(78,678) |
17,330 |
(61,348) |
(0.11) |
2,708 |
(971) |
1,737 |
- |
|||||||
Add: Net (Gains) Losses on Asset Dispositions |
(79,904) |
13,625 |
(66,279) |
(0.11) |
65,220 |
(23,315) |
41,905 |
0.07 |
|||||||
Add: Impairments |
131,795 |
(29,031) |
102,764 |
0.18 |
100,304 |
(35,954) |
64,350 |
0.11 |
|||||||
Add: Joint Interest Billings Deemed Uncollectible |
- |
- |
- |
- |
4,528 |
(1,623) |
2,905 |
0.01 |
|||||||
Less: Tax Reform Impact |
- |
(46,684) |
(46,684) |
(0.08) |
- |
(2,169,376) |
(2,169,376) |
(3.75) |
|||||||
Adjustments to Net Income |
(158,882) |
(15,664) |
(174,546) |
(0.30) |
217,792 |
(2,247,381) |
(2,029,589) |
(3.51) |
|||||||
Adjusted Net Income (Non-GAAP) |
$ 929,458 |
$ (211,236) |
$ 718,222 |
$ 1.24 |
$ 631,145 |
$ (230,266) |
$ 400,879 |
$ 0.69 |
|||||||
Average Number of Common Shares (GAAP) |
|||||||||||||||
Basic |
577,035 |
575,394 |
|||||||||||||
Diluted |
580,288 |
579,203 |
|||||||||||||
Twelve Months Ended |
Twelve Months Ended |
||||||||||||||
December 31, 2018 |
December 31, 2017 |
||||||||||||||
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 (GAAP) |
$ 4,240,998 |
$ (821,958) |
$ 3,419,040 |
$ 5.89 |
$ 661,182 |
$ 1,921,397 |
$ 2,582,579 |
$ 4.46 |
|||||||
Adjustments: |
|||||||||||||||
(Gains) Losses on Mark-to-Market Commodity |
165,640 |
(36,486) |
129,154 |
0.22 |
(19,828) |
7,107 |
(12,721) |
(0.02) |
|||||||
Net Cash Received from (Payments for) |
(258,906) |
57,029 |
(201,877) |
(0.35) |
7,438 |
(2,666) |
4,772 |
0.01 |
|||||||
Add: Net (Gains) Losses on Asset Dispositions |
(174,562) |
37,860 |
(136,702) |
(0.24) |
99,096 |
(35,270) |
63,826 |
0.11 |
|||||||
Add: Impairments |
152,671 |
(33,629) |
119,042 |
0.21 |
261,452 |
(93,718) |
167,734 |
0.29 |
|||||||
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 |
- |
(110,335) |
(110,335) |
(0.19) |
- |
(2,169,376) |
(2,169,376) |
(3.75) |
|||||||
Adjustments to Net Income |
(115,157) |
(85,561) |
(200,718) |
(0.35) |
365,944 |
(2,300,298) |
(1,934,354) |
(3.34) |
|||||||
Adjusted Net Income (Non-GAAP) |
$ 4,125,841 |
$ (907,519) |
$ 3,218,322 |
$ 5.54 |
$ 1,027,126 |
$ (378,901) |
$ 648,225 |
$ 1.12 |
|||||||
Average Number of Common Shares (GAAP) |
|||||||||||||||
Basic |
576,578 |
574,620 |
|||||||||||||
Diluted |
580,441 |
578,693 |
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, 2018 and 2017 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), Other Non-Current Income Taxes - Net Receivable (Payable), 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 three months and twelve months ended December 31, 2018. EOG management uses this information for comparative purposes within the industry. |
|||||||||||
Three Months Ended |
Twelve Months Ended |
||||||||||
December 31, |
December 31, |
||||||||||
2018 |
2017 |
2018 |
2017 |
||||||||
Net Cash Provided by Operating Activities (GAAP) |
$ |
2,085,228 |
$ |
1,327,548 |
$ |
7,768,608 |
$ |
4,265,336 |
|||
Adjustments: |
|||||||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) |
27,270 |
16,420 |
123,986 |
122,688 |
|||||||
Other Non-Current Income Taxes - Net Receivable (Payable) |
86,572 |
(513,404) |
148,993 |
(513,404) |
|||||||
Changes in Components of Working Capital and Other Assets |
|||||||||||
and Liabilities |
|||||||||||
Accounts Receivable |
(185,349) |
366,686 |
368,180 |
392,131 |
|||||||
Inventories |
108,591 |
156,874 |
395,408 |
174,548 |
|||||||
Accounts Payable |
98,178 |
(211,298) |
(439,347) |
(324,192) |
|||||||
Accrued Taxes Payable |
55,570 |
13,970 |
92,461 |
63,937 |
|||||||
Other Assets |
22,101 |
574,669 |
125,435 |
658,609 |
|||||||
Other Liabilities |
(25,725) |
20,647 |
(10,949) |
89,871 |
|||||||
Changes in Components of Working Capital Associated with |
|||||||||||
Investing and Financing Activities |
(205,599) |
(210,365) |
(301,083) |
(89,992) |
|||||||
Discretionary Cash Flow (Non-GAAP) |
$ |
2,066,837 |
$ |
1,541,747 |
$ |
8,271,692 |
$ |
4,839,532 |
|||
Discretionary Cash Flow (Non-GAAP) - Percentage Increase |
34% |
71% |
|||||||||
Discretionary Cash Flow (Non-GAAP) |
$ |
2,066,837 |
$ |
8,271,692 |
|||||||
Less: |
|||||||||||
Total Cash Expenditures Excluding Acquisitions (Non-GAAP)(a) |
(1,302,999) |
(6,172,950) |
|||||||||
Dividends Paid (GAAP) |
(126,970) |
(438,045) |
|||||||||
Free Cash Flow (Non-GAAP) |
$ |
636,868 |
$ |
1,660,697 |
|||||||
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Expenditures Excluding Acquisitions (Non-GAAP) for the three months and twelve months ended December 31, 2018: |
|||||||||||
Total Expenditures (GAAP) |
$ |
1,504,438 |
$ |
6,706,359 |
|||||||
Less: |
|||||||||||
Asset Retirement Costs |
(27,910) |
(69,699) |
|||||||||
Non-Cash Expenditures of Other Property, Plant and Equipment |
(547) |
(49,484) |
|||||||||
Non-Cash Acquisition Costs of Unproved Properties |
(128,719) |
(290,542) |
|||||||||
Acquisition Costs of Proved Properties |
(44,263) |
(123,684) |
|||||||||
Total Cash Expenditures Excluding Acquisitions (Non-GAAP) |
$ |
1,302,999 |
$ |
6,172,950 |
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 (GAAP) |
|||||||||||
(Unaudited; in thousands) |
|||||||||||
The following chart adjusts the three-month and twelve-month periods ended December 31, 2018 and 2017 reported Net Income (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 (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 (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, |
