EOG Resources Announces Outstanding Third Quarter 2018 Results
HOUSTON, Nov. 1, 2018 /PRNewswire/ --
- Exceeds High End of Oil and NGL Production Targets
- Generates Significant Free Cash Flow
- Achieves Improved Well Performance and Lower Costs in Delaware Basin
- Secures 2019 Services at Competitive Prices and Raises 2018 Capex Guidance Range to $5.8-$6.0 Billion
- Targets Further Well Cost Reductions in 2019
EOG Resources, Inc. (EOG) today reported third quarter 2018 net income of $1.2 billion, or $2.05 per share. This compares to third quarter 2017 net income of $101 million, or $0.17 per share. Net cash from operating activities in the third quarter 2018 was $2.2 billion.
Adjusted non-GAAP net income for the third quarter 2018 was $1.0 billion, or $1.75 per share, compared to adjusted non-GAAP net income of $111 million, or $0.19 per share, for the same prior year period. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.
Third Quarter ReviewEOG set a company record and exceeded the high end of its target range for crude oil volumes in the third quarter 2018 by producing 415,000 barrels of oil per day (Bopd), an increase of 27 percent compared to the same prior year period. Natural gas liquids (NGL) production increased 46 percent while natural gas volumes grew 13 percent, contributing to total company production growth of 25 percent.
Per-unit operating expenses declined during the third quarter 2018 compared to the same prior year period. General and administrative expenses fell 20 percent, transportation costs declined 15 percent and depreciation, depletion and amortization expenses fell 13 percent, all on a per-unit basis.
EOG generated $2.3 billion of discretionary cash flow in the third quarter 2018. After considering exploration and development expenditures of $1.7 billion and dividend payments of $107 million, EOG produced free cash flow during the third quarter of $503 million. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.
"EOG delivered a compelling combination of production growth, high returns and free cash flow in the third quarter 2018 due to disciplined capital allocation. These results demonstrate the value of EOG's sustainable business model," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "EOG is making significant progress lowering costs and improving well performance. Our culture of innovation, experimentation and entrepreneurship combined with our ability to capture and quickly analyze real-time data and make rapid changes in the field are resulting in significant performance improvements company-wide."
Updated 2018 OutlookEOG has raised its target for full-year 2018 crude oil production growth to 19 percent. To maintain operational continuity into 2019, the company elected to retain high performing service providers for the remainder of 2018. Approximately 65 percent of its anticipated 2019 services have been secured at competitive pricing. As a result, EOG increased its 2018 exploration and development expenditure forecast to $5.8 to $6.0 billion, excluding acquisitions and non-cash transactions. The company is on track to reduce total well costs by five percent in 2018, and targets further well cost reductions in 2019. EOG now expects to complete approximately 720 net wells in 2018, an increase of 20 net wells from its prior forecast.
"We are positioning EOG to carry the operating efficiencies gained this year into 2019. We secured a significant proportion of our service costs, which along with disciplined execution will help further reduce well costs and improve returns," Thomas continued. "With a deep inventory of premium drilling locations across multiple plays, EOG will continue to allocate capital to the highest return areas while maintaining a disciplined operating pace. EOG is well positioned to continue delivering its unique combination of high returns, disciplined growth and strong free cash flow for years to come."
Operating HighlightsEOG's South Texas Eagle Ford remained the most active area of the company in the third quarter 2018. EOG now expects to complete 290 net wells in 2018, an addition of 20 net wells from the prior forecast. EOG also continued to delineate the South Texas Austin Chalk, completing 14 wells in the third quarter.
In the Delaware Basin, EOG made significant progress on well cost reductions and optimizing targeting and development patterns. The company increased the number of wells developed in a single package and drilled longer laterals. Packages of four wells or more accounted for 87 percent of the wells brought on line in the third quarter. EOG also made additional progress towards its cost reduction goals. Drilling speeds and the pace of completion operations increased markedly during the quarter. In addition, the company now supplies nearly all of its Delaware Basin sand from local sources and has further increased its use of low-cost recycled water.
EOG continued development of its premium play in the Eastern Anadarko Basin Woodford Oil Window. EOG is testing spacing patterns and various targets across the play. The company completed 11 wells in the third quarter. EOG completed a package of four wells spaced 660 feet apart late in the second quarter. The Ted 2326 #1H-#4H were completed with an average treated lateral length of 10,000 feet per well and average 30-day initial production rates per well of 800 barrels of oil equivalent per day, or 660 Bopd, 90 barrels per day of NGLs and 0.3 million cubic feet per day of natural gas. These low-decline wells support our initial spacing assessment of 660 feet. EOG is also making significant progress reducing well costs in this new play. Recent wells have been brought to production at costs at or below the company's $7.8 million target.
EOG continued development of its premium plays across the Rocky Mountain region. The company brought 20 wells on line in the Powder River Basin during the third quarter 2018, including 13 wells from the Turner formation. In the Wyoming DJ Basin, EOG began production from 25 wells in the third quarter 2018. EOG completed 19 wells in the Williston Basin during the third quarter as part of its seasonal development program.
Financial ReviewAt September 30, 2018, EOG's total debt outstanding was $6.4 billion for a debt-to-total capitalization ratio of 26 percent. Considering cash on the balance sheet at the end of the third quarter, EOG's net debt was $5.2 billion for a net debt-to-total capitalization ratio of 22 percent. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
EOG reached an agreement to divest all of its U.K. operations. Closing is anticipated in the fourth quarter 2018.
During the third quarter ended September 30, 2018, EOG entered into additional crude oil derivative contracts. A comprehensive summary of EOG's crude oil and natural gas derivative contracts is provided in the attached tables.
Third Quarter 2018 Results WebcastFriday, November 2, 2018, 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 EOGEOG 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, the United Kingdom and China. To learn more visit www.eogresources.com.
