Delaware (State or other jurisdiction of incorporation) | 1-9743 (Commission File Number) | 47-0684736 (I.R.S. Employer Identification No.) |
EOG RESOURCES, INC. (Registrant) | ||
Date: May 3, 2018 | By: | /s/ TIMOTHY K. DRIGGERS Timothy K. Driggers Executive Vice President and Chief Financial Officer (Principal Financial Officer and Duly Authorized Officer) |
EOG Resources, Inc. | P.O. Box 4362, Houston, TX 77210-4362 |
News Release | |
For Further Information Contact: | Investors |
David J. Streit | |
(713) 571-4902 | |
Neel Panchal | |
(713) 571-4884 | |
W. John Wagner | |
(713) 571-4404 | |
Media and Investors | |
Kimberly M. Ehmer | |
(713) 571-4676 |
• | Reports Strong Operating Results |
- | Achieves Record Returns on First Quarter Capital Investments |
- | U.S. Oil Production Near High End of Target Range |
- | U.S. Realized Crude Oil Price Exceeds WTI NYMEX Average |
- | Per-Unit Transportation and DD&A Expenses Below Targets |
• | Maintains Full-Year $5.4-$5.8 Billion Exploration and Development Expenditure Target |
- | On Track to Reduce Well Costs 5 Percent in 2018 |
• | Reiterates Full-Year 2018 Oil Production Growth Target of 16-20 Percent |
• | Targets $3 Billion Debt Reduction and Higher Dividend Growth Rate |
• | 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. |
EOG RESOURCES, INC. Financial Report (Unaudited; in millions, except per share data) | |||||||
Three Months Ended | |||||||
March 31, | |||||||
2018 | 2017 | ||||||
Operating Revenues and Other | $ | 3,681.2 | $ | 2,610.6 | |||
Net Income | $ | 638.6 | $ | 28.5 | |||
Net Income Per Share | |||||||
Basic | $ | 1.11 | $ | 0.05 | |||
Diluted | $ | 1.10 | $ | 0.05 | |||
Average Number of Common Shares | |||||||
Basic | 575.8 | 573.9 | |||||
Diluted | 579.7 | 578.6 | |||||
Summary Income Statements (Unaudited; in thousands, except per share data) | |||||||
Three Months Ended | |||||||
March 31, | |||||||
2018 | 2017 | ||||||
Operating Revenues and Other | |||||||
Crude Oil and Condensate | $ | 2,101,308 | $ | 1,430,061 | |||
Natural Gas Liquids | 221,415 | 153,444 | |||||
Natural Gas | 299,766 | 230,602 | |||||
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts | (59,771 | ) | 62,020 | ||||
Gathering, Processing and Marketing | 1,101,822 | 726,537 | |||||
Losses on Asset Dispositions, Net | (14,969 | ) | (16,758 | ) | |||
Other, Net | 31,591 | 24,659 | |||||
Total | 3,681,162 | 2,610,565 | |||||
Operating Expenses | |||||||
Lease and Well | 300,064 | 255,777 | |||||
Transportation Costs | 176,957 | 178,714 | |||||
Gathering and Processing Costs | 101,345 | 38,144 | |||||
Exploration Costs | 34,836 | 56,894 | |||||
Impairments | 64,609 | 193,187 | |||||
Marketing Costs | 1,106,390 | 736,536 | |||||
Depreciation, Depletion and Amortization | 748,591 | 816,036 | |||||
General and Administrative | 94,698 | 97,238 | |||||
Taxes Other Than Income | 179,084 | 130,293 | |||||
Total | 2,806,574 | 2,502,819 | |||||
Operating Income | 874,588 | 107,746 | |||||
Other Income, Net | 727 | 3,151 | |||||
Income Before Interest Expense and Income Taxes | 875,315 | 110,897 | |||||
Interest Expense, Net | 61,956 | 71,515 | |||||
Income Before Income Taxes | 813,359 | 39,382 | |||||
Income Tax Provision | 174,770 | 10,865 | |||||
Net Income | $ | 638,589 | $ | 28,517 | |||
Dividends Declared per Common Share | $ | 0.1850 | $ | 0.1675 | |||
EOG RESOURCES, INC. Operating Highlights (Unaudited) | |||||||
Three Months Ended | |||||||
March 31, | |||||||
2018 | 2017 | ||||||
Wellhead Volumes and Prices | |||||||