||||||||||
2018 |
2017 |
2018 |
2017 |
||||||||
Net Income (GAAP) |
$ |
892,768 |
$ |
2,430,468 |
$ |
3,419,040 |
$ |
2,582,579 |
|||
Adjustments: |
|||||||||||
Interest Expense, Net |
56,020 |
63,362 |
245,052 |
274,372 |
|||||||
Income Tax Provision (Benefit) |
195,572 |
(2,017,115) |
821,958 |
(1,921,397) |
|||||||
Depreciation, Depletion and Amortization |
919,963 |
881,745 |
3,435,408 |
3,409,387 |
|||||||
Exploration Costs |
33,862 |
22,941 |
148,999 |
145,342 |
|||||||
Dry Hole Costs |
145 |
4,532 |
5,405 |
4,609 |
|||||||
Impairments |
186,087 |
153,442 |
347,021 |
479,240 |
|||||||
EBITDAX (Non-GAAP) |
2,284,417 |
1,539,375 |
8,422,883 |
4,974,132 |
|||||||
Total (Gains) Losses on MTM Commodity Derivative Contracts |
(132,095) |
45,032 |
165,640 |
(19,828) |
|||||||
Net Cash Received from (Payments for) Settlements of Commodity |
(78,678) |
2,708 |
(258,906) |
7,438 |
|||||||
(Gains) Losses on Asset Dispositions, Net |
(79,904) |
65,220 |
(174,562) |
99,096 |
|||||||
Adjusted EBITDAX (Non-GAAP) |
$ |
1,993,740 |
$ |
1,652,335 |
$ |
8,155,055 |
$ |
5,060,838 |
|||
Adjusted EBITDAX (Non-GAAP) - Percentage Increase |
21% |
61% |
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, |
||||
2018 |
2017 |
||||
Total Stockholders' Equity - (a) |
$ |
19,364 |
$ |
16,283 |
|
Current and Long-Term Debt (GAAP) - (b) |
6,083 |
6,387 |
|||
Less: Cash |
(1,556) |
(834) |
|||
Net Debt (Non-GAAP) - (c) |
4,527 |
5,553 |
|||
Total Capitalization (GAAP) - (a) + (b) |
$ |
25,447 |
$ |
22,670 |
|
Total Capitalization (Non-GAAP) - (a) + (c) |
$ |
23,891 |
$ |
21,836 |
|
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] |
24% |
28% |
|||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] |
19% |
25% |
EOG RESOURCES, INC. |
|||||||
Reserves Supplemental Data |
|||||||
(Unaudited) |
|||||||
2018 NET PROVED RESERVES RECONCILIATION SUMMARY |
|||||||
United |
Other |
||||||
States |
Trinidad |
International |
Total |
||||
CRUDE OIL AND CONDENSATE (MMBbl) |
|||||||
Beginning Reserves |
1,304.1 |
0.9 |
8.0 |
1,313.0 |
|||
Revisions |
(13.2) |
(0.2) |
- |
(13.4) |
|||
Purchases in Place |
2.7 |
- |
- |
2.7 |
|||
Extensions, Discoveries and Other Additions |
383.0 |
- |
- |
383.0 |
|||
Sales in Place |
(0.8) |
- |
(6.3) |
(7.1) |
|||
Production |
(144.1) |
(0.3) |
(1.5) |
(145.9) |
|||
Ending Reserves |
1,531.7 |
0.4 |
0.2 |
1,532.3 |
|||
NATURAL GAS LIQUIDS (MMBbl) |
|||||||
Beginning Reserves |
503.5 |
- |
- |
503.5 |
|||
Revisions |
23.9 |
- |
- |
23.9 |
|||
Purchases in Place |
2.0 |
- |
- |
2.0 |
|||
Extensions, Discoveries and Other Additions |
127.4 |
- |
- |
127.4 |
|||
Sales in Place |
- |
- |
- |
- |
|||
Production |
(42.5) |
- |
- |
(42.5) |
|||
Ending Reserves |
614.3 |
- |
- |
614.3 |
|||
NATURAL GAS (Bcf) |
|||||||
Beginning Reserves |
3,898.5 |
313.4 |
51.2 |
4,263.1 |
|||
Revisions |
(127.2) |
20.7 |
15.0 |
(91.5) |
|||
Purchases in Place |
41.3 |
- |
- |
41.3 |
|||
Extensions, Discoveries and Other Additions |
951.4 |
- |
4.6 |
956.0 |
|||
Sales in Place |
(22.2) |
- |
- |
(22.2) |
|||
Production |
(351.2) |
(97.1) |
(11.2) |
(459.5) |
|||
Ending Reserves |
4,390.6 |
237.0 |
59.6 |
4,687.2 |
|||
OIL EQUIVALENTS (MMBoe) |
|||||||
Beginning Reserves |
2,457.3 |
53.1 |
16.6 |
2,527.0 |
|||
Revisions |
(10.5) |
3.3 |
2.5 |
(4.7) |
|||
Purchases in Place |
11.6 |
- |
- |
11.6 |
|||
Extensions, Discoveries and Other Additions |
669.0 |
- |
0.7 |
669.7 |
|||
Sales in Place |
(4.5) |
- |
(6.3) |
(10.8) |
|||
Production |
(245.1) |
(16.5) |
(3.4) |
(265.0) |
|||
Ending Reserves |
2,877.8 |
39.9 |
10.1 |
2,927.8 |
|||
Net Proved Developed Reserves (MMBoe) |
|||||||
At December 31, 2017 |
1,300.7 |
50.8 |
12.8 |
1,364.3 |
|||
At December 31, 2018 |
1,503.4 |
37.7 |
7.0 |
1,548.1 |
|||
2018 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ Millions) |
|||||||
United |
Other |
||||||
States |
Trinidad |
International |
Total |
||||
Acquisition Cost of Unproved Properties |
$ 486.0 |
$ 1.3 |
$ - |
$ 487.3 |
|||
Exploration Costs |
157.2 |
22.5 |
13.9 |
193.6 |
|||
Development Costs |
5,515.4 |
(0.8) |
30.8 |
5,545.4 |
|||
Total Drilling |
6,158.6 |
23.0 |
44.7 |
6,226.3 |
|||
Acquisition Cost of Proved Properties |
123.7 |
- |
- |
123.7 |
|||
Asset Retirement Costs |
90.0 |
(12.1) |
(8.2) |
69.7 |
|||
Total Exploration and Development Expenditures |
6,372.3 |
10.9 |
36.5 |
6,419.7 |
|||
Gathering, Processing and Other |
286.0 |
0.4 |
0.3 |
286.7 |
|||
Total Expenditures |
6,658.3 |
11.3 |
36.8 |
6,706.4 |
|||
Proceeds from Sales in Place |
(53.3) |
- |
(174.1) |
(227.4) |
|||
Net Expenditures |
$ 6,605.0 |
$ 11.3 |
$ (137.3) |
$ 6,479.0 |
|||
RESERVE REPLACEMENT COSTS ($ / Boe ) * |
|||||||
All-in Total, Net of Revisions |
$ 8.84 |
$ 6.97 |
$ 13.97 |
$ 8.85 |
|||
All-in Total, Excluding Revisions Due to Price |
$ 9.32 |
$ 6.97 |
$ 13.97 |
$ 9.33 |
|||
RESERVE REPLACEMENT * |
|||||||
Drilling Only |
273% |
0% |
21% |
253% |
|||
All-in Total, Net of Revisions and Dispositions |
272% |
20% |
-91% |
251% |
|||
All-in Total, Excluding Revisions Due to Price |
257% |
20% |
-91% |
238% |
|||
All-in Total, Liquids |
281% |
-67% |
-420% |
275% |
|||