Investor ContactsDavid Streit 713-571-4902Neel Panchal 713-571-4884John Wagner 713-571-4404
Media and Investor ContactKimberly Ehmer 713-571-4676
This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "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, reduce or otherwise control operating and capital costs, generate income or cash flows, pay down 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, EOG has presented or referenced herein or in its accompanying disclosures certain forward-looking, non-GAAP financial measures, such as free cash flow and discretionary cash flow, and certain related estimates regarding future performance, results and financial position. These forward-looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented. EOG's actual results may differ materially from the measure and estimates presented or referenced herein. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
- the timing, extent and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities;
- the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
- the extent to which EOG is successful in its efforts to economically develop its acreage in, produce reserves and achieve anticipated production levels from, and maximize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects;
- the extent to which EOG is successful in its efforts to market its crude oil and condensate, natural gas liquids, natural gas and related commodity production;
- the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, transportation and refining facilities;
- the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights-of-way, and EOG's ability to retain mineral licenses and leases;
- the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations; environmental, health and safety laws and regulations relating to air emissions, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;
- EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties;
- the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully and economically;
- competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties, employees and other personnel, facilities, equipment, materials and services;
- the availability and cost of employees and other personnel, facilities, equipment, materials (such as water) and services;
- the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
- weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression and transportation facilities;
- the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
- EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;
- the extent to which EOG is successful in its completion of planned asset dispositions;
- the extent and effect of any hedging activities engaged in by EOG;
- the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
- political conditions and developments around the world (such as political instability and armed conflict), including in the areas in which EOG operates;
- the use of competing energy sources and the development of alternative energy sources;
- the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;
- acts of war and terrorism and responses to these acts;
- physical, electronic and cyber security breaches; and
- the other factors described under ITEM 1A, Risk Factors, on pages 14 through 23 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2017, and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration and extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2017, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
EOG RESOURCES, INC. | |||||||||||
Financial Report | |||||||||||
(Unaudited; in millions, except per share data) | |||||||||||
Three Months Ended | Nine Months Ended | ||||||||||
September 30, | September 30, | ||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||
Operating Revenues and Other | $ | 4,781.6 | $ | 2,644.8 | $ | 12,700.9 | $ | 7,867.9 | |||
Net Income | $ | 1,191.0 | $ | 100.5 | $ | 2,526.3 | $ | 152.1 | |||
Net Income Per Share | |||||||||||
Basic | $ | 2.06 | $ | 0.17 | $ | 4.38 | $ | 0.26 | |||
Diluted | $ | 2.05 | $ | 0.17 | $ | 4.35 | $ | 0.26 | |||
Average Number of Common Shares | |||||||||||
Basic | 577.3 | 574.8 | 576.4 | 574.4 | |||||||
Diluted | 581.6 | 578.7 | 580.4 | 578.5 | |||||||
Summary Income Statements | |||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||
Three Months Ended | Nine Months Ended | ||||||||||
September 30, | September 30, | ||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||
Operating Revenues and Other | |||||||||||
Crude Oil and Condensate | $ | 2,655,278 | $ | 1,451,410 | $ | 7,134,114 | $ | 4,326,925 | |||
Natural Gas Liquids | 353,704 | 180,038 | 861,473 | 480,389 | |||||||
Natural Gas | 311,713 | 220,402 | 912,324 | 675,012 | |||||||
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts | (52,081) | (6,606) | (297,735) | 64,860 | |||||||
Gathering, Processing and Marketing | 1,360,992 | 784,368 | 3,899,250 | 2,289,702 | |||||||
Gains (Losses) on Asset Dispositions, Net | 115,944 | (8,202) | 94,658 | (33,876) | |||||||
Other, Net | 36,074 | 23,434 | 96,779 | 64,869 | |||||||
Total | 4,781,624 | 2,644,844 | 12,700,863 | 7,867,881 | |||||||
Operating Expenses | |||||||||||
Lease and Well | 321,568 | 251,943 | 936,236 | 762,906 | |||||||
Transportation Costs | 196,027 | 183,565 | 550,781 | 548,635 | |||||||
Gathering and Processing Costs | 114,063 | 32,590 | 324,577 | 105,480 | |||||||
Exploration Costs | 32,823 | 30,796 | 115,137 | 122,401 | |||||||
Dry Hole Costs | 358 | 50 | 5,260 | 77 | |||||||
Impairments | 44,617 | 53,677 | 160,934 | 325,798 | |||||||
Marketing Costs | 1,326,974 | 793,536 | 3,853,827 | 2,320,671 | |||||||
Depreciation, Depletion and Amortization | 918,180 | 846,222 | 2,515,445 | 2,527,642 | |||||||
General and Administrative | 111,284 | 111,717 | 310,065 | 317,462 | |||||||
Taxes Other Than Income | 209,043 | 125,912 | 582,395 | 386,319 | |||||||
Total | 3,274,937 | 2,430,008 | 9,354,657 | 7,417,391 | |||||||
Operating Income | 1,506,687 | 214,836 | 3,346,206 | 450,490 | |||||||
Other Income (Expense), Net | 3,308 | 226 | (4,516) | 8,349 | |||||||
Income Before Interest Expense and Income Taxes | 1,509,995 | 215,062 | 3,341,690 | 458,839 | |||||||
Interest Expense, Net | 63,632 | 69,082 | 189,032 | 211,010 | |||||||
Income Before Income Taxes | 1,446,363 | 145,980 | 3,152,658 | 247,829 | |||||||
Income Tax Provision | 255,411 | 45,439 | 626,386 | 95,718 | |||||||
Net Income | $ | 1,190,952 | $ | 100,541 | $ | 2,526,272 | $ | 152,111 | |||
Dividends Declared per Common Share | $ | 0.2200 | $ | 0.1675 | $ | 0.5900 | $ | 0.5025 | |||
EOG RESOURCES, INC. | |||||||||||
Operating Highlights | |||||||||||
(Unaudited) | |||||||||||
Three Months Ended | Nine Months Ended | ||||||||||
September 30, | September 30, | ||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||
