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: February 27, 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 |
• | Delivers 20 Percent U.S. Crude Oil Production Growth and Pays Dividend within Cash Flow |
• | Lowers Per-Unit Transportation and DD&A Expenses Below Targets |
• | Increases Proved Reserves 18 Percent and Replaces 201 Percent of 2017 Production at Low Finding Costs |
• | Raises Common Stock Dividend 10 Percent |
• | Targets 18 Percent Crude Oil Production Growth and 16 Percent Total Production Growth for 2018 with Significant Free Cash Flow at $60 Oil |
• | Expects to Earn Double-Digit ROCE in 2018 |
• | 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 |
• | 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 | Twelve Months Ended | ||||||||||||||
December 31, | December 31, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
Net Operating Revenues and Other | $ | 3,340.4 | $ | 2,402.0 | $ | 11,208.3 | $ | 7,650.6 | |||||||
Net Income (Loss) | $ | 2,430.5 | $ | (142.4 | ) | $ | 2,582.6 | $ | (1,096.7 | ) | |||||
Net Income (Loss) Per Share | |||||||||||||||
Basic | $ | 4.22 | $ | (0.25 | ) | $ | 4.49 | $ | (1.98 | ) | |||||
Diluted | $ | 4.20 | $ | (0.25 | ) | $ | 4.46 | $ | (1.98 | ) | |||||
Average Number of Common Shares | |||||||||||||||
Basic | 575.4 | 567.3 | 574.6 | 553.4 | |||||||||||
Diluted | 579.2 | 567.3 | 578.7 | 553.4 | |||||||||||
Summary Income Statements (Unaudited; in thousands, except per share data) | |||||||||||||||
Three Months Ended | Twelve Months Ended | ||||||||||||||
December 31, | December 31, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
Net Operating Revenues and Other | |||||||||||||||
Crude Oil and Condensate | $ | 1,929,471 | $ | 1,366,223 | $ | 6,256,396 | $ | 4,317,341 | |||||||
Natural Gas Liquids | 249,172 | 137,849 | 729,561 | 437,250 | |||||||||||
Natural Gas | 246,922 | 215,373 | 921,934 | 742,152 | |||||||||||
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts | (45,032 | ) | (65,787 | ) | 19,828 | (99,608 | ) | ||||||||
Gathering, Processing and Marketing | 1,008,385 | 614,594 | 3,298,087 | 1,966,259 | |||||||||||
Gains (Losses) on Asset Dispositions, Net | (65,220 | ) | 104,034 | (99,096 | ) | 205,835 | |||||||||
Other, Net | 16,741 | 29,753 | 81,610 | 81,403 | |||||||||||
Total | 3,340,439 | 2,402,039 | 11,208,320 | 7,650,632 | |||||||||||
Operating Expenses | |||||||||||||||
Lease and Well | 281,941 | 241,846 | 1,044,847 | 927,452 | |||||||||||
Transportation Costs | 191,717 | 193,319 | 740,352 | 764,106 | |||||||||||
Gathering and Processing Costs | 43,295 | 32,516 | 148,775 | 122,901 | |||||||||||
Exploration Costs | 22,941 | 39,110 | 145,342 | 124,953 | |||||||||||
Dry Hole Costs | 4,532 | 193 | 4,609 | 10,657 | |||||||||||
Impairments | 153,442 | 297,946 | 479,240 | 620,267 | |||||||||||
Marketing Costs | 1,009,566 | 634,248 | 3,330,237 | 2,007,635 | |||||||||||
Depreciation, Depletion and Amortization | 881,745 | 862,524 | 3,409,387 | 3,553,417 | |||||||||||
General and Administrative | 117,005 | 102,182 | 434,467 | 394,815 | |||||||||||
Taxes Other Than Income | 158,343 | 103,642 | 544,662 | 349,710 | |||||||||||
Total | 2,864,527 | 2,507,526 | 10,281,918 | 8,875,913 | |||||||||||
Operating Income (Loss) | 475,912 | (105,487 | ) | 926,402 | (1,225,281 | ) | |||||||||
Other Income (Expense), Net | 803 | (17,198 | ) | 9,152 | (50,543 | ) | |||||||||
Income (Loss) Before Interest Expense and Income Taxes | 476,715 | (122,685 | ) | 935,554 | (1,275,824 | ) | |||||||||
Interest Expense, Net | 63,362 | 71,325 | 274,372 | 281,681 | |||||||||||
Income (Loss) Before Income Taxes | 413,353 | (194,010 | ) | 661,182 | (1,557,505 | ) | |||||||||
Income Tax (Benefit) | (2,017,115 | ) | (51,658 | ) | (1,921,397 | ) | (460,819 | ) | |||||||
Net Income (Loss) | $ | 2,430,468 | $ | (142,352 | ) | $ | 2,582,579 | $ | (1,096,686 | ) | |||||
Dividends Declared per Common Share | $ | 0.1675 | $ | 0.1675 | $ | 0.6700 | $ | 0.6700 | |||||||
EOG RESOURCES, INC. Operating Highlights (Unaudited) | |||||||||||||||
Three Months Ended | Twelve Months Ended | ||||||||||||||
December 31, | December 31, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
Wellhead Volumes and Prices | |||||||||||||||
Crude Oil and Condensate Volumes (MBbld) (A) | |||||||||||||||
United States | 366.9 | 306.0 | 335.0 | 278.3 | |||||||||||
Trinidad | 1.1 | 0.9 | 0.9 | 0.8 | |||||||||||
Other International (B) | 0.1 | 4.8 | 0.8 | 3.4 | |||||||||||
Total | 368.1 | 311.7 | 336.7 | 282.5 | |||||||||||
Average Crude Oil and Condensate Prices ($/Bbl) (C) | |||||||||||||||
United States | $ | 56.95 | $ | 47.93 | $ | 50.91 | $ | 41.84 | |||||||
Trinidad | 46.56 | 40.04 | 42.30 | 33.76 | |||||||||||