* 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 data) |
|||||||
The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) and 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 "Drilling Only" and "All-In", which reflect total exploration and development expenditures divided by total net proved reserve additions from extensions and discoveries only, or 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, 2018 |
|||||||
United |
Other |
||||||
States |
Trinidad |
International |
Total |
||||
Total Costs Incurred in Exploration and Development Activities (GAAP) |
$ 6,372.3 |
$ 10.9 |
$ 36.5 |
$ 6,419.7 |
|||
Less: Asset Retirement Costs |
(90.0) |
12.1 |
8.2 |
(69.7) |
|||
Non-Cash Acquisition Costs of Unproved Properties |
(290.5) |
- |
- |
(290.5) |
|||
Total Acquisition Costs of Proved Properties |
(123.7) |
- |
- |
(123.7) |
|||
Total Exploration and Development Expenditures (Non-GAAP) (a) |
$ 5,868.1 |
$ 23.0 |
$ 44.7 |
$ 5,935.8 |
|||
Total Costs Incurred in Exploration and Development Activities (GAAP) |
$ 6,372.3 |
$ 10.9 |
$ 36.5 |
$ 6,419.7 |
|||
Less: Asset Retirement Costs |
(90.0) |
12.1 |
8.2 |
(69.7) |
|||
Non-Cash Acquisition Costs of Unproved Properties |
(290.5) |
- |
- |
(290.5) |
|||
Non-Cash Acquisition Costs of Proved Properties |
(70.9) |
- |
- |
(70.9) |
|||
Total Exploration and Development Expenditures (Non-GAAP) (b) |
$ 5,920.9 |
$ 23.0 |
$ 44.7 |
$ 5,988.6 |
|||
Total Expenditures (GAAP) |
$ 6,658.3 |
$ 11.3 |
$ 36.8 |
$ 6,706.4 |
|||
Less: Asset Retirement Costs |
(90.0) |
12.1 |
8.2 |
(69.7) |
|||
Non-Cash Acquisition Costs of Unproved Properties |
(290.5) |
- |
- |
(290.5) |
|||
Non-Cash Acquisition Costs of Proved Properties |
(70.9) |
- |
- |
(70.9) |
|||
Non-Cash Capital - Other Miscellaneous |
(49.5) |
- |
- |
(49.5) |
|||
Total Cash Expenditures (Non-GAAP) |
$ 6,157.4 |
$ 23.4 |
$ 45.0 |
$ 6,225.8 |
|||
Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe) |
|||||||
Revisions Due to Price (c) |
34.8 |
- |
- |
34.8 |
|||
Revisions Other Than Price |
(45.3) |
3.3 |
2.5 |
(39.5) |
|||
Purchases in Place |
11.6 |
- |
- |
11.6 |
|||
Extensions, Discoveries and Other Additions (d) |
669.0 |
- |
0.7 |
669.7 |
|||
Total Proved Reserve Additions (e) |
670.1 |
3.3 |
3.2 |
676.6 |
|||
Sales in Place |
(4.5) |
- |
(6.3) |
(10.8) |
|||
Net Proved Reserve Additions From All Sources (f) |
665.6 |
3.3 |
(3.1) |
665.8 |
|||
Production (g) |
245.1 |
16.5 |
3.4 |
265.0 |
|||
RESERVE REPLACEMENT COSTS ($ / Boe) |
|||||||
Total Drilling, Before Revisions (a / d) |
$ 8.77 |
$ - |
$ 63.86 |
$ 8.86 |
|||
All-in Total, Net of Revisions (b / e) |
$ 8.84 |
$ 6.97 |
$ 13.97 |
$ 8.85 |
|||
All-in Total, Excluding Revisions Due to Price (b / (e - c)) |
$ 9.32 |
$ 6.97 |
$ 13.97 |
$ 9.33 |
|||
RESERVE REPLACEMENT |
|||||||
Drilling Only (d / g) |
273% |
0% |
21% |
253% |
|||
All-in Total, Net of Revisions and Dispositions (f / g) |
272% |
20% |
-91% |
251% |
|||
All-in Total, Excluding Revisions Due to Price ((f - c ) / g) |
257% |
20% |
-91% |
238% |
|||
Net Proved Reserve Additions From All Sources - Liquids (MMBbl) |
|||||||
Revisions |
10.7 |
(0.2) |
- |
10.5 |
|||
Purchases in Place |
4.7 |
- |
- |
4.7 |
|||
Extensions, Discoveries and Other Additions (h) |
510.4 |
- |
- |
510.4 |
|||
Total Proved Reserve Additions |
525.8 |
(0.2) |
- |
525.6 |
|||
Sales in Place |
(0.8) |
- |
(6.3) |
(7.1) |
|||
Net Proved Reserve Additions From All Sources (i) |
525.0 |
(0.2) |
(6.3) |
518.5 |
|||
Production (j) |
186.6 |
0.3 |
1.5 |
188.4 |
|||
RESERVE REPLACEMENT - LIQUIDS |
|||||||
Drilling Only (h / j) |
274% |
0% |
0% |
271% |
|||
All-in Total, Net of Revisions and Dispositions (i / j) |
281% |
-67% |
-420% |
275% |
|||
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 data) |
|||||||
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, 2018 |
|||||||
Total |
|||||||
PROVED DEVELOPED RESERVE REPLACEMENT COSTS ($ / Boe) |
|||||||
Total Costs Incurred in Exploration and Development Activities (GAAP) |
$ 6,419.7 |
||||||
Less: Asset Retirement Costs |
(69.7) |
||||||
Acquisition Costs of Unproved Properties |
(487.3) |
||||||
Acquisition Costs of Proved Properties |
(123.7) |
||||||
Drillbit Exploration and Development Expenditures (Non-GAAP) (j) |
$ 5,739.0 |
||||||
Total Proved Reserves - Extensions, Discoveries and Other Additions (MMBoe) |
669.7 |
||||||
Add: Conversion of Proved Undeveloped Reserves to Proved Developed |
265.7 |
||||||
Less: Proved Undeveloped Extensions and Discoveries |
(490.7) |
||||||
Proved Developed Reserves - Extensions and Discoveries (MMBoe) |
444.7 |
||||||
Total Proved Reserves - Revisions (MMBoe) |
(4.7) |
||||||
Less: Proved Undeveloped Reserves - Revisions |
8.2 |
||||||
Proved Developed - Revisions Due to Price |
(31.8) |
||||||
Proved Developed Reserves - Revisions Other Than Price (MMBoe) |
(28.3) |
||||||
Proved Developed Reserves - Extensions and Discoveries plus Revisions Other than Price (MMBoe) (k) |
416.4 |
||||||
Proved Developed Reserve Replacement Cost Excluding Revisions Due to Price ($ / Boe) (j / k) |
$ 13.78 |
EOG RESOURCES, INC. |
|||||||||
Quantitative Reconciliation of Total Exploration and Development Expenditures |
|||||||||
For Drilling Only (Non-GAAP) and 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 data) |