Crude Oil and Condensate Volumes (MBbld) (A) | |||||||
United States | 359.7 | 312.5 | |||||
Trinidad | 0.9 | 0.8 | |||||
Other International (B) | 2.7 | 2.4 | |||||
Total | 363.3 | 315.7 | |||||
Average Crude Oil and Condensate Prices ($/Bbl) (C) | |||||||
United States | $ | 64.24 | $ | 50.38 | |||
Trinidad | 54.86 | 41.56 | |||||
Other International (B) | 71.61 | 47.77 | |||||
Composite | 64.27 | 50.34 | |||||
Natural Gas Liquids Volumes (MBbld) (A) | |||||||
United States | 100.6 | 78.8 | |||||
Other International (B) | — | — | |||||
Total | 100.6 | 78.8 | |||||
Average Natural Gas Liquids Prices ($/Bbl) (C) | |||||||
United States | $ | 24.46 | $ | 21.63 | |||
Other International (B) | — | — | |||||
Composite | 24.46 | 21.63 | |||||
Natural Gas Volumes (MMcfd) (A) | |||||||
United States | 853 | 728 | |||||
Trinidad | 293 | 308 | |||||
Other International (B) | 30 | 22 | |||||
Total | 1,176 | 1,058 | |||||
Average Natural Gas Prices ($/Mcf) (C) | |||||||
United States | $ | 2.76 | $ | 2.32 | |||
Trinidad | 2.88 | 2.57 | |||||
Other International (B) | 4.36 | 3.76 | |||||
Composite | 2.83 | (D) | 2.42 | ||||
Crude Oil Equivalent Volumes (MBoed) (E) | |||||||
United States | 602.5 | 512.6 | |||||
Trinidad | 49.8 | 52.2 | |||||
Other International (B) | 7.6 | 5.9 | |||||
Total | 659.9 | 570.7 | |||||
Total MMBoe (E) | 59.4 | 51.4 |
(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 on EOG's Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2018). |
(D) | Includes a positive revenue adjustment of $0.41 per Mcf 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 on EOG's Quarterly Report on Form 10-Q for the fiscal quarter ended March 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 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) | |||||||
March 31, | December 31, | ||||||
2018 | 2017 | ||||||
ASSETS | |||||||
Current Assets | |||||||
Cash and Cash Equivalents | $ | 816,094 | $ | 834,228 | |||
Accounts Receivable, Net | 1,702,100 | 1,597,494 | |||||
Inventories | 584,729 | 483,865 | |||||
Assets from Price Risk Management Activities | 761 | 7,699 | |||||
Income Taxes Receivable | 262,789 | 113,357 | |||||
Other | 218,624 | 242,465 | |||||
Total | 3,585,097 | 3,279,108 | |||||
Property, Plant and Equipment | |||||||
Oil and Gas Properties (Successful Efforts Method) | 53,854,438 | 52,555,741 | |||||
Other Property, Plant and Equipment | 4,082,781 | 3,960,759 | |||||
Total Property, Plant and Equipment | 57,937,219 | 56,516,500 | |||||
Less: Accumulated Depreciation, Depletion and Amortization | (31,561,571 | ) | (30,851,463 | ) | |||
Total Property, Plant and Equipment, Net | 26,375,648 | 25,665,037 | |||||
Deferred Income Taxes | 18,182 | 17,506 | |||||
Other Assets | 761,590 | 871,427 | |||||
Total Assets | $ | 30,740,517 | $ | 29,833,078 | |||
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||||
Current Liabilities | |||||||
Accounts Payable | $ | 1,915,651 | $ | 1,847,131 | |||
Accrued Taxes Payable | 179,646 | 148,874 | |||||
Dividends Payable | 106,521 | 96,410 | |||||
Liabilities from Price Risk Management Activities | 84,128 | 50,429 | |||||
Current Portion of Long-Term Debt | 363,155 | 356,235 | |||||
Other | 187,657 | 226,463 | |||||
Total | 2,836,758 | 2,725,542 | |||||
Long-Term Debt | 6,071,604 | 6,030,836 | |||||
Other Liabilities | 1,301,938 | 1,275,213 | |||||
Deferred Income Taxes | 3,689,578 | 3,518,214 | |||||
Commitments and Contingencies | |||||||
Stockholders' Equity | |||||||