Other International (B) | 45.72 | 38.96 | 57.20 | 36.72 | |||||||||||
Composite | 56.97 | 47.76 | 50.91 | 41.76 | |||||||||||
Natural Gas Liquids Volumes (MBbld) (A) | |||||||||||||||
United States | 100.6 | 80.9 | 88.4 | 81.6 | |||||||||||
Other International (B) | — | — | — | — | |||||||||||
Total | 100.6 | 80.9 | 88.4 | 81.6 | |||||||||||
Average Natural Gas Liquids Prices ($/Bbl) (C) | |||||||||||||||
United States | $ | 26.92 | $ | 18.51 | $ | 22.61 | $ | 14.63 | |||||||
Other International (B) | — | — | — | — | |||||||||||
Composite | 26.92 | 18.51 | 22.61 | 14.63 | |||||||||||
Natural Gas Volumes (MMcfd) (A) | |||||||||||||||
United States | 829 | 800 | 765 | 810 | |||||||||||
Trinidad | 299 | 323 | 313 | 340 | |||||||||||
Other International (B) | 32 | 22 | 25 | 25 | |||||||||||
Total | 1,160 | 1,145 | 1,103 | 1,175 | |||||||||||
Average Natural Gas Prices ($/Mcf) (C) | |||||||||||||||
United States | $ | 2.17 | $ | 2.05 | $ | 2.20 | $ | 1.60 | |||||||
Trinidad | 2.52 | 1.89 | 2.38 | 1.88 | |||||||||||
Other International (B) | 4.23 | 3.85 | 3.89 | 3.64 | |||||||||||
Composite | 2.31 | 2.04 | 2.29 | 1.73 | |||||||||||
Crude Oil Equivalent Volumes (MBoed) (D) | |||||||||||||||
United States | 605.6 | 520.3 | 551.0 | 494.9 | |||||||||||
Trinidad | 51.0 | 54.6 | 53.0 | 57.5 | |||||||||||
Other International (B) | 5.4 | 8.6 | 4.9 | 7.6 | |||||||||||
Total | 662.0 | 583.5 | 608.9 | 560.0 | |||||||||||
Total MMBoe (D) | 60.9 | 53.7 | 222.3 | 205.0 |
(A) | Thousand barrels per day or million cubic feet per day, as applicable. |
(B) | Other International includes EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016. |
(C) | Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments. |
(D) | Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. |
EOG RESOURCES, INC. Summary Balance Sheets (Unaudited; in thousands, except share data) | |||||||
December 31, | December 31, | ||||||
2017 | 2016 | ||||||
ASSETS | |||||||
Current Assets | |||||||
Cash and Cash Equivalents | $ | 834,228 | $ | 1,599,895 | |||
Accounts Receivable, Net | 1,597,494 | 1,216,320 | |||||
Inventories | 483,865 | 350,017 | |||||
Assets from Price Risk Management Activities | 7,699 | — | |||||
Income Taxes Receivable | 113,357 | 12,305 | |||||
Other | 242,465 | 206,679 | |||||
Total | 3,279,108 | 3,385,216 | |||||
Property, Plant and Equipment | |||||||
Oil and Gas Properties (Successful Efforts Method) | 52,555,741 | 49,592,091 | |||||
Other Property, Plant and Equipment | 3,960,759 | 4,008,564 | |||||
Total Property, Plant and Equipment | 56,516,500 | 53,600,655 | |||||
Less: Accumulated Depreciation, Depletion and Amortization | (30,851,463 | ) | (27,893,577 | ) | |||
Total Property, Plant and Equipment, Net | 25,665,037 | 25,707,078 | |||||
Deferred Income Taxes | 17,506 | 16,140 | |||||
Other Assets | 871,427 | 190,767 | |||||
Total Assets | $ | 29,833,078 | $ | 29,299,201 | |||
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||||
Current Liabilities | |||||||
Accounts Payable | $ | 1,847,131 | $ | 1,511,826 | |||
Accrued Taxes Payable | 148,874 | 118,411 | |||||
Dividends Payable | 96,410 | 96,120 | |||||
Liabilities from Price Risk Management Activities | 50,429 | 61,817 | |||||
Current Portion of Long-Term Debt | 356,235 | 6,579 | |||||
Other | 226,463 | 232,538 | |||||
Total | 2,725,542 | 2,027,291 | |||||
Long-Term Debt | 6,030,836 | 6,979,779 | |||||
Other Liabilities | 1,275,213 | 1,282,142 | |||||
Deferred Income Taxes | 3,518,214 | 5,028,408 | |||||
Commitments and Contingencies | |||||||
Stockholders' Equity | |||||||
Common Stock, $0.01 Par, 1,280,000,000 Shares and 640,000,000 Shares Authorized at December 31, 2017 and 2016, respectively, and 578,827,768 Shares and 576,950,272 Shares Issued at December 31, 2017 and 2016, respectively | 205,788 | 205,770 | |||||
Additional Paid in Capital | 5,536,547 | 5,420,385 | |||||
Accumulated Other Comprehensive Loss | (19,297 | ) | (19,010 | ) | |||
Retained Earnings | 10,593,533 | 8,398,118 | |||||
Common Stock Held in Treasury, 350,961 Shares and 250,155 Shares at December 31, 2017 and 2016, respectively | (33,298 | ) | (23,682 | ) | |||
Total Stockholders' Equity | 16,283,273 | 13,981,581 | |||||
Total Liabilities and Stockholders' Equity | $ | 29,833,078 | $ | 29,299,201 |
EOG RESOURCES, INC. Summary Statements of Cash Flows (Unaudited; in thousands) | |||||||
Twelve Months Ended | |||||||
December 31, | |||||||
2017 | 2016 | ||||||
Cash Flows from Operating Activities | |||||||
Reconciliation of Net Income (Loss) to Net Cash Provided by Operating Activities: | |||||||
Net Income (Loss) | $ | 2,582,579 | $ | (1,096,686 | ) | ||
Items Not Requiring (Providing) Cash | |||||||