Wellhead Volumes and Prices | |||||||||||
Crude Oil and Condensate Volumes (MBbld) (A) | |||||||||||
United States | 409.2 | 327.1 | 382.9 | 324.3 | |||||||
Trinidad | 0.8 | 0.8 | 0.8 | 0.8 | |||||||
Other International (B) | 5.0 | - | 4.1 | 1.0 | |||||||
Total | 415.0 | 327.9 | 387.8 | 326.1 | |||||||
Average Crude Oil and Condensate Prices ($/Bbl) (C) | |||||||||||
United States | $ | 69.53 | $ | 48.06 | $ | 67.35 | $ | 48.61 | |||
Trinidad | 61.71 | 39.42 | 58.91 | 40.24 | |||||||
Other International (B) | 72.81 | - | 71.83 | 51.55 | |||||||
Composite | 69.55 | 48.11 | 67.38 | 48.60 | |||||||
Natural Gas Liquids Volumes (MBbld) (A) | |||||||||||
United States | 127.8 | 87.4 | 113.9 | 84.3 | |||||||
Other International (B) | - | - | - | - | |||||||
Total | 127.8 | 87.4 | 113.9 | 84.3 | |||||||
Average Natural Gas Liquids Prices ($/Bbl) (C) | |||||||||||
United States | $ | 30.09 | $ | 22.38 | $ | 27.71 | $ | 20.87 | |||
Other International (B) | - | - | - | - | |||||||
Composite | 30.09 | 22.38 | 27.71 | 20.87 | |||||||
Natural Gas Volumes (MMcfd) (A) | |||||||||||
United States | 948 | 748 | 905 | 744 | |||||||
Trinidad | 260 | 323 | 278 | 317 | |||||||
Other International (B) | 28 | 25 | 31 | 22 | |||||||
Total | 1,236 | 1,096 | 1,214 | 1,083 | |||||||
Average Natural Gas Prices ($/Mcf) (C) | |||||||||||
United States | $ | 2.67 | $ | 2.20 | $ | 2.66 | $ | 2.22 | |||
Trinidad | 2.88 | 2.04 | 2.91 | 2.33 | |||||||
Other International (B) | 3.83 | 3.74 | 4.10 | 3.72 | |||||||
Composite | 2.74 | (D) | 2.19 | 2.75 | (D) | 2.28 | |||||
Crude Oil Equivalent Volumes (MBoed) (E) | |||||||||||
United States | 695.0 | 539.2 | 647.6 | 532.6 | |||||||
Trinidad | 44.1 | 54.6 | 47.2 | 53.6 | |||||||
Other International (B) | 9.7 | 4.3 | 9.2 | 4.8 | |||||||
Total | 748.8 | 598.1 | 704.0 | 591.0 | |||||||
Total MMBoe (E) | 68.9 | 55.0 | 192.2 | 161.3 | |||||||
(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. | |||||||||||
(C) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 12 to the Condensed Consolidated Financial Statements in EOG's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2018). | |||||||||||
(D) Includes positive revenue adjustments of $0.49 per Mcf and $0.43 per Mcf for the three and nine months ended September 30, 2018, respectively, related to the adoption of ASU 2014-09, "Revenue From Contracts with Customers" (ASU 2014-09). (see Note 1 to the Condensed Consolidated Financial Statements in EOG's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 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 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) | |||||
September 30, | December 31, | ||||
2018 | 2017 | ||||
ASSETS | |||||
Current Assets | |||||
Cash and Cash Equivalents | $ | 1,274,132 | $ | 834,228 | |
Accounts Receivable, Net | 2,151,247 | 1,597,494 | |||
Inventories | 766,964 | 483,865 | |||
Assets from Price Risk Management Activities | 1,569 | 7,699 | |||
Income Taxes Receivable | 320,938 | 113,357 | |||
Other | 302,242 | 242,465 | |||
Total | 4,817,092 | 3,279,108 | |||
Property, Plant and Equipment | |||||
Oil and Gas Properties (Successful Efforts Method) | 56,799,237 | 52,555,741 | |||
Other Property, Plant and Equipment | 4,191,958 | 3,960,759 | |||
Total Property, Plant and Equipment | 60,991,195 | 56,516,500 | |||
Less: Accumulated Depreciation, Depletion and Amortization | (33,043,454) | (30,851,463) | |||
Total Property, Plant and Equipment, Net | 27,947,741 | 25,665,037 | |||
Deferred Income Taxes | 16,880 | 17,506 | |||
Other Assets | 856,023 | 871,427 | |||
Total Assets | $ | 33,637,736 | $ | 29,833,078 | |
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||
Current Liabilities | |||||
Accounts Payable | $ | 2,435,773 | $ | 1,847,131 | |
Accrued Taxes Payable | 249,234 | 148,874 | |||
Dividends Payable | 126,829 | 96,410 | |||
Liabilities from Price Risk Management Activities | 132,618 | 50,429 | |||
Current Portion of Long-Term Debt | 1,262,874 | 356,235 | |||
Other | 217,819 | 226,463 | |||
Total | 4,425,147 | 2,725,542 | |||
Long-Term Debt | 5,171,949 | 6,030,836 | |||
Other Liabilities | 1,302,249 | 1,275,213 | |||
Deferred Income Taxes | 4,199,921 | 3,518,214 | |||
Commitments and Contingencies | |||||
Stockholders' Equity | |||||
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 580,308,937 Shares Issued at September 30, 2018 and 578,827,768 Shares Issued at December 31, 2017 | 205,803 | 205,788 | |||
Additional Paid in Capital | 5,626,259 | 5,536,547 | |||
Accumulated Other Comprehensive Loss | (19,458) | (19,297) | |||
Retained Earnings | 12,778,104 | 10,593,533 | |||
Common Stock Held in Treasury, 478,042 Shares at September 30, 2018 and 350,961 Shares at December 31, 2017 | (52,238) | (33,298) | |||
Total Stockholders' Equity | 18,538,470 | 16,283,273 | |||
Total Liabilities and Stockholders' Equity | $ | 33,637,736 | $ | 29,833,078 | |
EOG RESOURCES, INC. | |||||
Summary Statements of Cash Flows | |||||
(Unaudited; in thousands) | |||||
Nine Months Ended | |||||
September 30, | |||||
2018 | 2017 | ||||
Cash Flows from Operating Activities | |||||
Reconciliation of Net Income to Net Cash Provided by Operating Activities: | |||||
Net Income | $ | 2,526,272 | $ | 152,111 | |
Items Not Requiring (Providing) Cash | |||||
Depreciation, Depletion and Amortization | 2,515,445 | 2,527,642 | |||
Impairments | 160,934 | 325,798 | |||
Stock-Based Compensation Expenses | 116,290 | 101,537 | |||
Deferred Income Taxes | 681,702 | 114,850 | |||
(Gains) Losses on Asset Dispositions, Net | (94,658) | 33,876 | |||
Other, Net | 15,314 | (4,514) | |||
Dry Hole Costs | 5,260 | 77 | |||
Mark-to-Market Commodity Derivative Contracts | |||||
Total (Gains) Losses | 297,735 | (64,860) | |||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts | (180,228) | 4,730 | |||
Other, Net | 1,652 | 270 | |||
Changes in Components of Working Capital and Other Assets and Liabilities | |||||
Accounts Receivable | (553,529) | (25,445) | |||
Inventories | (286,817) | (17,674) | |||
Accounts Payable | 537,525 | 112,894 | |||
Accrued Taxes Payable | (36,891) | (49,967) | |||
Other Assets | (103,334) | (83,940) | |||
Other Liabilities | (14,776) | (69,224) | |||
Changes in Components of Working Capital Associated with Investing and Financing Activities | 95,484 | (120,373) | |||
Net Cash Provided by Operating Activities | 5,683,380 | 2,937,788 | |||
Investing Cash Flows | |||||
Additions to Oil and Gas Properties | (4,571,932) | (2,927,988) | |||
Additions to Other Property, Plant and Equipment | (202,384) | (139,558) | |||
Proceeds from Sales of Assets | 11,582 | 191,593 | |||
Other Investing Activities | (19,993) | - | |||
Changes in Components of Working Capital Associated with Investing Activities | (95,541) | 120,469 | |||