|||||||||
The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) and 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 "Drilling Only" and "All-In", which reflect total exploration and development expenditures divided by total net proved reserve additions from extensions and discoveries only, or 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. |
|||||||||
2018 |
2017 |
2016 |
2015 |
2014 |
|||||
Total Costs Incurred in Exploration and Development Activities (GAAP) |
$ 6,419.7 |
$ 4,439.4 |
$ 6,445.2 |
$ 4,928.3 |
$ 7,904.8 |
||||
Less: Asset Retirement Costs |
(69.7) |
(55.6) |
19.9 |
(53.5) |
(195.6) |
||||
Non-Cash Acquisition Costs of Unproved Properties |
(290.5) |
(255.7) |
(3,101.8) |
- |
- |
||||
Acquisition Costs of Proved Properties |
(123.7) |
(72.6) |
(749.0) |
(480.6) |
(139.1) |
||||
Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) (a) |
$ 5,935.8 |
$ 4,055.5 |
$ 2,614.3 |
$ 4,394.2 |
$ 7,570.1 |
||||
Total Costs Incurred in Exploration and Development Activities (GAAP) |
$ 6,419.7 |
$ 4,439.4 |
$ 6,445.2 |
$ 4,928.3 |
$ 7,904.8 |
||||
Less: Asset Retirement Costs |
(69.7) |
(55.6) |
19.9 |
(53.5) |
(195.6) |
||||
Non-Cash Acquisition Costs of Unproved Properties |
(290.5) |
(255.7) |
(3,101.8) |
- |
- |
||||
Non-Cash Acquisition Costs of Proved Properties |
(70.9) |
(26.2) |
(732.3) |
- |
- |
||||
Total Exploration and Development Expenditures (Non-GAAP) (b) |
$ 5,988.6 |
$ 4,101.9 |
$ 2,631.0 |
$ 4,874.8 |
$ 7,709.2 |
||||
Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe) |
|||||||||
Revisions Due to Price (c) |
34.8 |
154.0 |
(100.7) |
(573.8) |
52.2 |
||||
Revisions Other Than Price |
(39.5) |
48.0 |
252.9 |
107.2 |
48.4 |
||||
Purchases in Place |
11.6 |
2.3 |
42.3 |
56.2 |
14.4 |
||||
Extensions, Discoveries and Other Additions (d) |
669.7 |
420.8 |
209.0 |
245.9 |
519.2 |
||||
Total Proved Reserve Additions (e) |
676.6 |
625.1 |
403.5 |
(164.5) |
634.2 |
||||
Sales in Place |
(10.8) |
(20.7) |
(167.6) |
(3.5) |
(36.3) |
||||
Net Proved Reserve Additions From All Sources (f) |
665.8 |
604.4 |
235.9 |
(168.0) |
597.9 |
||||
Production (g) |
265.0 |
224.4 |
207.1 |
211.2 |
219.1 |
||||
RESERVE REPLACEMENT COSTS ($ / Boe) |
|||||||||
Total Drilling, Before Revisions (a / d) |
$ 8.86 |
$ 9.64 |
$ 12.51 |
$ 17.87 |
$ 14.58 |
||||
All-in Total, Net of Revisions (b / e) |
$ 8.85 |
$ 6.56 |
$ 6.52 |
$ (29.63) |
$ 12.16 |
||||
All-in Total, Excluding Revisions Due to Price (b / (e - c)) |
$ 9.33 |
$ 8.71 |
$ 5.22 |
$ 11.91 |
$ 13.25 |
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 19, 2019. 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 December 31, 2018 (closed) |
15,000 |
$ 1.063 |
||||||
2019 |
||||||||
January 1, 2019 through February 28, 2019 (closed) |
20,000 |
$ 1.075 |
||||||
March 1, 2019 through December 31, 2019 |
20,000 |
1.075 |
||||||
EOG has also entered into 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 19, 2019. 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 September 30, 2018 (closed) |
37,000 |
$ 3.818 |
||||||
October 1, 2018 through December 31, 2018 (closed) |
52,000 |
3.911 |
||||||
2019 |
||||||||
January 1, 2019 through February 28, 2019 (closed) |
13,000 |
$ 5.572 |
||||||
March 1, 2019 through December 31, 2019 |
13,000 |
5.572 |
||||||
Presented below is a comprehensive summary of EOG's crude oil price swap contracts through February 19, 2019, with notional volumes expressed in Bbld and prices expressed in $/Bbl. |
||||||||
Crude Oil Price Swap Contracts |
||||||||
Weighted |
||||||||
Volume |
Average Price |
|||||||
(Bbld) |
($/Bbl) |
|||||||
2018 |
||||||||
January 1, 2018 through November 30, 2018 (closed) |
134,000 |
$ 60.04 |
||||||
On November 20, 2018, EOG entered into crude oil price swap contracts for the period December 1, 2018 through December 31, 2018, with notional volumes of 134,000 Bbld at an average price of $53.75 per Bbl. These contracts offset the crude oil price swap contracts for the same time period with notional volumes of 134,000 Bbld at an average price of $60.04 per Bbl. The net cash EOG received for settling these contracts was $26.1 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 19, 2019, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. |
||||||||
Natural Gas Price Swap Contracts |
||||||||
Weighted |
||||||||
Volume |
Average Price |
|||||||
(MMBtud) |
($/MMBtu) |
|||||||
2018 |
||||||||
March 1, 2018 through November 30, 2018 (closed) |
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 19, 2019, 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) |
|||||
2018 |
||||||||
March 1, 2018 through November 30, 2018 (closed) |
120,000 |
$ 3.38 |
96,000 |
$ 2.94 |
||||
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 (Non-GAAP), |
||||||||
Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculations of Return on Capital |
||||||||
Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest Expense (GAAP), Net Income |
||||||||
(GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively |
||||||||
(Unaudited; in millions, except ratio data) |
||||||||
The following chart reconciles Net Interest Expense (GAAP), Net Income (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income, Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. |