Depreciation, Depletion and Amortization | 3,409,387 | 3,553,417 | |||||
Impairments | 479,240 | 620,267 | |||||
Stock-Based Compensation Expenses | 133,849 | 128,090 | |||||
Deferred Income Taxes | (1,473,872 | ) | (515,206 | ) | |||
(Gains) Losses on Asset Dispositions, Net | 99,096 | (205,835 | ) | ||||
Other, Net | 6,546 | 61,690 | |||||
Dry Hole Costs | 4,609 | 10,657 | |||||
Mark-to-Market Commodity Derivative Contracts | |||||||
Total (Gains) Losses | (19,828 | ) | 99,608 | ||||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts | 7,438 | (22,219 | ) | ||||
Excess Tax Benefits from Stock-Based Compensation | — | (29,357 | ) | ||||
Other, Net | 1,204 | 10,971 | |||||
Changes in Components of Working Capital and Other Assets and Liabilities | |||||||
Accounts Receivable | (392,131 | ) | (232,799 | ) | |||
Inventories | (174,548 | ) | 170,694 | ||||
Accounts Payable | 324,192 | (74,048 | ) | ||||
Accrued Taxes Payable | (63,937 | ) | 92,782 | ||||
Other Assets | (658,609 | ) | (40,636 | ) | |||
Other Liabilities | (89,871 | ) | (16,225 | ) | |||
Changes in Components of Working Capital Associated with Investing and Financing Activities | 89,992 | (156,102 | ) | ||||
Net Cash Provided by Operating Activities | 4,265,336 | 2,359,063 | |||||
Investing Cash Flows | |||||||
Additions to Oil and Gas Properties | (3,950,918 | ) | (2,489,756 | ) | |||
Additions to Other Property, Plant and Equipment | (173,324 | ) | (93,039 | ) | |||
Proceeds from Sales of Assets | 226,768 | 1,119,215 | |||||
Net Cash Received from Yates Transaction | — | 54,534 | |||||
Changes in Components of Working Capital Associated with Investing Activities | (89,935 | ) | 156,102 | ||||
Net Cash Used in Investing Activities | (3,987,409 | ) | (1,252,944 | ) | |||
Financing Cash Flows | |||||||
Net Commercial Paper Repayments | — | (259,718 | ) | ||||
Long-Term Debt Borrowings | — | 991,097 | |||||
Long-Term Debt Repayments | (600,000 | ) | (563,829 | ) | |||
Dividends Paid | (386,531 | ) | (372,845 | ) | |||
Excess Tax Benefits from Stock-Based Compensation | — | 29,357 | |||||
Treasury Stock Purchased | (63,408 | ) | (82,125 | ) | |||
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan | 20,840 | 23,296 | |||||
Debt Issuance Costs | — | (1,602 | ) | ||||
Repayment of Capital Lease Obligation | (6,555 | ) | (6,353 | ) | |||
Other, Net | (57 | ) | — | ||||
Net Cash Used in Financing Activities | (1,035,711 | ) | (242,722 | ) | |||
Effect of Exchange Rate Changes on Cash | (7,883 | ) | 17,992 | ||||
Increase (Decrease) in Cash and Cash Equivalents | (765,667 | ) | 881,389 | ||||
Cash and Cash Equivalents at Beginning of Period | 1,599,895 | 718,506 | |||||
Cash and Cash Equivalents at End of Period | $ | 834,228 | $ | 1,599,895 |
EOG RESOURCES, INC. Quantitative Reconciliation of Adjusted Net Income (Loss) (Non-GAAP) To Net Income (Loss) (GAAP) (Unaudited; in thousands, except per share data) | |||||||||||||||||||||||||||||||
The following chart adjusts the three-month and twelve-month periods ended December 31, 2017 and 2016 reported Net Income (Loss) (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net (gains) losses on asset dispositions in 2017 and 2016, to add back impairment charges related to certain of EOG's assets in 2017 and 2016, to eliminate the impact of the Trinidad tax settlement in 2016, to add back certain voluntary retirement expense in 2016, to add back acquisition costs and state apportionment change related to the Yates transaction in 2016, to add back an early lease termination payment as the result of a legal settlement in 2017, to add back the transaction costs for the formation of a joint venture in 2017, to add back joint interest billings deemed uncollectible in 2017, and to eliminate the impact of tax reform in 2017. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||||||||||||||||||||||
Three Months Ended | Three Months Ended | ||||||||||||||||||||||||||||||
December 31, 2017 | December 31, 2016 | ||||||||||||||||||||||||||||||
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 (Loss) (GAAP) | $ | 413,353 | $ | 2,017,115 | $ | 2,430,468 | $ | 4.20 | $ | (194,010 | ) | $ | 51,658 | $ | (142,352 | ) | $ | (0.25 | ) | ||||||||||||
Adjustments: | |||||||||||||||||||||||||||||||
(Gains) Losses on Mark-to-Market Commodity Derivative Contracts | 45,032 | (16,142 | ) | 28,890 | 0.05 | 65,787 | (23,583 | ) | 42,204 | 0.07 | |||||||||||||||||||||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts | 2,708 | (971 | ) | 1,737 | — | — | 29 | 29 | — | ||||||||||||||||||||||
Add: Net (Gains) Losses on Asset Dispositions | 65,220 | (23,315 | ) | 41,905 | 0.07 | (104,034 | ) | 36,856 | (67,178 | ) | (0.12 | ) | |||||||||||||||||||