Net Cash Used in Investing Activities | (4,878,268) | (2,755,484) | |||
Financing Cash Flows | |||||
Long-Term Debt Repayments | - | (600,000) | |||
Dividends Paid | (311,075) | (289,261) | |||
Treasury Stock Purchased | (58,558) | (50,374) | |||
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan | 12,098 | 11,174 | |||
Repayment of Capital Lease Obligation | (5,052) | (4,897) | |||
Changes in Components of Working Capital Associated with Financing Activities | 57 | (96) | |||
Net Cash Used in Financing Activities | (362,530) | (933,454) | |||
Effect of Exchange Rate Changes on Cash | (2,678) | (2,607) | |||
Increase (Decrease) in Cash and Cash Equivalents | 439,904 | (753,757) | |||
Cash and Cash Equivalents at Beginning of Period | 834,228 | 1,599,895 | |||
Cash and Cash Equivalents at End of Period | $ | 1,274,132 | $ | 846,138 | |
EOG RESOURCES, INC. | ||||||||||||||
Third Quarter 2018 Well Results by Play | ||||||||||||||
(Unaudited) | ||||||||||||||
Wells Online | Initial Gross 30-Day Average Production Rate | |||||||||||||
Gross | Net | Lateral Length(ft) | Crude Oil and Condensate(Bbld) (A) | Natural GasLiquids(Bbld) (A) | Natural Gas(MMcfd) (A) | Crude Oil Equivalent(Boed) (B) | ||||||||
Delaware Basin | ||||||||||||||
Wolfcamp | 61 | 58 | 7,100 | 1,655 | 505 | 2.9 | 2,640 | |||||||
Bone Spring | 4 | 4 | 5,200 | 1,135 | 270 | 1.6 | 1,675 | |||||||
Leonard | 6 | 5 | 4,500 | 995 | 325 | 1.9 | 1,645 | |||||||
South Texas Eagle Ford | 90 | 83 | 7,300 | 1,235 | 155 | 0.9 | 1,540 | |||||||
South Texas Austin Chalk | 14 | 10 | 5,000 | 1,815 | 340 | 2.0 | 2,485 | |||||||
Powder River Basin Turner | 13 | 11 | 7,500 | 795 | 320 | 3.7 | 1,730 | |||||||
DJ Basin Codell | 25 | 19 | 10,100 | 915 | 105 | 0.4 | 1,090 | |||||||
Williston Basin Bakken/Three Forks | 19 | 12 | 9,400 | 1,135 | 130 | 0.6 | 1,370 | |||||||
Anadarko Basin Woodford Oil Window | 11 | 9 | 8,500 | 720 | 120 | 0.4 | 915 | |||||||
(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 nine-month periods ended September 30, 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 and to eliminate certain adjustments in 2018 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 | ||||||||||||||
September 30, 2018 | September 30, 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) | $1,446,363 | $(255,411) | $1,190,952 | $ 2.05 | $145,980 | $ (45,439) | $100,541 | $ 0.17 | |||||||
Adjustments: | |||||||||||||||
Losses on Mark-to-Market Commodity Derivative Contracts | 52,081 | (11,472) | 40,609 | 0.07 | 6,606 | (2,368) | 4,238 | 0.01 | |||||||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts | (91,894) | 20,241 | (71,653) | (0.12) | 2,139 | (767) | 1,372 | - | |||||||
Add: Net (Gains) Losses on Asset Dispositions | (115,944) | 28,934 | (87,010) | (0.15) | 8,202 | (3,068) | 5,134 | 0.01 | |||||||
Less: Tax Reform Impact | - | (57,127) | (57,127) | (0.10) | - | - | - | - | |||||||
Adjustments to Net Income | (155,757) | (19,424) | (175,181) | (0.30) | 16,947 | (6,203) | 10,744 | 0.02 | |||||||
Adjusted Net Income (Non-GAAP) | $1,290,606 | $(274,835) | $1,015,771 | $ 1.75 | $162,927 | $ (51,642) | $111,285 | $ 0.19 | |||||||
Average Number of Common Shares (GAAP) | |||||||||||||||
Basic | 577,254 | 574,783 | |||||||||||||
Diluted | 581,559 | 578,736 | |||||||||||||
Nine Months Ended | Nine Months Ended | ||||||||||||||
September 30, 2018 | September 30, 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) | $3,152,658 | $(626,386) | $2,526,272 | $ 4.35 | $247,829 | $ (95,718) | $152,111 | $ 0.26 | |||||||
Adjustments: | |||||||||||||||
(Gains) Losses on Mark-to-Market Commodity Derivative Contracts | 297,735 | (65,582) | 232,153 | 0.40 | (64,860) | 23,249 | (41,611) | (0.07) | |||||||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts | (180,228) | 39,699 | (140,529) | (0.24) | 4,730 | (1,695) | 3,035 | 0.01 | |||||||
Add: Net (Gains) Losses on Asset Dispositions | (94,658) | 24,235 | (70,423) | (0.12) | 33,876 | (11,955) | 21,921 | 0.04 | |||||||
Add: Impairments | 20,876 | (4,598) | 16,278 | 0.03 | 161,148 | (57,764) | 103,384 | 0.18 | |||||||
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 | - | |||||||
Less: Tax Reform Impact | - | (63,651) | (63,651) | (0.11) | - | - | - | - | |||||||
Adjustments to Net Income | 43,725 | (69,897) | (26,172) | (0.04) | 148,152 | (52,917) | 95,235 | 0.17 | |||||||
Adjusted Net Income (Non-GAAP) | $3,196,383 | $(696,283) | $2,500,100 | $ 4.31 | $395,981 | $(148,635) | $247,346 | $ 0.43 | |||||||
Average Number of Common Shares (GAAP) | |||||||||||||||
Basic | 576,431 | 574,370 | |||||||||||||
Diluted | 580,442 | 578,453 | |||||||||||||
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 nine-month periods ended September 30, 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 nine months ended September 30, 2018. EOG management uses this information for comparative purposes within the industry. | ||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||
September 30, | September 30, | |||||||||||
2018 | 2017 | 2018 | 2017 | |||||||||
Net Cash Provided by Operating Activities (GAAP) | $ | 2,189,597 | $ | 961,363 | $ | 5,683,380 | $ | 2,937,788 | ||||
Adjustments: | ||||||||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) | 27,032 | 26,132 | 96,716 | 106,268 | ||||||||
Other Non-Current Income Taxes - Net Receivable (Payable) | (129,941) | - | 62,421 | - | ||||||||
Changes in Components of Working Capital and Other Assets | ||||||||||||
and Liabilities | ||||||||||||
Accounts Receivable | 243,778 | 129,231 | 553,529 | 25,445 | ||||||||
Inventories | 94,598 | 11,545 | 286,817 | 17,674 | ||||||||
Accounts Payable | (81,548) | (36,190) | (537,525) | (112,894) | ||||||||
Accrued Taxes Payable | 59,426 | 10,843 | 36,891 | 49,967 | ||||||||
Other Assets | 40,491 | 22,851 | 103,334 | 83,940 | ||||||||
Other Liabilities | (38,392) | 2,355 | 14,776 | 69,224 | ||||||||
Changes in Components of Working Capital Associated with | ||||||||||||
Investing and Financing Activities | (122,763) | 41,235 | (95,484) | 120,373 | ||||||||
Discretionary Cash Flow (Non-GAAP) | $ | 2,282,278 | $ | 1,169,365 | $ | 6,204,855 | $ | 3,297,785 | ||||
Discretionary Cash Flow (Non-GAAP) - Percentage Increase | 95% | 88% | ||||||||||
Discretionary Cash Flow (Non-GAAP) | $ | 2,282,278 | $ | 6,204,855 | ||||||||
Less: | ||||||||||||
Total Cash Expenditures Excluding Acquisitions (Non-GAAP)(a) | (1,671,922) | (4,869,951) | ||||||||||
Dividends Paid (GAAP) | (107,465) | (311,075) | ||||||||||
Free Cash Flow (Non-GAAP) | $ | 502,891 | $ | 1,023,829 | ||||||||
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Expenditures Excluding Acquisitions (Non-GAAP) for the three months and nine months ended September 30, 2018: | ||||||||||||
Total Expenditures (GAAP) | $ | 1,828,348 | $ | 5,201,921 | ||||||||