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 579,272,616 Shares Issued at March 31, 2018 and 578,827,768 Shares Issued at December 31, 2017 | 205,793 | 205,788 | |||||
Additional Paid in Capital | 5,569,194 | 5,536,547 | |||||
Accumulated Other Comprehensive Loss | (14,289 | ) | (19,297 | ) | |||
Retained Earnings | 11,125,051 | 10,593,533 | |||||
Common Stock Held in Treasury, 459,990 Shares at March 31, 2018 and 350,961 Shares at December 31, 2017 | (45,110 | ) | (33,298 | ) | |||
Total Stockholders' Equity | 16,840,639 | 16,283,273 | |||||
Total Liabilities and Stockholders' Equity | $ | 30,740,517 | $ | 29,833,078 |
EOG RESOURCES, INC. Summary Statements of Cash Flows (Unaudited; in thousands) | |||||||
Three Months Ended | |||||||
March 31, | |||||||
2018 | 2017 | ||||||
Cash Flows from Operating Activities | |||||||
Reconciliation of Net Income to Net Cash Provided by Operating Activities: | |||||||
Net Income | $ | 638,589 | $ | 28,517 | |||
Items Not Requiring (Providing) Cash | |||||||
Depreciation, Depletion and Amortization | 748,591 | 816,036 | |||||
Impairments | 64,609 | 193,187 | |||||
Stock-Based Compensation Expenses | 35,486 | 30,460 | |||||
Deferred Income Taxes | 171,362 | 694 | |||||
Losses on Asset Dispositions, Net | 14,969 | 16,758 | |||||
Other, Net | 2,013 | (3,052 | ) | ||||
Mark-to-Market Commodity Derivative Contracts | |||||||
Total (Gains) Losses | 59,771 | (62,020 | ) | ||||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts | (21,965 | ) | 1,912 | ||||
Other, Net | (478 | ) | (428 | ) | |||
Changes in Components of Working Capital and Other Assets and Liabilities | |||||||
Accounts Receivable | (109,654 | ) | 28,688 | ||||
Inventories | (106,799 | ) | 24,736 | ||||
Accounts Payable | 53,652 | 20,426 | |||||
Accrued Taxes Payable | 21,950 | (38,613 | ) | ||||
Other Assets | (8,863 | ) | (44,677 | ) | |||
Other Liabilities | (29,055 | ) | (51,251 | ) | |||
Changes in Components of Working Capital Associated with Investing and Financing Activities | 17,988 | (63,324 | ) | ||||
Net Cash Provided by Operating Activities | 1,552,166 | 898,049 | |||||
Investing Cash Flows | |||||||
Additions to Oil and Gas Properties | (1,365,111 | ) | (912,227 | ) | |||
Additions to Other Property, Plant and Equipment | (76,100 | ) | (34,336 | ) | |||
Proceeds from Sales of Assets | 2,829 | 46,812 | |||||
Changes in Components of Working Capital Associated with Investing Activities | (18,045 | ) | 63,324 | ||||
Net Cash Used in Investing Activities | (1,456,427 | ) | (836,427 | ) | |||
Financing Cash Flows | |||||||
Dividends Paid | (97,026 | ) | (96,707 | ) | |||
Treasury Stock Purchased | (16,776 | ) | (18,628 | ) | |||
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan | 1,453 | 2,356 | |||||
Repayment of Capital Lease Obligation | (1,671 | ) | (1,619 | ) | |||
Changes in Working Capital Associated with Financing Activities | 57 | — | |||||
Net Cash Used in Financing Activities | (113,963 | ) | (114,598 | ) | |||
Effect of Exchange Rate Changes on Cash | 90 | (353 | ) | ||||
Decrease in Cash and Cash Equivalents | (18,134 | ) | (53,329 | ) | |||
Cash and Cash Equivalents at Beginning of Period | 834,228 | 1,599,895 | |||||
Cash and Cash Equivalents at End of Period | $ | 816,094 | $ | 1,546,566 |
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 periods ended March 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 losses on asset dispositions in 2018 and 2017, to add back impairment charges related to certain of EOG's assets in 2018 and 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 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 | ||||||||||||||||||||||||||||||