Add: Impairments | 100,304 | (35,954 | ) | 64,350 | 0.11 | 217,839 | (76,728 | ) | 141,111 | 0.25 | |||||||||||||||||||||
Add: Voluntary Retirement Expense | — | — | — | — | — | (57 | ) | (57 | ) | — | |||||||||||||||||||||
Add: Acquisition - State Apportionment Change | — | — | — | — | — | 16,424 | 16,424 | 0.03 | |||||||||||||||||||||||
Add: Acquisition Costs | — | — | — | — | 2,173 | 955 | 3,128 | 0.01 | |||||||||||||||||||||||
Add: Joint Interest Billings Deemed Uncollectible | 4,528 | (1,623 | ) | 2,905 | 0.01 | — | — | — | — | ||||||||||||||||||||||
Less: Tax Reform Impact | — | (2,169,376 | ) | (2,169,376 | ) | (3.75 | ) | — | — | — | — | ||||||||||||||||||||
Adjustments to Net Income (Loss) | 217,792 | (2,247,381 | ) | (2,029,589 | ) | (3.51 | ) | 181,765 | (46,104 | ) | 135,661 | 0.24 | |||||||||||||||||||
Adjusted Net Income (Loss) (Non-GAAP) | $ | 631,145 | $ | (230,266 | ) | $ | 400,879 | $ | 0.69 | $ | (12,245 | ) | $ | 5,554 | $ | (6,691 | ) | $ | (0.01 | ) | |||||||||||
Average Number of Common Shares (GAAP) | |||||||||||||||||||||||||||||||
Basic | 575,394 | 567,337 | |||||||||||||||||||||||||||||
Diluted | 579,203 | 567,337 |
Twelve Months Ended | Twelve Months Ended | |||||||||||||||||||||||||
December 31, 2017 | December 31, 2016 | |||||||||||||||||||||||||
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 (Loss) (GAAP) | $ | 661,182 | $ | 1,921,397 | $ | 2,582,579 | $ | 4.46 | $ | (1,557,505) | $ | 460,819 | $ | (1,096,686) | $ | (1.98 | ) | |||||||||
Adjustments: | ||||||||||||||||||||||||||
(Gains) Losses on Mark-to-Market Commodity Derivative Contracts | (19,828) | 7,107 | (12,721 | ) | (0.02 | ) | 99,608 | (35,640) | 63,968 | 0.12 | ||||||||||||||||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts | 7,438 | (2,666) | 4,772 | 0.01 | (22,219) | 7,950 | (14,269) | (0.03 | ) | |||||||||||||||||
Add: Net (Gains) Losses on Asset Dispositions | 99,096 | (35,270) | 63,826 | 0.11 | (205,835) | 61,491 | (144,344) | (0.26 | ) | |||||||||||||||||
Add: Impairments | 261,452 | (93,718) | 167,734 | 0.29 | 320,617 | (113,368) | 207,249 | 0.37 | ||||||||||||||||||
Add: Trinidad Tax Settlement | — | — | — | — | — | 43,000 | 43,000 | 0.08 | ||||||||||||||||||
Add: Voluntary Retirement Expense | — | — | — | — | 42,054 | (15,047) | 27,007 | 0.05 | ||||||||||||||||||
Add: Acquisition - State Apportionment Change | — | — | — | — | — | 16,424 | 16,424 | 0.03 | ||||||||||||||||||
Add: Acquisition Costs | — | — | — | — | 5,100 | (88) | 5,012 | 0.01 | ||||||||||||||||||
Add: Legal Settlement - Early Lease Termination | 10,202 | (3,657) | 6,545 | 0.01 | — | — | — | — | ||||||||||||||||||
Add: Joint Venture Transaction Costs | 3,056 | (1,095) | 1,961 | — | — | — | — | — | ||||||||||||||||||
Add: Joint Interest Billings Deemed Uncollectible | 4,528 | (1,623) | 2,905 | 0.01 | — | — | — | — | ||||||||||||||||||
Less: Tax Reform Impact | — | (2,169,376) | (2,169,376 | ) | (3.75 | ) | — | — | — | — | ||||||||||||||||
Adjustments to Net Income (Loss) | 365,944 | (2,300,298) | (1,934,354 | ) | (3.34 | ) | 239,325 | (35,278) | 204,047 | 0.37 | ||||||||||||||||
Adjusted Net Income (Loss) (Non-GAAP) | $ | 1,027,126 | $ | (378,901) | $ | 648,225 | $ | 1.12 | $ | (1,318,180) | $ | 425,541 | $ | (892,639) | $ | (1.61 | ) | |||||||||
Average Number of Common Shares (GAAP) | ||||||||||||||||||||||||||
Basic | 574,620 | 553,384 | ||||||||||||||||||||||||
Diluted | 578,693 | 553,384 |
EOG RESOURCES, INC. Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP) To Net Cash Provided by Operating Activities (GAAP) (Unaudited; in thousands) Calculation of Free Cash Flow (Non-GAAP) (Unaudited; in thousands) | |||||||||||||||
The following chart reconciles the three-month and twelve-month periods ended December 31, 2017 and 2016 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Other Non-Current Taxes, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG defines Free Cash Flow (Non-GAAP) for a given period as Discretionary Cash Flow (Non-GAAP) (see below reconciliation) for such period less the total cash capital expenditures excluding acquisitions incurred (Non-GAAP) during such period and dividends paid (GAAP) during such period, as is illustrated below for the twelve months ended December 31, 2017. EOG management uses this information for comparative purposes within the industry. | |||||||||||||||
Three Months Ended | Twelve Months Ended | ||||||||||||||
December 31, | December 31, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
Net Cash Provided by Operating Activities (GAAP) | $ | 1,327,548 | $ | 804,745 | $ | 4,265,336 | $ | 2,359,063 | |||||||
Adjustments: | |||||||||||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) | 16,420 | 33,931 | 122,688 | 104,199 | |||||||||||