Less: | ||||||||||||
Asset Retirement Costs | (10,834) | (41,789) | ||||||||||
Non-Cash Expenditures of Other Property, Plant and Equipment | (1,257) | (48,937) | ||||||||||
Non-Cash Acquisition Costs of Unproved Properties | (101,821) | (161,823) | ||||||||||
Acquisition Costs of Proved Properties | (42,514) | (79,421) | ||||||||||
Total Cash Expenditures Excluding Acquisitions (Non-GAAP) | $ | 1,671,922 | $ | 4,869,951 | ||||||||
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 nine-month periods ended September 30, 2018 and 2017 reported Net Income (GAAP) to Earnings Before Interest Expense (Net), Income Taxes (Income Tax Provision), 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), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||
Three Months Ended | Nine Months Ended | ||||||||||
September 30, | September 30, | ||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||
Net Income (GAAP) | $ | 1,190,952 | $ | 100,541 | $ | 2,526,272 | $ | 152,111 | |||
Adjustments: | |||||||||||
Interest Expense, Net | 63,632 | 69,082 | 189,032 | 211,010 | |||||||
Income Tax Provision | 255,411 | 45,439 | 626,386 | 95,718 | |||||||
Depreciation, Depletion and Amortization | 918,180 | 846,222 | 2,515,445 | 2,527,642 | |||||||
Exploration Costs | 32,823 | 30,796 | 115,137 | 122,401 | |||||||
Dry Hole Costs | 358 | 50 | 5,260 | 77 | |||||||
Impairments | 44,617 | 53,677 | 160,934 | 325,798 | |||||||
EBITDAX (Non-GAAP) | 2,505,973 | 1,145,807 | 6,138,466 | 3,434,757 | |||||||
Total (Gains) Losses on MTM Commodity Derivative Contracts | 52,081 | 6,606 | 297,735 | (64,860) | |||||||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts | (91,894) | 2,139 | (180,228) | 4,730 | |||||||
(Gains) Losses on Asset Dispositions, Net | (115,944) | 8,202 | (94,658) | 33,876 | |||||||
Adjusted EBITDAX (Non-GAAP) | $ | 2,350,216 | $ | 1,162,754 | $ | 6,161,315 | $ | 3,408,503 | |||
Adjusted EBITDAX (Non-GAAP) - Percentage Increase | 102% | 81% | |||||||||
EOG RESOURCES, INC. | |||||
Quantitative Reconciliation of Net Debt (Non-GAAP) and Total | |||||
Capitalization (Non-GAAP) as Used in the Calculation of | |||||
The Net Debt-to-Total Capitalization Ratio (Non-GAAP) to | |||||
Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) | |||||
(Unaudited; in millions, except ratio data) | |||||
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. | |||||
At | At | ||||
September 30, | December 31, | ||||
2018 | 2017 | ||||
Total Stockholders' Equity - (a) | $ | 18,538 | $ | 16,283 | |
Current and Long-Term Debt (GAAP) - (b) | 6,435 | 6,387 | |||
Less: Cash | (1,274) | (834) | |||
Net Debt (Non-GAAP) - (c) | 5,161 | 5,553 | |||
Total Capitalization (GAAP) - (a) + (b) | $ | 24,973 | $ | 22,670 | |
Total Capitalization (Non-GAAP) - (a) + (c) | $ | 23,699 | $ | 21,836 | |
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] | 26% | 28% | |||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] | 22% | 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 October 26, 2018. The weighted average price differential expressed in $/Bbl represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | |||||||||||
Midland Differential Basis Swap Contracts | |||||||||||
Weighted | |||||||||||
Average Price | |||||||||||
Volume | Differential | ||||||||||
(Bbld) | ($/Bbl) | ||||||||||
2018 | |||||||||||
January 1, 2018 through November 30, 2018 (closed) | 15,000 | $ 1.063 | |||||||||
December 2018 | 15,000 | 1.063 | |||||||||
2019 | |||||||||||
January 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 October 26, 2018. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | |||||||||||
Gulf Coast Differential Basis Swap Contracts | |||||||||||
Weighted | |||||||||||
Average Price | |||||||||||
Volume | Differential | ||||||||||
(Bbld) | ($/Bbl) | ||||||||||
2018 | |||||||||||
January 1, 2018 through September 30, 2018 (closed) | 37,000 | $ 3.818 | |||||||||
October 1, 2018 through November 30, 2018 (closed) | 52,000 | 3.911 | |||||||||
December 2018 | 52,000 | 3.911 | |||||||||
2019 | |||||||||||
January 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 October 26, 2018, 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 September 30, 2018 (closed) | 134,000 | $ 60.04 | |||||||||
October 1, 2018 through December 31, 2018 | 134,000 | 60.04 | |||||||||
Presented below is a comprehensive summary of EOG's natural gas price swap contracts through October 26, 2018, 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 October 31, 2018 (closed) | 35,000 | $ 3.00 | |||||||||
November 2018 | 35,000 | 3.00 | |||||||||
EOG has sold call options which establish a ceiling price for the sale of notional volumes of natural gas as specified in the call option contracts. The call options require that EOG pay the difference between the call option strike price and either the average or last business day NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the call option strike price. | |||||||||||
In addition, EOG has purchased put options which establish a floor price for the sale of notional volumes of natural gas as specified in the put option contracts. The put options grant EOG the right to receive the difference between the put option strike price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the put option strike price. Presented below is a comprehensive summary of EOG's natural gas call and put option contracts through October 26, 2018, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||||||
Natural Gas Option Contracts | |||||||||||
Call Options Sold | Put Options Purchased | ||||||||||
Weighted | Weighted | ||||||||||
Volume | Average Price | Volume | Average Price | ||||||||
(MMBtud) | ($/MMBtu) | (MMBtud) | ($/MMBtu) | ||||||||
2018 | |||||||||||
March 1, 2018 through October 31, 2018 (closed) | 120,000 | $ 3.38 | 96,000 | $ 2.94 | |||||||
November 2018 | 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 (Loss) | ||||||||||||||
(Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculations of | ||||||||||||||
Return on Capital Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest Expense (GAAP), | ||||||||||||||
Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively | ||||||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||||||
The following chart reconciles Net Interest Expense (GAAP), Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Loss) (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income (Loss), Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||||||
2017 | 2016 | 2015 | 2014 | 2013 | ||||||||||
Return on Capital Employed (ROCE) (Non-GAAP) | ||||||||||||||
Net Interest Expense (GAAP) | $ | 274 | $ | 282 | $ | 237 | $ | 201 | ||||||
Tax Benefit Imputed (based on 35%) | (96) | (99) | (83) | (70) | ||||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 178 | $ | 183 | $ | 154 | $ | 131 | ||||||