||||||||
2018 |
2017 |
|||||||
Return on Capital Employed (ROCE) (Non-GAAP) |
||||||||
Net Interest Expense (GAAP) |
$ |
245 |
||||||
Tax Benefit Imputed (based on 21%) |
(51) |
|||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
$ |
194 |
||||||
Net Income (GAAP) - (b) |
$ |
3,419 |
||||||
Adjustments to Net Income, Net of Tax (See Accompanying Schedule) |
(201) |
(1) |
||||||
Adjusted Net Income (Non-GAAP) - (c) |
$ |
3,218 |
||||||
Total Stockholders' Equity - (d) |
$ |
19,364 |
$ |
16,283 |
||||
Average Total Stockholders' Equity * - (e) |
$ |
17,824 |
||||||
Current and Long-Term Debt (GAAP) - (f) |
$ |
6,083 |
$ |
6,387 |
||||
Less: Cash |
(1,556) |
(834) |
||||||
Net Debt (Non-GAAP) - (g) |
$ |
4,527 |
$ |
5,553 |
||||
Total Capitalization (GAAP) - (d) + (f) |
$ |
25,447 |
$ |
22,670 |
||||
Total Capitalization (Non-GAAP) - (d) + (g) |
$ |
23,891 |
$ |
21,836 |
||||
Average Total Capitalization (Non-GAAP) * - (h) |
$ |
22,864 |
||||||
ROCE (GAAP Net Income) - [(a) + (b)] / (h) |
15.8% |
|||||||
ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (h) |
14.9% |
|||||||
Return on Equity (ROE) |
||||||||
ROE (GAAP Net Income) - (b) / (e) |
19.2% |
|||||||
ROE (Non-GAAP Adjusted Net Income) - (c) / (e) |
18.1% |
|||||||
* Average for the current and immediately preceding year |
||||||||
Adjustments to Net Income (GAAP) |
||||||||
(1) See below schedule for detail of adjustments to Net Income (GAAP) in 2018: |
||||||||
Year Ended December 31, 2018 |
||||||||
Before |
Income Tax |
After |
||||||
Tax |
Impact |
Tax |
||||||
Adjustments: |
||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
(93) |
$ |
20 |
$ |
(73) |
||
Add: Impairments of Certain Assets |
153 |
(34) |
119 |
|||||
Less: Net Gains on Asset Dispositions |
(175) |
38 |
(137) |
|||||
Less: Tax Reform Impact |
- |
(110) |
(110) |
|||||
Total |
$ |
(115) |
$ |
(86) |
$ |
(201) |
EOG RESOURCES, INC. |
||||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total |
||||||||||
Capitalization (Non-GAAP) as used in the Calculation of Return on Capital Employed (Non-GAAP) to Net Interest |
||||||||||
Expense (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), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. 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) |
||||||||||
(Calculated Using GAAP Net Income) |
||||||||||
Net Interest Expense (GAAP) |
$ |
274 |
$ |
282 |
$ |
237 |
$ |
201 |
$ |
235 |
Tax Benefit Imputed (based on 35%) |
(96) |
(99) |
(83) |
(70) |
(82) |
|||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
$ |
178 |
$ |
183 |
$ |
154 |
$ |
131 |
$ |
153 |
Net Income (Loss) (GAAP) - (b) |
$ |
2,583 |
$ |
(1,097) |
$ |
(4,525) |
$ |
2,915 |
$ |
2,197 |
Total Stockholders' Equity - (d) |
$ |
16,283 |
$ |
13,982 |
$ |
12,943 |
$ |
17,713 |
$ |
15,418 |
Average Total Stockholders' Equity * - (e) |
$ |
15,133 |
$ |
13,463 |
$ |
15,328 |
$ |
16,566 |
$ |
14,352 |
Current and Long-Term Debt (GAAP) - (f) |
$ |
6,387 |
$ |
6,986 |
$ |
6,655 |
$ |
5,906 |
$ |
5,909 |
Less: Cash |
(834) |
(1,600) |
(719) |
(2,087) |
(1,318) |
|||||
Net Debt (Non-GAAP) - (g) |
$ |
5,553 |
$ |
5,386 |
$ |
5,936 |
$ |
3,819 |
$ |
4,591 |
Total Capitalization (GAAP) - (d) + (f) |
$ |
22,670 |
$ |
20,968 |
$ |
19,598 |
$ |
23,619 |
$ |
21,327 |
Total Capitalization (Non-GAAP) - (d) + (g) |
$ |
21,836 |
$ |
19,368 |
$ |
18,879 |
$ |
21,532 |
$ |
20,009 |
Average Total Capitalization (Non-GAAP) * - (h) |
$ |
20,602 |
$ |
19,124 |
$ |
20,206 |
$ |
20,771 |
$ |
19,365 |
ROCE (GAAP Net Income) - [(a) + (b)] / (h) |
13.4% |
-4.8% |
-21.6% |
14.7% |
12.1% |
|||||
Return on Equity (ROE) (GAAP) |
||||||||||
ROE (GAAP Net Income) - (b) / (e) |
17.1% |
-8.1% |
-29.5% |
17.6% |
15.3% |
|||||
* Average for the current and immediately preceding year |
||||||||||
EOG RESOURCES, INC. |
||||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total |
||||||||||
Capitalization (Non-GAAP) as used in the Calculation of Return on Capital Employed (Non-GAAP) to Net Interest |
||||||||||
Expense (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), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. |
||||||||||
2012 |
2011 |
2010 |
2009 |
2008 |
||||||
Return on Capital Employed (ROCE) (Non-GAAP) |
||||||||||
(Calculated Using GAAP Net Income) |
||||||||||
Net Interest Expense (GAAP) |
$ |
214 |
$ |
210 |
$ |
130 |
$ |
101 |
$ |
52 |
Tax Benefit Imputed (based on 35%) |
(75) |
(74) |
(46) |
(35) |
(18) |
|||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
$ |
139 |
$ |
136 |
$ |
84 |
$ |
66 |
$ |
34 |
Net Income (Loss) (GAAP) - (b) |
$ |
570 |
$ |
1,091 |
$ |
161 |
$ |
547 |
$ |
2,437 |
Total Stockholders' Equity - (d) |
$ |
13,285 |
$ |
12,641 |
$ |
10,232 |
$ |
9,998 |
$ |
9,015 |
Average Total Stockholders' Equity * - (e) |
$ |
12,963 |
$ |
11,437 |
$ |
10,115 |
$ |
9,507 |
$ |
8,003 |
Current and Long-Term Debt (GAAP) - (f) |
$ |
6,312 |
$ |
5,009 |
$ |
5,223 |
$ |
2,797 |
$ |
1,897 |
Less: Cash |
(876) |
(616) |
(789) |
(686) |
(331) |
|||||
Net Debt (Non-GAAP) - (g) |
$ |
5,436 |
$ |
4,393 |
$ |
4,434 |
$ |
2,111 |
$ |
1,566 |
Total Capitalization (GAAP) - (d) + (f) |
$ |
19,597 |
$ |
17,650 |
$ |
15,455 |
$ |
12,795 |
$ |
10,912 |
Total Capitalization (Non-GAAP) - (d) + (g) |
$ |
18,721 |
$ |
17,034 |
$ |