March 31, 2018 | March 31, 2017 | ||||||||||||||||||||||||||||||
Before Tax | Income Tax Impact | After Tax | Diluted Earnings per Share | Before Tax | Income Tax Impact | After Tax | Diluted Earnings per Share | ||||||||||||||||||||||||
Reported Net Income (GAAP) | $ | 813,359 | $ | (174,770 | ) | $ | 638,589 | $ | 1.10 | $ | 39,382 | $ | (10,865 | ) | $ | 28,517 | $ | 0.05 | |||||||||||||
Adjustments: | |||||||||||||||||||||||||||||||
(Gains) Losses on Mark-to-Market Commodity Derivative Contracts | 59,771 | (13,166 | ) | 46,605 | 0.08 | (62,020 | ) | 22,191 | (39,829 | ) | (0.07 | ) | |||||||||||||||||||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts | (21,965 | ) | 4,838 | (17,127 | ) | (0.03 | ) | 1,912 | (684 | ) | 1,228 | — | |||||||||||||||||||
Add: Net Losses on Asset Dispositions | 14,969 | (3,324 | ) | 11,645 | 0.02 | 16,758 | (5,736 | ) | 11,022 | 0.02 | |||||||||||||||||||||
Add: Impairments | 20,876 | (4,598 | ) | 16,278 | 0.03 | 137,751 | (49,287 | ) | 88,464 | 0.15 | |||||||||||||||||||||
Less: Tax Reform Impact | — | (6,524 | ) | (6,524 | ) | (0.01 | ) | — | — | — | — | ||||||||||||||||||||
Adjustments to Net Income | 73,651 | (22,774 | ) | 50,877 | 0.09 | 94,401 | (33,516 | ) | 60,885 | 0.10 | |||||||||||||||||||||
Adjusted Net Income (Non-GAAP) | $ | 887,010 | $ | (197,544 | ) | $ | 689,466 | $ | 1.19 | $ | 133,783 | $ | (44,381 | ) | $ | 89,402 | $ | 0.15 | |||||||||||||
Average Number of Common Shares (GAAP) | |||||||||||||||||||||||||||||||
Basic | 575,775 | 573,935 | |||||||||||||||||||||||||||||
Diluted | 579,726 | 578,593 |
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 periods ended March 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, 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 ended March 31, 2018. EOG management uses this information for comparative purposes within the industry. | |||||||
Three Months Ended | |||||||
March 31, | |||||||
2018 | 2017 | ||||||
Net Cash Provided by Operating Activities (GAAP) | $ | 1,552,166 | $ | 898,049 | |||
Adjustments: | |||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) | 27,936 | 50,734 | |||||
Other Non-Current Income Taxes - Net Receivable | 118,921 | — | |||||
Changes in Components of Working Capital and Other Assets and Liabilities | |||||||
Accounts Receivable | 109,654 | (28,688 | ) | ||||
Inventories | 106,799 | (24,736 | ) | ||||
Accounts Payable | (53,652 | ) | (20,426 | ) | |||
Accrued Taxes Payable | (21,950 | ) | 38,613 | ||||
Other Assets | 8,863 | 44,677 | |||||
Other Liabilities | 29,055 | 51,251 | |||||
Changes in Components of Working Capital Associated with Investing and Financing Activities | (17,988 | ) | 63,324 | ||||
Discretionary Cash Flow (Non-GAAP) | $ | 1,859,804 | $ | 1,072,798 | |||
Discretionary Cash Flow (Non-GAAP) - Percentage Increase | 73 | % | |||||
Discretionary Cash Flow (Non-GAAP) | $ | 1,859,804 | |||||
Less: | |||||||
Total Cash Expenditures Excluding Acquisitions (Non-GAAP) (a) | (1,477,830 | ) | |||||
Dividends Paid (GAAP) | (97,026 | ) | |||||
Free Cash Flow (Non-GAAP) | $ | 284,948 | |||||
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Expenditures Excluding Acquisitions (Non-GAAP) for the three months ended March 31, 2018: | |||||||
Total Expenditures (GAAP) | $ | 1,546,641 | |||||
Less: | |||||||
Asset Retirement Costs | (12,100 | ) | |||||
Non-Cash Acquisition Costs of Other Property, Plant and Equipment | (47,635 | ) | |||||