Net Income (Loss) (GAAP) - (b) | $ | 2,583 | $ | (1,097) | $ | (4,525) | $ | 2,915 | ||||||
Adjustments to Net Income (Loss), Net of Tax (See Accompanying Schedules) | (1,934) | (a) | 204 | (b) | 4,559 | (c) | (199) | (d) | ||||||
Adjusted Net Income (Loss) (Non-GAAP) - (c) | $ | 649 | $ | (893) | $ | 34 | $ | 2,716 | ||||||
Total Stockholders' Equity Before Retained Earnings Adjustment (GAAP) - (d) | $ | 16,283 | $ | 13,982 | $ | 12,943 | $ | 17,713 | $ | 15,418 | ||||
Less: Tax Reform Impact | (2,169) | - | - | - | - | |||||||||
Total Stockholders' Equity (Non-GAAP) - (e) | $ | 14,114 | $ | 13,982 | $ | 12,943 | $ | 17,713 | $ | 15,418 | ||||
Average Total Stockholders' Equity (GAAP) * - (f) | $ | 15,133 | $ | 13,463 | $ | 15,328 | $ | 16,566 | ||||||
Average Total Stockholders' Equity (Non-GAAP) * - (g) | $ | 14,048 | $ | 13,463 | $ | 15,328 | $ | 16,566 | ||||||
Current and Long-Term Debt (GAAP) - (h) | $ | 6,387 | $ | 6,986 | $ | 6,655 | $ | 5,906 | $ | 5,909 | ||||
Less: Cash | (834) | (1,600) | (719) | (2,087) | (1,318) | |||||||||
Net Debt (Non-GAAP) - (i) | $ | 5,553 | $ | 5,386 | $ | 5,936 | $ | 3,819 | $ | 4,591 | ||||
Total Capitalization (GAAP) - (d) + (h) | $ | 22,670 | $ | 20,968 | $ | 19,598 | $ | 23,619 | $ | 21,327 | ||||
Total Capitalization (Non-GAAP) - (e) + (i) | $ | 19,667 | $ | 19,368 | $ | 18,879 | $ | 21,532 | $ | 20,009 | ||||
Average Total Capitalization (Non-GAAP) * - (j) | $ | 19,518 | $ | 19,124 | $ | 20,206 | $ | 20,771 | ||||||
ROCE (GAAP Net Income) - [(a) + (b)] / (j) | 14.1% | -4.8% | -21.6% | 14.7% | ||||||||||
ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (j) | 4.2% | -3.7% | 0.9% | 13.7% | ||||||||||
Return on Equity (ROE) | ||||||||||||||
ROE (GAAP) (GAAP Net Income) - (b) / (f) | 17.1% | -8.1% | -29.5% | 17.6% | ||||||||||
ROE (Non-GAAP) (Non-GAAP Adjusted Net Income) - (c) / (g) | 4.6% | -6.6% | 0.2% | 16.4% | ||||||||||
* Average for the current and immediately preceding year | ||||||||||||||
Adjustments to Net Income (Loss) (GAAP) | ||||||||||||||
(a) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2017: | ||||||||||||||
Year Ended December 31, 2017 | ||||||||||||||
Before | Income Tax | After | ||||||||||||
Tax | Impact | Tax | ||||||||||||
Adjustments: | ||||||||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact | $ | (12) | $ | 4 | $ | (8) | ||||||||
Add: Impairments of Certain Assets | 261 | (93) | 168 | |||||||||||
Add: Net Losses on Asset Dispositions | 99 | (35) | 64 | |||||||||||
Add: Legal Settlement - Early Lease Termination | 10 | (4) | 6 | |||||||||||
Add: Joint Venture Transaction Costs | 3 | (1) | 2 | |||||||||||
Add: Joint Interest Billings Deemed Uncollectible | 5 | (2) | 3 | |||||||||||
Less: Tax Reform Impact | - | (2,169) | (2,169) | |||||||||||
Total | $ | 366 | $ | (2,300) | $ | (1,934) | ||||||||
(b) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2016: | ||||||||||||||
Year Ended December 31, 2016 | ||||||||||||||
Before | Income Tax | After | ||||||||||||
Tax | Impact | Tax | ||||||||||||
Adjustments: | ||||||||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact | $ | 77 | $ | (28) | $ | 49 | ||||||||
Add: Impairments of Certain Assets | 321 | (113) | 208 | |||||||||||
Less: Net Gains on Asset Dispositions | (206) | 62 | (144) | |||||||||||
Add: Trinidad Tax Settlement | - | 43 | 43 | |||||||||||
Add: Voluntary Retirement Expense | 42 | (15) | 27 | |||||||||||
Add: Acquisition - State Apportionment Change | - | 16 | 16 | |||||||||||
Add: Acquisition Costs | 5 | - | 5 | |||||||||||
Total | $ | 239 | $ | (35) | $ | 204 | ||||||||
(c) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2015: | ||||||||||||||
Year Ended December 31, 2015 | ||||||||||||||
Before | Income Tax | After | ||||||||||||
Tax | Impact | Tax | ||||||||||||
Adjustments: | ||||||||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact | $ | 668 | $ | (238) | $ | 430 | ||||||||
Add: Impairments of Certain Assets | 6,308 | (2,183) | 4,125 | |||||||||||
Less: Texas Margin Tax Rate Reduction | - | (20) | (20) | |||||||||||
Add: Legal Settlement - Early Leasehold Termination | 19 | (6) | 13 | |||||||||||
Add: Severance Costs | 9 | (3) | 6 | |||||||||||
Add: Net Losses on Asset Dispositions | 9 | (4) | 5 | |||||||||||
Total | $ | 7,013 | $ | (2,454) | $ | 4,559 | ||||||||
(d) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2014: | ||||||||||||||
Year Ended December 31, 2014 | ||||||||||||||
Before | Income Tax | After | ||||||||||||
Tax | Impact | Tax | ||||||||||||
Adjustments: | ||||||||||||||
Less: Mark-to-Market Commodity Derivative Contracts Impact | $ | (800) | $ | 285 | $ | (515) | ||||||||
Add: Impairments of Certain Assets | 824 | (271) | 553 | |||||||||||
Less: Net Gains on Asset Dispositions | (508) | 21 | (487) | |||||||||||
Add: Tax Expense Related to the Repatriation of Accumulated Foreign Earnings in Future Years | - | 250 | 250 | |||||||||||
Total | $ | (484) | $ | 285 | $ | (199) | ||||||||
EOG RESOURCES, INC. | |||||||||||||||||
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. | |||||||||||||||||
2013 | 2012 | 2011 | 2010 | 2009 | 2008 | ||||||||||||
Return on Capital Employed (ROCE) (Non-GAAP) | |||||||||||||||||
(Calculated Using GAAP Net Income) | |||||||||||||||||
Net Interest Expense (GAAP) | $ | 235 | $ | 214 | $ | 210 | $ | 130 | $ | 101 | $ | 52 | |||||
Tax Benefit Imputed (based on 35%) | (82) | (75) | (74) | (46) | (35) | (18) | |||||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 153 | $ | 139 | $ | 136 | $ | 84 | $ | 66 | $ | 34 | |||||
Net Income (Loss) (GAAP) - (b) | $ | 2,197 | $ | 570 | $ | 1,091 | $ | 161 | $ | 547 | $ | 2,437 | |||||
Total Stockholders' Equity (GAAP) - (d) | $ | 15,418 | $ | 13,285 | $ | 12,641 | $ | 10,232 | $ | 9,998 | $ | 9,015 | |||||
Average Total Stockholders' Equity (GAAP) * - (f) | $ | 14,352 | $ | 12,963 | $ | 11,437 | $ | 10,115 | $ | 9,507 | $ | 8,003 | |||||
Current and Long-Term Debt (GAAP) - (h) | $ | 5,909 | $ | 6,312 | $ | 5,009 | $ | 5,223 | $ | 2,797 | $ | 1,897 | |||||
Less: Cash | (1,318) | (876) | (616) | (789) | (686) | (331) | |||||||||||
Net Debt (Non-GAAP) - (i) | $ | 4,591 | $ | 5,436 | $ | 4,393 | $ | 4,434 | $ | 2,111 | $ | 1,566 | |||||
Total Capitalization (GAAP) - (d) + (h) | $ | 21,327 | $ | 19,597 | $ | 17,650 | $ | 15,455 | $ | 12,795 | $ | 10,912 | |||||
Total Capitalization (Non-GAAP) - (d) + (i) | $ | 20,009 | $ | 18,721 | $ | 17,034 | $ | 14,666 | $ | 12,109 | $ | 10,581 | |||||
Average Total Capitalization (Non-GAAP) * - (j) | $ | 19,365 | $ | 17,878 | $ | 15,850 | $ | 13,388 | $ | 11,345 | $ | 9,351 | |||||
ROCE (GAAP Net Income) - [(a) + (b)] / (j) | 12.1% | 4.0% | 7.7% | 1.8% | 5.4% | 26.4% | |||||||||||
Return on Equity (ROE) (GAAP) | |||||||||||||||||