14,666 |
$ |
12,109 |
$ |
10,581 |
Average Total Capitalization (Non-GAAP) * - (h) |
$ |
17,878 |
$ |
15,850 |
$ |
13,388 |
$ |
11,345 |
$ |
9,351 |
ROCE (GAAP Net Income) - [(a) + (b)] / (h) |
4.0% |
7.7% |
1.8% |
5.4% |
26.4% |
|||||
Return on Equity (ROE) (GAAP) |
||||||||||
ROE (GAAP Net Income) - (b) / (e) |
4.4% |
9.5% |
1.6% |
5.8% |
30.5% |
|||||
* Average for the current and immediately preceding year |
||||||||||
EOG RESOURCES, INC. |
||||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total |
||||||||||
Capitalization (Non-GAAP) as used in the Calculation of Return on Capital Employed (Non-GAAP) to Net Interest |
||||||||||
Expense (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), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. |
||||||||||
2007 |
2006 |
2005 |
2004 |
2003 |
||||||
Return on Capital Employed (ROCE) (Non-GAAP) |
||||||||||
(Calculated Using GAAP Net Income) |
||||||||||
Net Interest Expense (GAAP) |
$ |
47 |
$ |
43 |
$ |
63 |
$ |
63 |
$ |
59 |
Tax Benefit Imputed (based on 35%) |
(16) |
(15) |
(22) |
(22) |
(21) |
|||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
$ |
31 |
$ |
28 |
$ |
41 |
$ |
41 |
$ |
38 |
Net Income (Loss) (GAAP) - (b) |
$ |
1,090 |
$ |
1,300 |
$ |
1,260 |
$ |
625 |
$ |
430 |
Total Stockholders' Equity - (d) |
$ |
6,990 |
$ |
5,600 |
$ |
4,316 |
$ |
2,945 |
$ |
2,223 |
Average Total Stockholders' Equity * - (e) |
$ |
6,295 |
$ |
4,958 |
$ |
3,631 |
$ |
2,584 |
$ |
1,948 |
Current and Long-Term Debt (GAAP) - (f) |
$ |
1,185 |
$ |
733 |
$ |
985 |
$ |
1,078 |
$ |
1,109 |
Less: Cash |
(54) |
(218) |
(644) |
(21) |
(4) |
|||||
Net Debt (Non-GAAP) - (g) |
$ |
1,131 |
$ |
515 |
$ |
341 |
$ |
1,057 |
$ |
1,105 |
Total Capitalization (GAAP) - (d) + (f) |
$ |
8,175 |
$ |
6,333 |
$ |
5,301 |
$ |
4,023 |
$ |
3,332 |
Total Capitalization (Non-GAAP) - (d) + (g) |
$ |
8,121 |
$ |
6,115 |
$ |
4,657 |
$ |
4,002 |
$ |
3,328 |
Average Total Capitalization (Non-GAAP) * - (h) |
$ |
7,118 |
$ |
5,386 |
$ |
4,330 |
$ |
3,665 |
$ |
3,068 |
ROCE (GAAP Net Income) - [(a) + (b)] / (h) |
15.7% |
24.7% |
30.0% |
18.2% |
15.3% |
|||||
Return on Equity (ROE) (GAAP) |
||||||||||
ROE (GAAP Net Income) - (b) / (e) |
17.3% |
26.2% |
34.7% |
24.2% |
22.1% |
|||||
* Average for the current and immediately preceding year |
||||||||||
EOG RESOURCES, INC. |
||||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total |
||||||||||
Capitalization (Non-GAAP) as used in the Calculation of Return on Capital Employed (Non-GAAP) to Net Interest |
||||||||||
Expense (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), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. |
||||||||||
2002 |
2001 |
2000 |
1999 |
1998 |
||||||
Return on Capital Employed (ROCE) (Non-GAAP) |
||||||||||
(Calculated Using GAAP Net Income) |
||||||||||
Net Interest Expense (GAAP) |
$ |
60 |
$ |
45 |
$ |
61 |
$ |
62 |
||
Tax Benefit Imputed (based on 35%) |
(21) |
(16) |
(21) |
(22) |
||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
$ |
39 |
$ |
29 |
$ |
40 |
$ |
40 |
||
Net Income (Loss) (GAAP) - (b) |
$ |
87 |
$ |
399 |
$ |
397 |
$ |
569 |
||
Total Stockholders' Equity - (d) |
$ |
1,672 |
$ |
1,643 |
$ |
1,381 |
$ |
1,130 |
$ |
1,280 |
Average Total Stockholders' Equity * - (e) |
$ |
1,658 |
$ |
1,512 |
$ |
1,256 |
$ |
1,205 |
||
Current and Long-Term Debt (GAAP) - (f) |
$ |
1,145 |
$ |
856 |
$ |
859 |
$ |
990 |
$ |
1,143 |
Less: Cash |
(10) |
(3) |
(20) |
(25) |
(6) |
|||||
Net Debt (Non-GAAP) - (g) |
$ |
1,135 |
$ |
853 |
$ |
839 |
$ |
965 |
$ |
1,137 |
Total Capitalization (GAAP) - (d) + (f) |
$ |
2,817 |
$ |
2,499 |
$ |
2,240 |
$ |
2,120 |
$ |
2,423 |
Total Capitalization (Non-GAAP) - (d) + (g) |
$ |
2,807 |
$ |
2,496 |
$ |
2,220 |
$ |
2,095 |
$ |
2,417 |
Average Total Capitalization (Non-GAAP) * - (h) |
$ |
2,652 |
$ |
2,358 |
$ |
2,158 |
$ |
2,256 |
||
ROCE (GAAP Net Income) - [(a) + (b)] / (h) |
4.8% |
18.2% |
20.2% |
27.0% |
||||||
Return on Equity (ROE) (GAAP) |
||||||||||
ROE (GAAP Net Income) - (b) / (e) |
5.2% |
26.4% |
31.6% |
47.2% |
||||||
* Average for the current and immediately preceding year |
EOG RESOURCES, INC. |
|||||||||||
Cash Operating Expenses per Barrel of Oil Equivalent (Boe) |
|||||||||||
(Unaudited; in thousands, except per Boe amounts) |
|||||||||||
Year Ended |
|||||||||||
December 31, |
|||||||||||
2018 |
2017 |
2016 |
2015 |
2014 |
|||||||
Cash Operating Expenses (GAAP)* |
|||||||||||
Lease and Well |
$ 1,282,678 |
$ 1,044,847 |
$ 927,452 |
$ 1,182,282 |
$ 1,416,413 |
||||||
Transportation Costs |
746,876 |
740,352 |
764,106 |
849,319 |
972,176 |
||||||
General and Administrative |
426,969 |
434,467 |
394,815 |
366,594 |
402,010 |
||||||
Cash Operating Expenses |
2,456,523 |
2,219,666 |
2,086,373 |
2,398,195 |
2,790,599 |
||||||
Less: Legal Settlement - Early Leasehold Termination |
- |
(10,202) |
- |
(19,355) |
- |
||||||
Less: Voluntary Retirement Expense |
- |
- |
(42,054) |
- |
- |
||||||
Less: Acquisition Costs - Yates Transaction |
- |
- |
(5,100) |
- |
- |
||||||
Less: Joint Venture Transaction Costs |
- |
(3,056) |
- |
- |
- |
||||||
Less: Joint Interest Billings Deemed Uncollectible |
- |
(4,528) |
- |
- |
- |
||||||
Adjusted Cash Operating Expenses (Non-GAAP) - (a) |
$ 2,456,523 |
$ 2,201,880 |
$ 2,039,219 |
$ 2,378,840 |