Non-Cash Acquisition Costs of Unproved Properties | (8,809 | ) | |||||
Acquisition Costs of Proved Properties | (267 | ) | |||||
Total Cash Expenditures Excluding Acquisitions (Non-GAAP) | $ | 1,477,830 |
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 periods ended March 31, 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 net 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 | |||||||
March 31, | |||||||
2018 | 2017 | ||||||
Net Income (GAAP) | $ | 638,589 | $ | 28,517 | |||
Adjustments: | |||||||
Interest Expense, Net | 61,956 | 71,515 | |||||
Income Tax Provision | 174,770 | 10,865 | |||||
Depreciation, Depletion and Amortization | 748,591 | 816,036 | |||||
Exploration Costs | 34,836 | 56,894 | |||||
Impairments | 64,609 | 193,187 | |||||
EBITDAX (Non-GAAP) | 1,723,351 | 1,177,014 | |||||
Total (Gains) Losses on MTM Commodity Derivative Contracts | 59,771 | (62,020 | ) | ||||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts | (21,965 | ) | 1,912 | ||||
Losses on Asset Dispositions, Net | 14,969 | 16,758 | |||||
Adjusted EBITDAX (Non-GAAP) | $ | 1,776,126 | $ | 1,133,664 | |||
Adjusted EBITDAX (Non-GAAP) - Percentage Increase | 57 | % |
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 | ||||||
March 31, | December 31, | ||||||
2018 | 2017 | ||||||
Total Stockholders' Equity - (a) | $ | 16,841 | $ | 16,283 | |||
Current and Long-Term Debt (GAAP) - (b) | 6,435 | 6,387 | |||||
Less: Cash | (816 | ) | (834 | ) | |||
Net Debt (Non-GAAP) - (c) | 5,619 | 5,553 | |||||
Total Capitalization (GAAP) - (a) + (b) | $ | 23,276 | $ | 22,670 | |||
Total Capitalization (Non-GAAP) - (a) + (c) | $ | 22,460 | $ | 21,836 | |||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] | 28 | % | 28 | % | |||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] | 25 | % | 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 April 26, 2018. The weighted average price differential expressed in $/Bbl represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | |||||||
Midland Differential Basis Swap Contracts | |||||||
Volume (Bbld) | Weighted Average Price Differential ($/Bbl) | ||||||
2018 | |||||||
January 1, 2018 through May 31, 2018 (closed) | 15,000 | $ | 1.063 | ||||
June 1, 2018 through December 31, 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 April 26, 2018. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | |||||||
Gulf Coast Differential Basis Swap Contracts | |||||||
Volume (Bbld) | Weighted Average Price Differential ($/Bbl) | ||||||
2018 | |||||||
January 1, 2018 through May 31, 2018 (closed) | 37,000 | $ | 3.818 | ||||
June 1, 2018 through December 31, 2018 | 37,000 | 3.818 |
Presented below is a comprehensive summary of EOG's crude oil price swap contracts through April 26, 2018, with notional volumes expressed in Bbld and prices expressed in $/Bbl. | ||||||||
Crude Oil Price Swap Contracts | ||||||||
Volume (Bbld) | Weighted Average Price ($/Bbl) | |||||||
2018 | ||||||||
January 1, 2018 through March 31, 2018 (closed) | 134,000 | $ | 60.04 | |||||
April 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 April 26, 2018, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||
Natural Gas Price Swap Contracts | |||||||
Volume (MMBtud) | Weighted Average Price ($/MMBtu) | ||||||
2018 | |||||||
March 1, 2018 through May 31, 2018 (closed) | 35,000 | $ | 3.00 | ||||
June 1, 2018 through November 30, 2018 | 35,000 | 3.00 |