ROE (GAAP Net Income) - (b) / (f) | 15.3% | 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 | 2002 | ||||||||||||
Return on Capital Employed (ROCE) (Non-GAAP) | |||||||||||||||||
(Calculated Using GAAP Net Income) | |||||||||||||||||
Net Interest Expense (GAAP) | $ | 47 | $ | 43 | $ | 63 | $ | 63 | $ | 59 | $ | 60 | |||||
Tax Benefit Imputed (based on 35%) | (16) | (15) | (22) | (22) | (21) | (21) | |||||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 31 | $ | 28 | $ | 41 | $ | 41 | $ | 38 | $ | 39 | |||||
Net Income (Loss) (GAAP) - (b) | $ | 1,090 | $ | 1,300 | $ | 1,260 | $ | 625 | $ | 430 | $ | 87 | |||||
Total Stockholders' Equity (GAAP)- (d) | $ | 6,990 | $ | 5,600 | $ | 4,316 | $ | 2,945 | $ | 2,223 | $ | 1,672 | |||||
Average Total Stockholders' Equity (GAAP) * - (f) | $ | 6,295 | $ | 4,958 | $ | 3,631 | $ | 2,584 | $ | 1,948 | $ | 1,658 | |||||
Current and Long-Term Debt (GAAP) - (h) | $ | 1,185 | $ | 733 | $ | 985 | $ | 1,078 | $ | 1,109 | $ | 1,145 | |||||
Less: Cash | (54) | (218) | (644) | (21) | (4) | (10) | |||||||||||
Net Debt (Non-GAAP) - (i) | $ | 1,131 | $ | 515 | $ | 341 | $ | 1,057 | $ | 1,105 | $ | 1,135 | |||||
Total Capitalization (GAAP) - (d) + (h) | $ | 8,175 | $ | 6,333 | $ | 5,301 | $ | 4,023 | $ | 3,332 | $ | 2,817 | |||||
Total Capitalization (Non-GAAP) - (d) + (i) | $ | 8,121 | $ | 6,115 | $ | 4,657 | $ | 4,002 | $ | 3,328 | $ | 2,807 | |||||
Average Total Capitalization (Non-GAAP) * - (j) | $ | 7,118 | $ | 5,386 | $ | 4,330 | $ | 3,665 | $ | 3,068 | $ | 2,652 | |||||
ROCE (GAAP Net Income) - [(a) + (b)] / (j) | 15.7% | 24.7% | 30.0% | 18.2% | 15.3% | 4.8% | |||||||||||
Return on Equity (ROE) (GAAP) | |||||||||||||||||
ROE (GAAP Net Income) - (b) / (f) | 17.3% | 26.2% | 34.7% | 24.2% | 22.1% | 5.2% | |||||||||||
* 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. | |||||||||||||||||
2001 | 2000 | 1999 | 1998 | 1997 | |||||||||||||
Return on Capital Employed (ROCE) (Non-GAAP) | |||||||||||||||||
(Calculated Using GAAP Net Income) | |||||||||||||||||
Net Interest Expense (GAAP) | $ | 45 | $ | 61 | $ | 62 | $ | 49 | |||||||||
Tax Benefit Imputed (based on 35%) | (16) | (21) | (22) | (17) | |||||||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 29 | $ | 40 | $ | 40 | $ | 32 | |||||||||
Net Income (Loss) (GAAP) - (b) | $ | 399 | $ | 397 | $ | 569 | $ | 56 | |||||||||
Total Stockholders' Equity (GAAP)- (d) | $ | 1,643 | $ | 1,381 | $ | 1,130 | $ | 1,280 | $ | 1,281 | |||||||
Average Total Stockholders' Equity (GAAP) * - (f) | $ | 1,512 | $ | 1,256 | $ | 1,205 | $ | 1,281 | |||||||||
Current and Long-Term Debt (GAAP) - (h) | $ | 856 | $ | 859 | $ | 990 | $ | 1,143 | $ | 745 | |||||||
Less: Cash | (3) | (20) | (25) | (6) | (9) | ||||||||||||
Net Debt (Non-GAAP) - (i) | $ | 853 | $ | 839 | $ | 965 | $ | 1,137 | $ | 736 | |||||||
Total Capitalization (GAAP) - (d) + (h) | $ | 2,499 | $ | 2,240 | $ | 2,120 | $ | 2,423 | $ | 2,026 | |||||||
Total Capitalization (Non-GAAP) - (d) + (i) | $ | 2,496 | $ | 2,220 | $ | 2,095 | $ | 2,417 | $ | 2,017 | |||||||
Average Total Capitalization (Non-GAAP) * - (j) | $ | 2,358 | $ | 2,158 | $ | 2,256 | $ | 2,217 | |||||||||
ROCE (GAAP Net Income) - [(a) + (b)] / (j) | 18.2% | 20.2% | 27.0% | 4.0% | |||||||||||||
Return on Equity (ROE) (GAAP) | |||||||||||||||||
ROE (GAAP Net Income) - (b) / (f) | 26.4% | 31.6% | 47.2% | 4.4% | |||||||||||||
* 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-To-Date (YTD) | Year Ended | ||||||||||
September 30, | December 31, | ||||||||||
2018 | 2017 | 2016 | 2015 | 2014 | |||||||
Cash Operating Expenses (GAAP)* | |||||||||||
Lease and Well | $ 936,236 | $ 1,044,847 | $ 927,452 | $ 1,182,282 | $ 1,416,413 | ||||||
Transportation Costs | 550,781 | 740,352 | 764,106 | 849,319 | 972,176 | ||||||
General and Administrative | 310,065 | 434,467 | 394,815 | 366,594 | 402,010 | ||||||
Cash Operating Expenses | 1,797,082 | 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) | $ 1,797,082 | $ 2,201,880 | $ 2,039,219 | $ 2,378,840 | $ 2,790,599 | ||||||
Volume - Thousand Barrels of Oil Equivalent - (b) | 192,182 | 222,251 | 204,929 | 208,862 | 217,073 | ||||||
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - (a) / (b) | $ 9.35 | $ 9.91 | (c) | $ 9.95 | (d) | $ 11.39 | (e) | $ 12.86 | (f) | ||
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - Percentage Decrease | |||||||||||
YTD 2017 compared to YTD 2016 - [(c) - (d)] / (d) | 0% | ||||||||||
YTD 2017 compared to YTD 2015 - [(c) - (e)] / (e) | -13% | ||||||||||
YTD 2017 compared to YTD 2014 - [(c) - (f)] / (f) | -23% | ||||||||||
* 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) | ||||||||
Year Ended | ||||||||
December 31, | ||||||||
2014 | 2015 | 2016 | 2017 | |||||
Volume - Thousand Barrels of Oil Equivalent | 217,073 | 208,862 | 204,929 | 222,251 | ||||
Total Wellhead Revenues | $ 12,592,917 | $ 6,403,258 | $ 5,496,743 | $ 7,907,891 | ||||
Composite Average Wellhead Revenue per Boe | $ 58.01 | $ 30.66 | $ 26.82 | $ 35.58 | ||||
Operating Costs | ||||||||
Lease and Well | $ 1,416,413 | $ 1,182,282 | $ 927,452 | $ 1,044,847 | ||||
Transportation Costs | 972,176 | 849,319 | 764,106 | 740,352 | ||||
Gathering and Processing Costs | 145,800 | 146,156 | 122,901 | 148,775 | ||||
General and Administrative | 402,010 | 366,594 | 394,815 | 434,467 | ||||
Less: Voluntary Retirement Expense | - | - | (42,054) | - | ||||
Less: Acquisition Costs | - | - | (5,100) | - | ||||
Less: Legal Settlement - Early Leasehold Termination | - | (19,355) | - | (10,202) | ||||
Less: Joint Venture Transaction Costs | - | - | - | (3,056) | ||||
Less: Joint Interest Billings Deemed Uncollectible | - | - | - | (4,528) | ||||
General and Administrative (Non-GAAP) | 402,010 | 347,239 | 347,661 | 416,681 | ||||
Taxes Other Than Income | 757,564 | 421,744 | 349,710 | 544,662 | ||||
Interest Expense, Net | 201,458 | 237,393 | 281,681 | 274,372 | ||||
Total Cash Operating Cost (Non-GAAP) (excluding DD&A and Exploration Costs) | $ 3,895,421 | $ 3,184,133 | $ 2,793,511 | $ 3,169,689 | ||||
Total Cash Operating Cost per Boe (Non-GAAP) (excluding DD&A and Exploration Costs) | $ 17.95 | $ 15.25 | $ 13.64 | $ 14.25 | ||||
Composite Average Margin per Boe (Non- GAAP) (excluding DD&A and Exploration Costs) | $ 40.06 | $ 15.41 | $ 13.18 | $ 21.33 | ||||
Depreciation, Depletion and Amortization (DD&A) | 3,997,041 | 3,313,644 | 3,553,417 | 3,409,387 | ||||
Total Operating Cost (Non-GAAP) (excluding Exploration Costs) | $ 7,892,462 | $ 6,497,777 | $ 6,346,928 | $ 6,579,076 | ||||
Total Operating Cost per Boe (Non-GAAP) (excluding Exploration Costs) | $ 36.38 | $ 31.11 | $ 30.98 | $ 29.59 | ||||
Composite Average Margin per Boe (Non-GAAP) (excluding Exploration Costs) | $ 21.63 | $ (0.45) | $ (4.16) | $ 5.99 | ||||
Total Exploration Costs | 976,453 | 6,777,786 | 755,877 | 629,191 | ||||