$ 2,790,599 |
||||||
Volume - Thousand Barrels of Oil Equivalent - (b) |
262,516 |
222,251 |
204,929 |
208,862 |
217,073 |
||||||
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - (a) / (b) |
$ 9.36 |
(c) |
$ 9.91 |
(d) |
$ 9.95 |
(e) |
$ 11.39 |
(f) |
$ 12.86 |
(g) |
|
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - |
|||||||||||
2018 compared to 2017 - [(c) - (d)] / (d) |
-6% |
||||||||||
2018 compared to 2016 - [(c) - (e)] / (e) |
-6% |
||||||||||
2018 compared to 2015 - [(c) - (f)] / (f) |
-18% |
||||||||||
2018 compared to 2014 - [(c) - (g)] / (g) |
-27% |
||||||||||
* Includes stock compensation expense and other non-cash items. |
EOG RESOURCES, INC. |
|||||||||
Cost per Barrel of Oil Equivalent (Boe) |
|||||||||
(Unaudited; in thousands, except per Boe amounts) |
|||||||||
Three Months Ended |
|||||||||
March 31, |
June 30, |
September 30, |
December 31, |
||||||
2018 |
2018 |
2018 |
2018 |
||||||
Volume - Thousand Barrels of Oil Equivalent - (a) |
59,394 |
63,898 |
68,890 |
70,334 |
|||||
Crude Oil and Condensate |
$ 2,101,308 |
$ 2,377,528 |
$ 2,655,278 |
$ 2,383,326 |
|||||
Natural Gas Liquids |
221,415 |
286,354 |
353,704 |
266,037 |
|||||
Natural Gas |
299,766 |
300,845 |
311,713 |
389,213 |
|||||
Total Wellhead Revenues - (b) |
$ 2,622,489 |
$ 2,964,727 |
$ 3,320,695 |
$ 3,038,576 |
|||||
Operating Costs |
|||||||||
Lease and Well |
$ 300,064 |
$ 314,604 |
$ 321,568 |
$ 346,442 |
|||||
Transportation Costs |
176,957 |
177,797 |
196,027 |
196,095 |
|||||
Gathering and Processing Costs |
101,345 |
109,169 |
114,063 |
112,396 |
|||||
General and Administrative |
94,698 |
104,083 |
111,284 |
116,904 |
|||||
Taxes Other Than Income |
179,084 |
194,268 |
209,043 |
190,086 |
|||||
Interest Expense, Net |
61,956 |
63,444 |
63,632 |
56,020 |
|||||
Total Cash Operating Cost (excluding |
$ 914,104 |
$ 963,365 |
$ 1,015,617 |
$ 1,017,943 |
|||||
Depreciation, Depletion and Amortization (DD&A) |
748,591 |
848,674 |
918,180 |
919,963 |
|||||
Total Operating Cost (excluding Exploration |
$ 1,662,695 |
$ 1,812,039 |
$ 1,933,797 |
$ 1,937,906 |
|||||
Exploration Costs |
$ 34,836 |
$ 47,478 |
$ 32,823 |
$ 33,862 |
|||||
Dry Hole Costs |
- |
4,902 |
358 |
145 |
|||||
Impairments |
64,609 |
51,708 |
44,617 |
186,087 |
|||||
Total Exploration Costs |
99,445 |
104,088 |
77,798 |
220,094 |
|||||
Less: Impairments (Non-GAAP) |
(20,876) |
- |
- |
(131,795) |
|||||
Total Exploration Costs (Non-GAAP) |
$ 78,569 |
$ 104,088 |
$ 77,798 |
$ 88,299 |
|||||
Total Operating Cost (Non-GAAP) (including Exploration |
$ 1,741,264 |
$ 1,916,127 |
$ 2,011,595 |
$ 2,026,205 |
|||||
Composite Average Wellhead Revenue per Boe - (b) / (a) |
$ 44.15 |
$ 46.40 |
$ 48.20 |
$ 43.20 |
|||||
Total Cash Operating Cost per Boe |
$ 15.39 |
$ 15.07 |
$ 14.75 |
$ 14.48 |
|||||
Composite Average Margin per Boe (excluding |
$ 28.76 |
$ 31.33 |
$ 33.45 |
$ 28.72 |
|||||
Total Operating Cost per Boe (excluding |
$ 27.99 |
$ 28.35 |
$ 28.08 |
$ 27.56 |
|||||
Composite Average Margin per Boe (excluding |
$ 16.16 |
$ 18.05 |
$ 20.12 |
$ 15.64 |
|||||
Total Operating Cost per Boe (Non-GAAP) (including |
$ 29.31 |
$ 29.98 |
$ 29.21 |
$ 28.82 |
|||||
Composite Average Margin per Boe (Non-GAAP) |
$ 14.84 |
$ 16.42 |
$ 18.99 |
$ 14.38 |
|||||
EOG RESOURCES, INC. |
|||||||||
Cost per Barrel of Oil Equivalent (Boe) |
|||||||||
(Unaudited; in thousands, except per Boe amounts) |
|||||||||
Year Ended |
|||||||||
December 31, |
|||||||||
2018 |
2017 |
2016 |
2015 |
2014 |
|||||
Volume - Thousand Barrels of Oil Equivalent - (a) |
262,516 |
222,251 |
204,929 |
208,862 |
217,073 |
||||
Crude Oil and Condensate |
$ 9,517,440 |
$ 6,256,396 |
$ 4,317,341 |
$ 4,934,562 |
$ 9,742,480 |
||||
Natural Gas Liquids |
1,127,510 |
729,561 |
437,250 |
407,658 |
934,051 |
||||
Natural Gas |
1,301,537 |
921,934 |
742,152 |
1,061,038 |
1,916,386 |
||||
Total Wellhead Revenues - (b) |
$ 11,946,487 |
$ 7,907,891 |
$ 5,496,743 |
$ 6,403,258 |
$ 12,592,917 |
||||
Operating Costs |
|||||||||
Lease and Well |
$ 1,282,678 |
$ 1,044,847 |
$ 927,452 |
$ 1,182,282 |
$ 1,416,413 |
||||
Transportation Costs |
746,876 |
740,352 |
764,106 |
849,319 |
972,176 |
||||
Gathering and Processing Costs |
436,973 |
148,775 |
122,901 |
146,156 |
145,800 |
||||
General and Administrative |
426,969 |
434,467 |
394,815 |
366,594 |
402,010 |
||||
Less: Voluntary Retirement Expense |
- |
- |
(42,054) |
- |
- |
||||
Less: Acquisition Costs |
- |
- |
(5,100) |
- |
- |
||||
Less: Legal Settlement - Early Leasehold Termination |
- |
(10,202) |
- |
(19,355) |
- |
||||
Less: Joint Venture Transaction Costs |
- |
(3,056) |
- |
- |
- |
||||
Less: Joint Interest Billings Deemed Uncollectible |
- |
(4,528) |
- |
- |
- |
||||
General and Administrative (Non-GAAP) |
426,969 |
416,681 |
347,661 |
347,239 |
402,010 |
||||
Taxes Other Than Income |
772,481 |
544,662 |
349,710 |
421,744 |
757,564 |
||||
Interest Expense, Net |
245,052 |
274,372 |
281,681 |
237,393 |
201,458 |
||||
Total Cash Operating Cost (Non-GAAP) (excluding |
$ 3,911,029 |
$ 3,169,689 |
$ 2,793,511 |
$ 3,184,133 |
$ 3,895,421 |
||||
Depreciation, Depletion and Amortization (DD&A) |
3,435,408 |
3,409,387 |
3,553,417 |
3,313,644 |
3,997,041 |
||||
Total Operating Cost (Non-GAAP) (excluding Exploration |