Excess Tax Benefits from Stock-Based Compensation | — | 7,286 | — | 29,357 | |||||||||||
Other Non-Current Taxes (Non-Current Impact of the Tax Cut Jobs Act) | (513,404 | ) | — | (513,404 | ) | — | |||||||||
Changes in Components of Working Capital and Other Assets and Liabilities | |||||||||||||||
Accounts Receivable | 366,686 | 220,939 | 392,131 | 232,799 | |||||||||||
Inventories | 156,874 | (33,131 | ) | 174,548 | (170,694 | ) | |||||||||
Accounts Payable | (211,298 | ) | (127,165 | ) | (324,192 | ) | 74,048 | ||||||||
Accrued Taxes Payable | 13,970 | 21,214 | 63,937 | (92,782 | ) | ||||||||||
Other Assets | 574,669 | 28,110 | 658,609 | 40,636 | |||||||||||
Other Liabilities | 20,647 | 53,024 | 89,871 | 16,225 | |||||||||||
Changes in Components of Working Capital Associated with Investing and Financing Activities | (210,365 | ) | 36,342 | (89,992 | ) | 156,102 | |||||||||
Discretionary Cash Flow (Non-GAAP) | $ | 1,541,747 | $ | 1,045,295 | $ | 4,839,532 | $ | 2,748,953 | |||||||
Discretionary Cash Flow (Non-GAAP) - Percentage Increase | 47 | % | 76 | % | |||||||||||
Discretionary Cash Flow (Non-GAAP) | $ | 4,839,532 | |||||||||||||
Less: | |||||||||||||||
Total Cash Expenditures Excluding Acquisitions (Non-GAAP) (a) | (4,228,859 | ) | |||||||||||||
Dividends Paid (GAAP) | (386,531 | ) | |||||||||||||
Free Cash Flow (Non-GAAP) | $ | 224,142 | |||||||||||||
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Expenditures Excluding Acquisitions (Non-GAAP) for the twelve months ended December 31, 2017: | |||||||||||||||
Total Expenditures (GAAP) | $ | 4,612,746 | |||||||||||||
Less: | |||||||||||||||
Asset Retirement Costs | (55,592 | ) | |||||||||||||
Non-Cash Acquisition of Unproved Properties | (255,711 | ) | |||||||||||||
Acquisition Costs of Proved Properties | (72,584 | ) | |||||||||||||
Total Cash Expenditures Excluding Acquisitions (Non-GAAP) | $ | 4,228,859 |
EOG RESOURCES, INC. Quantitative Reconciliation of Adjusted Earnings Before Interest Expense, Net, Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs, Impairments and Additional Items (Adjusted EBITDAX) (Non-GAAP) to Net Income (Loss) (GAAP) (Unaudited; in thousands) | |||||||||||||||
The following chart adjusts the three-month and twelve-month periods ended December 31, 2017 and 2016 reported Net Income (Loss) (GAAP) to Earnings Before Interest Expense (Net), Income Taxes (Income Tax Provision (Benefit)), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the net (gains) losses on asset dispositions (Net). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (Loss) (GAAP) to add back Interest Expense (Net), Income Taxes (Income Tax Provision (Benefit)), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||||||
Three Months Ended | Twelve Months Ended | ||||||||||||||
December 31, | December 31, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
Net Income (Loss) (GAAP) | $ | 2,430,468 | $ | (142,352 | ) | $ | 2,582,579 | $ | (1,096,686 | ) | |||||
Adjustments: | |||||||||||||||
Interest Expense, Net | 63,362 | 71,325 | 274,372 | 281,681 | |||||||||||
Income Tax Provision (Benefit) | (2,017,115 | ) | (51,658 | ) | (1,921,397 | ) | (460,819 | ) | |||||||
Depreciation, Depletion and Amortization | 881,745 | 862,524 | 3,409,387 | 3,553,417 | |||||||||||
Exploration Costs | 22,941 | 39,110 | 145,342 | 124,953 | |||||||||||
Dry Hole Costs | 4,532 | 193 | 4,609 | 10,657 | |||||||||||
Impairments | 153,442 | 297,946 | 479,240 | 620,267 | |||||||||||
EBITDAX (Non-GAAP) | 1,539,375 | 1,077,088 | 4,974,132 | 3,033,470 | |||||||||||
Total (Gains) Losses on MTM Commodity Derivative Contracts | 45,032 | 65,787 | (19,828 | ) | 99,608 | ||||||||||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts | 2,708 | — | 7,438 | (22,219 | ) | ||||||||||
(Gains) Losses on Asset Dispositions, Net | 65,220 | (104,034 | ) | 99,096 | (205,835 | ) | |||||||||
Adjusted EBITDAX (Non-GAAP) | $ | 1,652,335 | $ | 1,038,841 | $ | 5,060,838 | $ | 2,905,024 | |||||||
Adjusted EBITDAX (Non-GAAP) - Percentage Increase | 59 | % | 74 | % |
EOG RESOURCES, INC. Quantitative Reconciliation of Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as Used in the Calculation of The Net Debt-to-Total Capitalization Ratio (Non-GAAP) to Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) (Unaudited; in millions, except ratio data) | |||||||
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. | |||||||
At | At | ||||||
December 31, | December 31, | ||||||
2017 | 2016 | ||||||
Total Stockholders' Equity - (a) | $ | 16,283 | $ | 13,982 | |||
Current and Long-Term Debt (GAAP) - (b) | 6,387 | 6,986 | |||||
Less: Cash | (834 | ) | (1,600 | ) | |||