EOG has sold call options which establish a ceiling price for the sale of notional volumes of natural gas as specified in the call option contracts. The call options require that EOG pay the difference between the call option strike price and either the average or last business day NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the call option strike price. In addition, EOG has purchased put options which establish a floor price for the sale of notional volumes of natural gas as specified in the put option contracts. The put options grant EOG the right to receive the difference between the put option strike price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the put option strike price. Presented below is a comprehensive summary of EOG's natural gas call and put option contracts through April 26, 2018, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||||||||
Natural Gas Option Contracts | |||||||||||||
Call Options Sold | Put Options Purchased | ||||||||||||
Volume (MMBtud) | Weighted Average Price ($/MMBtu) | Volume (MMBtud) | Weighted Average Price ($/MMBtu) | ||||||||||
2018 | |||||||||||||
March 1, 2018 through May 31, 2018 (closed) | 120,000 | $ | 3.38 | 96,000 | $ | 2.94 | |||||||
June 1, 2018 through November 30, 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 |
(a) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2017: | ||||||||||||
Year Ended December 31, 2017 | ||||||||||||
Before Tax | Income Tax Impact | After 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 Tax | Income Tax Impact | After 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 Tax | Income Tax Impact | After 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 Tax | Income Tax Impact | After 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. Second Quarter and Full Year 2018 Forecast and Benchmark Commodity Pricing | |||||||||||||||||||
(a) Second Quarter and Full Year 2018 Forecast | |||||||||||||||||||
The forecast items for the second 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) | |||||||||||||||||||
2Q 2018 | Full Year 2018 | ||||||||||||||||||
Daily Sales Volumes | |||||||||||||||||||
Crude Oil and Condensate Volumes (MBbld) | |||||||||||||||||||
United States | 374.0 | - | 382.0 | 387.0 | - | 401.0 | |||||||||||||
Trinidad | 0.4 | - | 0.6 | 0.4 | - | 0.6 | |||||||||||||
Other International | 0.0 | - | 6.0 | 2.0 | - | 4.0 | |||||||||||||
Total | 374.4 | - | 388.6 | 389.4 | - | 405.6 | |||||||||||||
Natural Gas Liquids Volumes (MBbld) | |||||||||||||||||||
Total | 100.0 | - | 110.0 | 100.0 | - | 110.0 | |||||||||||||
Natural Gas Volumes (MMcfd) | |||||||||||||||||||
United States | 870 | - | 910 | 900 | - | 950 | |||||||||||||
Trinidad | 280 | - | 300 | 250 | - | 290 | |||||||||||||
Other International | 25 | - | 35 | 28 | - | 38 | |||||||||||||
Total | 1,175 | - | 1,245 | 1,178 | - | 1,278 | |||||||||||||
Crude Oil Equivalent Volumes (MBoed) | |||||||||||||||||||
United States | 619.0 | - | 643.7 | 637.0 | - | 669.3 | |||||||||||||
Trinidad | 47.1 | - | 50.6 | 42.1 | - | 48.9 | |||||||||||||
Other International | 4.2 | - | 11.9 | 6.7 | - | 10.3 | |||||||||||||
Total | 670.3 | - | 706.2 | 685.8 | - | 728.5 | |||||||||||||
Estimated Ranges (Unaudited) | |||||||||||||||||||
2Q 2018 | Full Year 2018 | ||||||||||||||||||
Operating Costs | |||||||||||||||||||
Unit Costs ($/Boe) | |||||||||||||||||||
Lease and Well | $ | 4.50 | - | $ | 4.90 | $ | 4.20 | - | $ | 4.80 | |||||||||
Transportation Costs | $ | 2.90 | - | $ | 3.40 | $ | 2.75 | - | $ | 3.25 | |||||||||
Depreciation, Depletion and Amortization | $ | 13.15 | - | $ | 13.55 | $ | 13.00 | - | $ | 13.40 | |||||||||
