Feb 26, 2019 SOURCE: PR NewsWire
EOG Resources Reports Fourth Quarter and Full Year 2018 Results and Announces 2019 Capital Program
HOUSTON, Feb. 26, 2019 /PRNewswire/ --
-- Earns Record Net Income in 2018 and Generates Significant Net Cash from
Operating Activities and Free Cash Flow
-- Exceeds Fourth Quarter Crude Oil and NGL Production Target Midpoints
-- Increases Proved Reserves by 16% and Replaces 238% of 2018 Production at
Sub-$10 Finding Cost
-- Targets Improved Capital Efficiency, Significant Investment in
High-Quality New Drilling Potential and 12-16% U.S. Crude Oil Volume
Growth in 2019, Funded with Net Cash from Operating Activities at $50
Oil
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:
-- the timing, extent and duration of changes in prices for, supplies
of, and demand for, crude oil and condensate, natural gas liquids,
natural gas and related commodities;
-- the extent to which EOG is successful in its efforts to acquire or
discover additional reserves;
-- the extent to which EOG is successful in its efforts to economically
develop its acreage in, produce reserves and achieve anticipated
production levels from, and maximize reserve recovery from, its existing
and future crude oil and natural gas exploration and development
projects;
-- the extent to which EOG is successful in its efforts to market its
crude oil and condensate, natural gas liquids, natural gas and related
commodity production;
-- the availability, proximity and capacity of, and costs associated
with, appropriate gathering, processing, compression, storage,
transportation and refining facilities;
-- the availability, cost, terms and timing of issuance or execution of,
and competition for, mineral licenses and leases and governmental and
other permits and rights-of-way, and EOG's ability to retain mineral
licenses and leases;
-- the impact of, and changes in, government policies, laws and
regulations, including tax laws and regulations; climate change and
other environmental, health and safety laws and regulations relating to
air emissions, disposal of produced water, drilling fluids and other
wastes, hydraulic fracturing and access to and use of water; laws and
regulations imposing conditions or restrictions on drilling and
completion operations and on the transportation of crude oil and natural
gas; laws and regulations with respect to derivatives and hedging
activities; and laws and regulations with respect to the import and
export of crude oil, natural gas and related commodities;
-- EOG's ability to effectively integrate acquired crude oil and natural
gas properties into its operations, fully identify existing and
potential problems with respect to such properties and accurately
estimate reserves, production and costs with respect to such properties;
-- the extent to which EOG's third-party-operated crude oil and natural
gas properties are operated successfully and economically;
-- competition in the oil and gas exploration and production industry
for the acquisition of licenses, leases and properties, employees and
other personnel, facilities, equipment, materials and services;
-- the availability and cost of employees and other personnel,
facilities, equipment, materials (such as water and tubulars) and
services;
-- the accuracy of reserve estimates, which by their nature involve the
exercise of professional judgment and may therefore be imprecise;
-- weather, including its impact on crude oil and natural gas demand,
and weather-related delays in drilling and in the installation and
operation (by EOG or third parties) of production, gathering,
processing, refining, compression, storage and transportation
facilities;
-- the ability of EOG's customers and other contractual counterparties
to satisfy their obligations to EOG and, related thereto, to access the
credit and capital markets to obtain financing needed to satisfy their
obligations to EOG;
-- EOG's ability to access the commercial paper market and other credit
and capital markets to obtain financing on terms it deems acceptable, if
at all, and to otherwise satisfy its capital expenditure requirements;
-- the extent to which EOG is successful in its completion of planned
asset dispositions;
-- the extent and effect of any hedging activities engaged in by EOG;
-- the timing and extent of changes in foreign currency exchange rates,
interest rates, inflation rates, global and domestic financial market
conditions and global and domestic general economic conditions;
-- geopolitical factors and political conditions and developments around
the world (such as the imposition of tariffs or trade or other economic
sanctions, political instability and armed conflict), including in the
areas in which EOG operates;
-- the use of competing energy sources and the development of
alternative energy sources;
-- the extent to which EOG incurs uninsured losses and liabilities or
losses and liabilities in excess of its insurance coverage;
-- acts of war and terrorism and responses to these acts;
-- physical, electronic and cybersecurity breaches; and
-- the other factors described under ITEM 1A, Risk Factors, on pages 13
through 22 of EOG's Annual Report on Form 10-K for the fiscal year ended
December 31, 2018 and any updates to those factors set forth in EOG's
subsequent Quarterly Reports on Form 10-Q or Current Reports on Form
8-K.
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration 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
Derivative Contracts
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
580,408,117 Shares and 578,827,768 Shares Issued at December 31, 2018
and 2017, respectively.
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)
December 31, 2018 and 2017, respectively.
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
Activities
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
Length Condensate Liquids (MMcfd) (A) Equivalent
(ft) (Bbld) (A) (Bbld) (A) (Boed) (B)
---
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
Derivative Contracts
Net Cash Received from (Payments for) (78,678) 17,330 (61,348) (0.11) 2,708 (971) 1,737 -
Settlements of Commodity Derivative
Contracts
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)
Derivative Contracts
Net Cash Received from (Payments for) (258,906) 57,029 (201,877) (0.35) 7,438 (2,666) 4,772 0.01
Settlements of Commodity Derivative
Contracts
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
Derivative Contracts
(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) -
Percentage Decrease
---
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
DD&A and Exploration Costs) - (c)
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
Costs) - (d)
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
Costs) - (e)
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
(excluding DD&A and Exploration Costs) - (c) / (a)
Composite Average Margin per Boe (excluding $28.76 $31.33 $33.45 $28.72
DD&A and Exploration Costs) - [(b) / (a) - (c) / (a)]
Total Operating Cost per Boe (excluding $27.99 $28.35 $28.08 $27.56
Exploration Costs) - (d) / (a)
Composite Average Margin per Boe (excluding $16.16 $18.05 $20.12 $15.64
Exploration Costs) - [(b) / (a) - (d) / (a)]
Total Operating Cost per Boe (Non-GAAP) (including $29.31 $29.98 $29.21 $28.82
Exploration Costs) (e) / (a)
Composite Average Margin per Boe (Non-GAAP) $14.84 $16.42 $18.99 $14.38
(including Exploration Costs) - [(b) / (a) - (e) / (a)]
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
DD&A and Exploration Costs) - (c)
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
Costs) - (d)
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
Costs) - (e)
===
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
(excluding DD&A and Exploration Costs) - (c) / (a)
===
Composite Average Margin per Boe (Non-GAAP) $30.61 $21.33 $13.18 $15.41 $40.06
(excluding DD&A and Exploration Costs) - [(b) / (a) - (c) / (a)]
===
Total Operating Cost per Boe (Non-GAAP) (excluding $27.99 $29.59 $30.98 $31.11 $36.38
Exploration Costs) - (d) / (a)
===
Composite Average Margin per Boe (Non-GAAP) $17.52 $5.99 $(4.16) $(0.45) $21.63
(excluding Exploration Costs) - [(b) / (a) - (d) / (a)]
===
Total Operating Cost per Boe (Non-GAAP) (including $29.32 $31.24 $33.10 $33.36 $37.08
Exploration Costs) - (e) / (a)
===
Composite Average Margin per Boe (Non-GAAP) $16.19 $4.34 $(6.28) $(2.70) $20.93
(including Exploration Costs) - [(b) / (a) - (e) / (a)]
===
EOG RESOURCES, INC.
First Quarter and Full Year 2019 Forecast and Benchmark Commodity Pricing
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(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.