Net Debt (Non-GAAP) - (c) | 5,553 | 5,386 | |||||
Total Capitalization (GAAP) - (a) + (b) | $ | 22,670 | $ | 20,968 | |||
Total Capitalization (Non-GAAP) - (a) + (c) | $ | 21,836 | $ | 19,368 | |||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] | 28 | % | 33 | % | |||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] | 25 | % | 28 | % |
EOG RESOURCES, INC. | |||||||||||||||
Reserves Supplemental Data | |||||||||||||||
(Unaudited) | |||||||||||||||
2017 NET PROVED RESERVES RECONCILIATION SUMMARY | |||||||||||||||
United States | Trinidad | Other International | Total | ||||||||||||
CRUDE OIL & CONDENSATE (MMBbl) | |||||||||||||||
Beginning Reserves | 1,168.5 | 0.8 | 8.3 | 1,177.6 | |||||||||||
Revisions | 58.0 | 0.1 | (0.2 | ) | 57.9 | ||||||||||
Purchases in place | 1.1 | — | — | 1.1 | |||||||||||
Extensions, discoveries and other additions | 207.1 | 0.3 | 0.1 | 207.5 | |||||||||||
Sales in place | (8.4 | ) | — | — | (8.4 | ) | |||||||||
Production | (122.2 | ) | (0.3 | ) | (0.2 | ) | (122.7 | ) | |||||||
Ending Reserves | 1,304.1 | 0.9 | 8.0 | 1,313.0 | |||||||||||
NATURAL GAS LIQUIDS (MMBbl) | |||||||||||||||
Beginning Reserves | 416.4 | — | — | 416.4 | |||||||||||
Revisions | 46.9 | — | — | 46.9 | |||||||||||
Purchases in place | 0.4 | — | — | 0.4 | |||||||||||
Extensions, discoveries and other additions | 75.0 | — | — | 75.0 | |||||||||||
Sales in place | (2.9 | ) | — | — | (2.9 | ) | |||||||||
Production | (32.3 | ) | — | — | (32.3 | ) | |||||||||
Ending Reserves | 503.5 | — | — | 503.5 | |||||||||||
NATURAL GAS (Bcf) | |||||||||||||||
Beginning Reserves | 3,021.2 | 280.9 | 15.8 | 3,317.9 | |||||||||||
Revisions | 602.8 | (27.4 | ) | 8.6 | 584.0 | ||||||||||
Purchases in place | 4.8 | — | — | 4.8 | |||||||||||
Extensions, discoveries and other additions | 619.3 | 174.2 | 35.9 | 829.4 | |||||||||||
Sales in place | (56.4 | ) | — | — | (56.4 | ) | |||||||||
Production | (293.2 | ) | (114.3 | ) | (9.1 | ) | (416.6 | ) | |||||||
Ending Reserves | 3,898.5 | 313.4 | 51.2 | 4,263.1 | |||||||||||
OIL EQUIVALENTS (MMBoe) | |||||||||||||||
Beginning Reserves | 2,088.4 | 47.7 | 10.9 | 2,147.0 | |||||||||||
Revisions | 205.3 | (4.5 | ) | 1.2 | 202.0 | ||||||||||
Purchases in place | 2.3 | — | — | 2.3 | |||||||||||
Extensions, discoveries and other additions | 385.4 | 29.3 | 6.1 | 420.8 | |||||||||||
Sales in place | (20.7 | ) | — | — | (20.7 | ) | |||||||||
Production | (203.4 | ) | (19.4 | ) | (1.6 | ) | (224.4 | ) | |||||||
Ending Reserves | 2,457.3 | 53.1 | 16.6 | 2,527.0 | |||||||||||
Net Proved Developed Reserves (MMBoe) | |||||||||||||||
At December 31, 2016 | 1,038.5 | 44.5 | 10.9 | 1,093.9 | |||||||||||
At December 31, 2017 | 1,300.7 | 50.8 | 12.8 | 1,364.3 | |||||||||||
2017 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ Millions) | |||||||||||||||
United States | Trinidad | Other International | Total | ||||||||||||
Acquisition Cost of Unproved Properties | $ | 424.1 | $ | 2.4 | $ | — | $ | 426.5 | |||||||
Exploration Costs | 144.5 | 62.6 | 16.5 | 223.6 | |||||||||||
Development Costs | 3,540.7 | 107.2 | 13.2 | 3,661.1 | |||||||||||
Total Drilling | 4,109.3 | 172.2 | 29.7 | 4,311.2 | |||||||||||
Acquisition Cost of Proved Properties | 72.6 | — | — | 72.6 | |||||||||||
Asset Retirement Costs | 50.2 | 2.3 | 3.1 | 55.6 | |||||||||||
Total Exploration & Development Expenditures | 4,232.1 | 174.5 | 32.8 | 4,439.4 | |||||||||||
Gathering, Processing and Other | 173.0 | 0.1 | 0.2 | 173.3 | |||||||||||
Total Expenditures | 4,405.1 | 174.6 | 33.0 | 4,612.7 | |||||||||||
Proceeds from Sales in Place | (226.6 | ) | — | — | (226.6 | ) | |||||||||
Net Expenditures | $ | 4,178.5 | $ | 174.6 | $ | 33.0 | $ | 4,386.1 | |||||||
RESERVE REPLACEMENT COSTS ($ / Boe) * | |||||||||||||||
All-in Total, Net of Revisions | $ | 6.58 | $ | 6.94 | $ | 4.07 | $ | 6.56 | |||||||
All-in Total, Excluding Revisions Due to Price | $ | 8.88 | $ | 6.94 | $ | 4.07 | $ | 8.71 | |||||||
RESERVE REPLACEMENT * | |||||||||||||||
Drilling Only | 190 | % | 151 | % | 381 | % | 188 | % | |||||||
All-in Total, Net of Revisions & Dispositions | 281 | % | 128 | % | 456 | % | 269 | % | |||||||
All-in Total, Excluding Revisions Due to Price | 206 | % | 128 | % | 456 | % | 201 | % | |||||||
All-in Total, Liquids | 244 | % | 133 | % | -50 | % | 244 | % | |||||||
* See attached reconciliation schedule for calculation methodology |
EOG RESOURCES, INC. Quantitative Reconciliation of Total Exploration and Development Expenditures (Non-GAAP) As Used in the Calculation of Reserve Replacement Costs ($ / BOE) To Total Costs Incurred in Exploration and Development Activities (GAAP) (Unaudited; in millions, except ratio information) | |||||||||||||||