Expenses ($MM) | |||||||||||||||||||
Exploration, Dry Hole and Impairment | $ | 100 | - | $ | 120 | $ | 375 | - | $ | 425 | |||||||||
General and Administrative | $ | 100 | - | $ | 110 | $ | 415 | - | $ | 445 | |||||||||
Gathering and Processing | $ | 110 | - | $ | 120 | $ | 430 | - | $ | 470 | |||||||||
Capitalized Interest | $ | 5 | - | $ | 6 | $ | 19 | - | $ | 23 | |||||||||
Net Interest | $ | 62 | - | $ | 65 | $ | 244 | - | $ | 248 | |||||||||
Taxes Other Than Income (% of Wellhead Revenue) | 6.5 | % | - | 6.9 | % | 6.5 | % | - | 6.9 | % | |||||||||
Income Taxes | |||||||||||||||||||
Effective Rate | 20 | % | - | 25 | % | 20 | % | - | 25 | % | |||||||||
Current Tax (Benefit) / Expense ($MM) | $ | (90 | ) | - | $ | (55 | ) | $ | (350 | ) | - | $ | (310 | ) | |||||
Capital Expenditures (Excluding Acquisitions, $MM) | |||||||||||||||||||
Exploration and Development, Excluding Facilities | $ | 4,500 | - | $ | 4,800 | ||||||||||||||
Exploration and Development Facilities | $ | 600 | - | $ | 650 | ||||||||||||||
Gathering, Processing and Other | $ | 300 | - | $ | 350 | ||||||||||||||
Pricing - (Refer to Benchmark Commodity Pricing in text) | |||||||||||||||||||
Crude Oil and Condensate ($/Bbl) | |||||||||||||||||||
Differentials | |||||||||||||||||||
United States - above (below) WTI | $ | (1.50 | ) | - | $ | 0.50 | $ | (1.25 | ) | - | $ | 0.75 | |||||||
Trinidad - above (below) WTI | $ | (11.00 | ) | - | $ | (9.00 | ) | $ | (11.00 | ) | - | $ | (9.00 | ) | |||||
Other International - above (below) WTI | $ | 2.00 | - | $ | 4.00 | $ | 0.00 | - | $ | 6.00 | |||||||||
Natural Gas Liquids | |||||||||||||||||||
Realizations as % of WTI | 32 | % | - | 38 | % | 32 | % | - | 38 | % | |||||||||
Natural Gas ($/Mcf) | |||||||||||||||||||
Differentials | |||||||||||||||||||
United States - above (below) NYMEX Henry Hub | $ | (0.70 | ) | - | $ | (0.30 | ) | $ | (0.60 | ) | - | $ | 0.00 | ||||||
Realizations | |||||||||||||||||||
Trinidad | $ | 2.30 | - | $ | 2.70 | $ | 2.15 | - | $ | 2.75 | |||||||||
Other International | $ | 4.15 | - | $ | 4.65 | $ | 4.00 | - | $ | 5.00 | |||||||||
Definitions | |||||||||||||||||||
$/Bbl | U.S. Dollars per barrel | ||||||||||||||||||
$/Boe | U.S. Dollars per barrel of oil equivalent | ||||||||||||||||||
$/Mcf | U.S. Dollars per thousand cubic feet | ||||||||||||||||||
$MM | U.S. Dollars in millions | ||||||||||||||||||
MBbld | Thousand barrels per day | ||||||||||||||||||
MBoed | Thousand barrels of oil equivalent per day | ||||||||||||||||||
MMcfd | Million cubic feet per day | ||||||||||||||||||
NYMEX | U.S. New York Mercantile Exchange | ||||||||||||||||||
WTI | West Texas Intermediate |
EOG RESOURCES, INC. First 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 Gas Liquids (Bbld) (A) | Natural Gas (MMcfd) (A) | Crude Oil Equivalent (Boed) (B) | |||||||||||||||
Delaware Basin | |||||||||||||||||||||
Wolfcamp | 58 | 53 | 5,900 | 1,335 | 250 | 2.1 | 1,925 | ||||||||||||||
Bone Spring | 9 | 8 | 5,900 | 1,195 | 190 | 1.6 | 1,645 | ||||||||||||||
Leonard | 3 | 3 | 4,300 | 1,640 | 335 | 2.8 | 2,430 | ||||||||||||||
Powder River Basin Turner | 9 | 8 | 6,100 | 675 | 180 | 2.1 | 1,210 | ||||||||||||||
DJ Basin Codell | 12 | 9 | 9,200 | 895 | 95 | 0.4 | 1,055 | ||||||||||||||
South Texas Eagle Ford | 72 | 65 | 6,900 | 1,325 | 150 | 0.9 | 1,620 | ||||||||||||||
South Texas Austin Chalk | 10 | 8 | 4,600 | 1,960 | 400 | 2.3 | 2,750 | ||||||||||||||
(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. |
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