$ 7,346,437 |
$ 6,579,076 |
$ 6,346,928 |
$ 6,497,777 |
$ 7,892,462 |
||||
Exploration Costs |
$ 148,999 |
$ 145,342 |
$ 124,953 |
$ 149,494 |
$ 184,388 |
||||
Dry Hole Costs |
5,405 |
4,609 |
10,657 |
14,746 |
48,490 |
||||
Impairments |
347,021 |
479,240 |
620,267 |
6,613,546 |
743,575 |
||||
Total Exploration Costs |
501,425 |
629,191 |
755,877 |
6,777,786 |
976,453 |
||||
Less: Impairments (Non-GAAP) |
(152,671) |
(261,452) |
(320,617) |
(6,307,593) |
(824,312) |
||||
Total Exploration Costs (Non-GAAP) |
$ 348,754 |
$ 367,739 |
$ 435,260 |
$ 470,193 |
$ 152,141 |
||||
Total Operating Cost (Non-GAAP) (including Exploration |
$ 7,695,191 |
$ 6,946,815 |
$ 6,782,188 |
$ 6,967,970 |
$ 8,044,603 |
||||
Composite Average Wellhead Revenue per Boe - (b) / (a) |
$ 45.51 |
$ 35.58 |
$ 26.82 |
$ 30.66 |
$ 58.01 |
||||
Total Cash Operating Cost per Boe (Non-GAAP) |
$ 14.90 |
$ 14.25 |
$ 13.64 |
$ 15.25 |
$ 17.95 |
||||
Composite Average Margin per Boe (Non-GAAP) |
$ 30.61 |
$ 21.33 |
$ 13.18 |
$ 15.41 |
$ 40.06 |
||||
Total Operating Cost per Boe (Non-GAAP) (excluding |
$ 27.99 |
$ 29.59 |
$ 30.98 |
$ 31.11 |
$ 36.38 |
||||
Composite Average Margin per Boe (Non-GAAP) |
$ 17.52 |
$ 5.99 |
$ (4.16) |
$ (0.45) |
$ 21.63 |
||||
Total Operating Cost per Boe (Non-GAAP) (including |
$ 29.32 |
$ 31.24 |
$ 33.10 |
$ 33.36 |
$ 37.08 |
||||
Composite Average Margin per Boe (Non-GAAP) |
$ 16.19 |
$ 4.34 |
$ (6.28) |
$ (2.70) |
$ 20.93 |
EOG RESOURCES, INC. |
|||||||||||
First Quarter and Full Year 2019 Forecast and Benchmark Commodity Pricing |
|||||||||||
(a) First Quarter and Full Year 2019 Forecast |
|||||||||||
The forecast items for the first quarter and full year 2019 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) Capital Expenditures |
|||||||||||
The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Exploration Costs, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs and any Non-Cash Exchanges. |
|||||||||||
(c) 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 2019 |
Full Year 2019 |
||||||||||
Daily Sales Volumes |
|||||||||||
Crude Oil and Condensate Volumes (MBbld) |
|||||||||||
United States |
426.6 |
- |
434.2 |
442.6 |
- |
458.2 |
|||||
Trinidad |
0.4 |
- |
0.6 |
0.4 |
- |
0.6 |
|||||
Other International |
0.0 |
- |
0.2 |
0.0 |
- |
0.2 |
|||||
Total |
427.0 |
- |
435.0 |
443.0 |
- |
459.0 |
|||||
Natural Gas Liquids Volumes (MBbld) |
|||||||||||
Total |
115.0 |
- |
125.0 |
120.0 |
- |
140.0 |
|||||
Natural Gas Volumes (MMcfd) |
|||||||||||
United States |
950 |
- |
1,000 |
1,030 |
- |
1,130 |
|||||
Trinidad |
245 |
- |
275 |
250 |
- |
290 |
|||||
Other International |
30 |
- |
40 |
30 |
- |
40 |
|||||
Total |
1,225 |
- |
1,315 |
1,310 |
- |
1,460 |
|||||
Crude Oil Equivalent Volumes (MBoed) |
|||||||||||
United States |
699.9 |
- |
725.9 |
734.3 |
- |
786.5 |
|||||
Trinidad |
41.2 |
- |
46.4 |
42.1 |
- |
48.9 |
|||||
Other International |
5.0 |
- |
6.9 |
5.0 |
- |
6.9 |
|||||
Total |
746.1 |
- |
779.2 |
781.4 |
- |
842.3 |
|||||
Capital Expenditures ($MM) |
$ |
1,750 |
- |
$ |
1,950 |
$ |
6,100 |
- |
$ |
6,500 |
|
Estimated Ranges |
|||||||||||
(Unaudited) |
|||||||||||
1Q 2019 |
Full Year 2019 |
||||||||||
Operating Costs |
|||||||||||
Unit Costs ($/Boe) |
|||||||||||
Lease and Well |
$ |
4.90 |
- |
$ |
5.30 |
$ |
4.50 |
- |
$ |
5.30 |
|
Transportation Costs |
$ |
2.50 |
- |
$ |
3.00 |
$ |
2.60 |
- |
$ |
3.10 |
|
Depreciation, Depletion and Amortization |
$ |
12.50 |
- |
$ |
13.00 |
$ |
12.25 |
- |
$ |
13.25 |
|
Expenses ($MM) |
|||||||||||
Exploration and Dry Hole |
$ |
35 |
- |
$ |
45 |
$ |
155 |
- |
$ |
195 |
|
Impairment |
$ |
55 |
- |
$ |
65 |
$ |
190 |
- |
$ |
230 |
|
General and Administrative |
$ |
110 |
- |
$ |
120 |
$ |
450 |
- |
$ |
490 |
|
Gathering and Processing |
$ |
100 |
- |
$ |
110 |
$ |
440 |
- |
$ |
480 |
|
Capitalized Interest |
$ |
6 |
- |
$ |
8 |
$ |
25 |
- |
$ |
30 |
|
Net Interest |
$ |
54 |
- |
$ |
56 |
$ |
190 |
- |
$ |
200 |
|
Taxes Other Than Income (% of Wellhead Revenue) |
7.2% |
- |
7.6% |
7.2% |
- |
7.6% |
|||||
Income Taxes |
|||||||||||
Effective Rate |
20% |
- |
25% |
20% |
- |
25% |
|||||
Current Tax (Benefit) / Expense ($MM) |
$ |
(55) |
- |
$ |
(15) |
$ |
(190) |
- |
$ |
(110) |
|
Pricing - (Refer toBenchmark Commodity Pricingin text) |
|||||||||||
Crude Oil and Condensate ($/Bbl) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) WTI |
$ |
0.25 |
- |
$ |
1.25 |
$ |
(1.00) |
- |
$ |
1.00 |
|
Trinidad - above (below) WTI |
$ |
(11.00) |
- |
$ |
(9.00) |
$ |
(11.00) |
- |
$ |
(9.00) |
|
Other International - above (below) WTI |
$ |
5.00 |
- |
$ |
9.00 |
$ |
(1.00) |
- |
$ |
1.00 |
|
Natural Gas Liquids |
|||||||||||
Realizations as % of WTI |
37% |
- |
43% |
37% |
- |
43% |
|||||
Natural Gas ($/Mcf) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) NYMEX Henry Hub |
$ |
(0.40) |
- |
$ |
0.00 |
$ |
(0.50) |
- |
$ |
0.10 |
|
Realizations |
|||||||||||
Trinidad |
$ |
2.50 |
- |
$ |
2.90 |
$ |
2.50 |
- |
$ |
3.20 |
|
Other International |
$ |
4.30 |
- |
$ |
4.80 |
$ |
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 |
View original content:http://www.prnewswire.com/news-releases/eog-resources-reports-fourth-quarter-and-full-year-2018-results-and-announces-2019-capital-program-300802665.html
SOURCE EOG Resources, Inc.