The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Reserve Replacement Costs per Boe. There are numerous ways that industry participants present Reserve Replacement Costs, including an “All-In” calculation, which reflects total exploration and development expenditures divided by total net proved reserve additions from all sources. Combined with Reserve Replacement, these statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry. Please note that the actual cost of adding reserves will vary from the reported statistics due to timing differences in reserve bookings and capital expenditures. Accordingly, some analysts use three or five year averages of reported statistics, while others prefer to estimate future costs. EOG has not included future capital costs to develop proved undeveloped reserves in exploration and development expenditures. | |||||||||||||||
For the Twelve Months Ended December 31, 2017 | |||||||||||||||
United States | Trinidad | Other International | Total | ||||||||||||
Total Costs Incurred in Exploration and Development Activities (GAAP) | $ | 4,232.1 | $ | 174.5 | $ | 32.8 | $ | 4,439.4 | |||||||
Less: Asset Retirement Costs | (50.2 | ) | (2.3 | ) | (3.1 | ) | (55.6 | ) | |||||||
Non-Cash Acquisition Costs of Unproved Properties | (255.7 | ) | — | — | (255.7 | ) | |||||||||
Non-Cash Acquisition Cost of Proved Properties | (26.2 | ) | — | — | (26.2 | ) | |||||||||
Total Exploration & Development Expenditures (Non-GAAP) (a) | $ | 3,900.0 | $ | 172.2 | $ | 29.7 | $ | 4,101.9 | |||||||
Total Expenditures (GAAP) | $ | 4,405.1 | $ | 174.6 | $ | 33.0 | $ | 4,612.7 | |||||||
Less: Asset Retirement Costs | (50.2 | ) | (2.3 | ) | (3.1 | ) | (55.6 | ) | |||||||
Non-Cash Acquisition Costs of Unproved Properties | (255.7 | ) | — | — | (255.7 | ) | |||||||||
Non-Cash Acquisition Costs of Proved Properties | (26.2 | ) | — | — | (26.2 | ) | |||||||||
Total Cash Expenditures (Non-GAAP) | $ | 4,073.0 | $ | 172.3 | $ | 29.9 | $ | 4,275.2 | |||||||
Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe) | |||||||||||||||
Revisions due to price (b) | 154.0 | — | — | 154.0 | |||||||||||
Revisions other than price | 51.3 | (4.5 | ) | 1.2 | 48.0 | ||||||||||
Purchases in place | 2.3 | — | — | 2.3 | |||||||||||
Extensions, discoveries and other additions (c) | 385.4 | 29.3 | 6.1 | 420.8 | |||||||||||
Total Proved Reserve Additions (d) | 593.0 | 24.8 | 7.3 | 625.1 | |||||||||||
Sales in place | (20.7 | ) | — | — | (20.7 | ) | |||||||||
Net Proved Reserve Additions From All Sources (e) | 572.3 | 24.8 | 7.3 | 604.4 | |||||||||||
Production (f) | 203.4 | 19.4 | 1.6 | 224.4 | |||||||||||
RESERVE REPLACEMENT COSTS ($ / Boe) | |||||||||||||||
All-in Total, Net of Revisions (a / d) | $ | 6.58 | $ | 6.94 | $ | 4.07 | $ | 6.56 | |||||||
All-in Total, Excluding Revisions Due to Price (a / (d - b)) | $ | 8.88 | $ | 6.94 | $ | 4.07 | $ | 8.71 | |||||||
RESERVE REPLACEMENT | |||||||||||||||
Drilling Only (c / f) | 190 | % | 151 | % | 381 | % | 188 | % | |||||||
All-in Total, Net of Revisions & Dispositions (e / f) | 281 | % | 128 | % | 456 | % | 269 | % | |||||||
All-in Total, Excluding Revisions Due to Price ((e - b) / f) | 206 | % | 128 | % | 456 | % | 201 | % | |||||||
Net Proved Reserve Additions From All Sources - Liquids (MMBbl) | |||||||||||||||
Revisions | 104.9 | 0.1 | (0.2 | ) | 104.8 | ||||||||||
Purchases in place | 1.5 | — | — | 1.5 | |||||||||||
Extensions, discoveries and other additions (g) | 282.1 | 0.3 | 0.1 | 282.5 | |||||||||||
Total Proved Reserve Additions | 388.5 | 0.4 | (0.1 | ) | 388.8 | ||||||||||
Sales in place | (11.3 | ) | — | — | (11.3 | ) | |||||||||
Net Proved Reserve Additions From All Sources (h) | 377.2 | 0.4 | (0.1 | ) | 377.5 | ||||||||||
Production (i) | 154.5 | 0.3 | 0.2 | 155.0 | |||||||||||
RESERVE REPLACEMENT - LIQUIDS | |||||||||||||||
Drilling Only (g / i) | 183 | % | 100 | % | 50 | % | 182 | % | |||||||
All-in Total, Net of Revisions & Dispositions (h / i) | 244 | % | 133 | % | -50 | % | 244 | % |
EOG RESOURCES, INC. Quantitative Reconciliation of Drillbit Exploration and Development Expenditures (Non-GAAP) As Used in the Calculation of Proved Developed Reserve Replacement Costs ($ / BOE) To Total Costs incurred in Exploration and Development Activities (GAAP) (Unaudited; in millions, except ratio data) | |||
The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Drillbit Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Proved Developed Reserve Replacement Costs per Boe. These statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry. | |||
For the Twelve Months Ended December 31, 2017 | |||
PROVED DEVELOPED RESERVE REPLACEMENT COSTS ($ / Boe) | Total | ||