Less: Impairments | (824,312) | (6,307,593) | (320,617) | (261,452) | ||||
Total Exploration Costs (Non-GAAP) | 152,141 | 470,193 | 435,260 | 367,739 | ||||
Total Operating Cost (Non-GAAP) (including Exploration Costs) | $ 8,044,603 | $ 6,967,970 | $ 6,782,188 | $ 6,946,815 | ||||
Total Operating Cost per Boe (Non-GAAP) (including Exploration Costs) | $ 37.08 | $ 33.36 | $ 33.10 | $ 31.24 | ||||
Composite Average Margin per Boe (Non-GAAP) (including Exploration Costs) | $ 20.93 | $ (2.70) | $ (6.28) | $ 4.34 | ||||
EOG RESOURCES, INC. | ||||||||
Cost per Barrel of Oil Equivalent (Boe) | ||||||||
(Unaudited; in thousands, except per Boe amounts) | ||||||||
Three Months Ended | Year-To-Date | |||||||
March 31, | June 30, | September 30, | September 30, | |||||
2018 | 2018 | 2018 | 2018 | |||||
Volume - Thousand Barrels of Oil Equivalent | 59,394 | 63,898 | 68,890 | 192,182 | ||||
Total Wellhead Revenues | $ 2,622,489 | $ 2,964,727 | $ 3,320,695 | $ 8,907,911 | ||||
Composite Average Wellhead Revenue per Boe | $ 44.15 | $ 46.40 | $ 48.20 | $ 46.35 | ||||
Operating Costs | ||||||||
Lease and Well | $ 300,064 | $ 314,604 | $ 321,568 | $ 936,236 | ||||
Transportation Costs | 176,957 | 177,797 | 196,027 | 550,781 | ||||
Gathering and Processing Costs | 101,345 | 109,169 | 114,063 | 324,577 | ||||
General and Administrative | 94,698 | 104,083 | 111,284 | 310,065 | ||||
Taxes Other Than Income | 179,084 | 194,268 | 209,043 | 582,395 | ||||
Interest Expense, Net | 61,956 | 63,444 | 63,632 | 189,032 | ||||
Total Cash Operating Cost (excluding DD&A and Exploration Costs) | $ 914,104 | $ 963,365 | $ 1,015,617 | $ 2,893,086 | ||||
Total Cash Operating Cost per Boe (excluding DD&A and Exploration Costs) | $ 15.39 | $ 15.07 | $ 14.75 | $ 15.05 | ||||
Composite Average Margin per Boe (excluding DD&A and Exploration Costs) | $ 28.76 | $ 31.33 | $ 33.45 | $ 31.30 | ||||
Depreciation, Depletion and Amortization (DD&A) | 748,591 | 848,674 | 918,180 | 2,515,445 | ||||
Total Operating Cost (excluding Exploration Costs) | $ 1,662,695 | $ 1,812,039 | $ 1,933,797 | $ 5,408,531 | ||||
Total Operating Cost per Boe (excluding Exploration Costs) | $ 27.99 | $ 28.35 | $ 28.08 | $ 28.14 | ||||
Composite Average Margin per Boe (excluding Exploration Costs) | $ 16.16 | $ 18.05 | $ 20.12 | $ 18.21 | ||||
Total Exploration Costs | 99,445 | 104,088 | 77,798 | 281,331 | ||||
Less: Impairments | (20,876) | - | - | (20,876) | ||||
Total Exploration Costs (Non-GAAP) | 78,569 | 104,088 | 77,798 | 260,455 | ||||
Total Operating Cost (Non-GAAP) (including Exploration Costs) | $ 1,741,264 | $ 1,916,127 | $ 2,011,595 | $ 5,668,986 | ||||
Total Operating Cost per Boe (Non-GAAP) (including Exploration Costs) | $ 29.31 | $ 29.98 | $ 29.21 | $ 29.50 | ||||
Composite Average Margin per Boe (Non-GAAP) (including Exploration Costs) | $ 14.84 | $ 16.42 | $ 18.99 | $ 16.85 | ||||
EOG RESOURCES, INC. | |||||||||||
Fourth Quarter and Full Year 2018 Forecast and Benchmark Commodity Pricing | |||||||||||
(a) Fourth Quarter and Full Year 2018 Forecast | |||||||||||
The forecast items for the fourth quarter and full year 2018 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. | |||||||||||
(b) Benchmark Commodity Pricing | |||||||||||
EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. | |||||||||||
EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month. | |||||||||||
Estimated Ranges | |||||||||||
(Unaudited) | |||||||||||
4Q 2018 | Full Year 2018 | ||||||||||
Daily Sales Volumes | |||||||||||
Crude Oil and Condensate Volumes (MBbld) | |||||||||||
United States | 425.0 | - | 430.0 | 393.5 | - | 394.8 | |||||
Trinidad | 0.5 | - | 0.7 | 0.7 | - | 0.9 | |||||
Other International | 3.0 | - | 5.0 | 3.8 | - | 4.3 | |||||
Total | 428.5 | - | 435.7 | 398.0 | - | 400.0 | |||||
Natural Gas Liquids Volumes (MBbld) | |||||||||||
Total | 115.0 | - | 125.0 | 114.1 | - | 116.7 | |||||
Natural Gas Volumes (MMcfd) | |||||||||||
United States | 975 | - | 1,025 | 923 | - | 935 | |||||
Trinidad | 220 | - | 250 | 264 | - | 271 | |||||
Other International | 30 | - | 40 | 30 | - | 33 | |||||
Total | 1,225 | - | 1,315 | 1,217 | - | 1,239 | |||||
Crude Oil Equivalent Volumes (MBoed) | |||||||||||
United States | 702.5 | - | 725.8 | 661.5 | - | 667.3 | |||||
Trinidad | 37.2 | - | 42.4 | 44.6 | - | 46.1 | |||||
Other International | 8.0 | - | 11.7 | 8.8 | - | 9.8 | |||||
Total | 747.7 | - | 779.9 | 714.9 | - | 723.2 | |||||
Estimated Ranges | |||||||||||
(Unaudited) | |||||||||||
4Q 2018 | Full Year 2018 | ||||||||||
Operating Costs | |||||||||||
Unit Costs ($/Boe) | |||||||||||
Lease and Well | $ | 4.45 | - | $ | 4.85 | $ | 4.80 | - | $ | 4.90 | |
Transportation Costs | $ | 2.45 | - | $ | 2.85 | $ | 2.75 | - | $ | 2.85 | |
Depreciation, Depletion and Amortization | $ | 13.60 | - | $ | 13.95 | $ | 13.23 | - | $ | 13.32 | |
Expenses ($MM) | |||||||||||
Exploration, Dry Hole and Impairment | $ | 105 | - | $ | 125 | $ | 365 | - | $ | 385 | |
General and Administrative | $ | 105 | - | $ | 115 | $ | 415 | - | $ | 425 | |
Gathering and Processing | $ | 110 | - | $ | 130 | $ | 435 | - | $ | 455 | |
Capitalized Interest | $ | 5 | - | $ | 7 | $ | 23 | - | $ | 25 | |
Net Interest | $ | 55 | - | $ | 58 | $ | 244 | - | $ | 247 | |
Taxes Other Than Income (% of Wellhead Revenue) | 6.5% | - | 6.8% | 6.5% | - | 6.7% | |||||
Income Taxes | |||||||||||
Effective Rate | 20% | - | 25% | 19% | - | 24% | |||||
Current Tax (Benefit) / Expense ($MM) | $ | (70) | - | $ | (30) | $ | (190) | - | $ | (150) | |
Capital Expenditures (Excluding Acquisitions, $MM) | |||||||||||
Exploration and Development, Excluding Facilities | $ | 4,900 | - | $ | 5,000 | ||||||
Exploration and Development Facilities | $ | 600 | - | $ | 650 | ||||||
Gathering, Processing and Other | $ | 300 | - | $ | 350 | ||||||
Pricing - (Refer to Benchmark Commodity Pricing in text) | |||||||||||
Crude Oil and Condensate ($/Bbl) | |||||||||||
Differentials | |||||||||||
United States - above (below) WTI | $ | 0.00 | - | $ | 2.00 | $ | 0.50 | - | $ | 1.05 | |
Trinidad - above (below) WTI | $ | (11.00) | - | $ | (9.00) | $ | (9.00) | - | $ | (8.00) | |
Other International - above (below) WTI | $ | 0.00 | - | $ | 7.00 | $ | 3.80 | - | $ | 5.60 | |
Natural Gas Liquids | |||||||||||
Realizations as % of WTI | 38% | - | 46% | 41% | - | 43% | |||||
Natural Gas ($/Mcf) | |||||||||||
Differentials | |||||||||||
United States - above (below) NYMEX Henry Hub | $ | (0.40) | - | $ | 0.00 | $ | (0.25) | - | $ | (0.15) | |
Realizations | |||||||||||
Trinidad | $ | 2.40 | - | $ | 2.80 | $ | 2.80 | - | $ | 2.90 | |
Other International | $ | 4.15 | - | $ | 4.65 | $ | 4.10 | - | $ | 4.25 | |
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-announces-outstanding-third-quarter-2018-results-300742708.html
SOURCE EOG Resources, Inc.