Total Costs Incurred in Exploration and Development Activities (GAAP) | $ | 4,439.4 | |
Less: Asset Retirement Costs | (55.6 | ) | |
Acquisition Costs of Unproved Properties | (426.5 | ) | |
Acquisition Cost of Proved Properties | (72.6 | ) | |
Drillbit Exploration & Development Expenditures (Non-GAAP) (j) | $ | 3,884.7 | |
Total Proved Reserves - Extensions, discoveries and other additions (MMBoe) | 420.8 | ||
Add: Conversion of proved undeveloped reserves to proved developed | 152.6 | ||
Less: Proved undeveloped extensions and discoveries | (237.4 | ) | |
Proved Developed Reserves - Extensions and discoveries (MMBoe) | 336.0 | ||
Total Proved Reserves - Revisions (MMBoe) | 202.0 | ||
Less: Proved Undeveloped Reserves - Revisions | (33.1 | ) | |
Proved Developed - Revisions due to price | (143.0 | ) | |
Proved Developed Reserves - Revisions other than price (MMBoe) | 25.9 | ||
Proved Developed Reserves - Extensions and discoveries plus revisions other than price (MMBoe) (k) | 361.9 | ||
Proved Developed Reserve Replacement Cost Excluding Revisions Due to Price ($ / Boe) (j / k) | $ | 10.73 |
EOG RESOURCES, INC. Crude Oil and Natural Gas Financial Commodity Derivative Contracts | |||||||
EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. Prices received by EOG for its crude oil production generally vary from NYMEX West Texas Intermediate prices due to adjustments for delivery location (basis) and other factors. EOG has entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma (Midland Differential). Presented below is a comprehensive summary of EOG's Midland Differential basis swap contracts through February 20, 2018. The weighted average price differential expressed in $/Bbl represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | |||||||
Midland Differential Basis Swap Contracts | |||||||
Volume (Bbld) | Weighted Average Price Differential ($/Bbl) | ||||||
2018 | |||||||
January 1, 2018 through February 28, 2018 (closed) | 15,000 | $ | 1.063 | ||||
March 1, 2018 through December 31, 2018 | 15,000 | 1.063 | |||||
2019 | |||||||
January 1, 2019 through December 31, 2019 | 20,000 | $ | 1.075 | ||||
EOG has entered into additional crude oil basis swap contracts in order to fix the differential between pricing in the U.S. Gulf Coast and Cushing, Oklahoma (Gulf Coast Differential). Presented below is a comprehensive summary of EOG's Gulf Coast Differential basis swap contracts through February 20, 2018. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. |
Gulf Coast Differential Basis Swap Contracts | |||||||
Volume (Bbld) | Weighted Average Price Differential ($/Bbl) | ||||||
2018 | |||||||
January 1, 2018 through February 28, 2018 (closed) | 37,000 | $ | 3.818 | ||||
March 1, 2018 through December 31, 2018 | 37,000 | 3.818 | |||||
On March 14, 2017, EOG executed the optional early termination provision granting EOG the right to terminate certain 2017 crude oil price swaps with notional volumes of 30,000 Bbld at a weighted average price of $50.05 per Bbl for the period March 1, 2017 through June 30, 2017. EOG received cash of $4.6 million for the early termination of these contracts, which are included in the table below. Presented below is a comprehensive summary of EOG's crude oil price swap contracts through February 20, 2018, with notional volumes expressed in Bbld and prices expressed in $/Bbl. |
Crude Oil Price Swap Contracts | ||||||||
Volume (Bbld) | Weighted Average Price ($/Bbl) | |||||||
2017 | ||||||||
January 1, 2017 through February 28, 2017 (closed) | 35,000 | $ | 50.04 | |||||
March 1, 2017 through June 30, 2017 (closed) | 30,000 | 50.05 | ||||||
2018 | ||||||||
January 2018 (closed) | 134,000 | $ | 60.04 | |||||
February 1, 2018 through December 31, 2018 | 134,000 | 60.04 | ||||||
On March 14, 2017, EOG entered into a crude oil price swap contract for the period March 1, 2017 through June 30, 2017, with notional volumes of 5,000 Bbld at a price of $48.81 per Bbl. This contract offset the remaining 2017 crude oil price swap contract for the same time period with notional volumes of 5,000 Bbld at a price of $50.00 per Bbl. The net cash EOG received for settling these contracts was $0.7 million. The offsetting contracts are excluded from the above table. |
Presented below is a comprehensive summary of EOG's natural gas price swap contracts through February 20, 2018, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||
Natural Gas Price Swap Contracts | |||||||
Volume (MMBtud) | Weighted Average Price ($/MMBtu) | ||||||
2017 | |||||||
March 1, 2017 through November 30, 2017 (closed) | 30,000 | $ | 3.10 | ||||
2018 | |||||||
March 1, 2018 through November 30, 2018 | 35,000 | $ | 3.00 |
EOG has sold call options which establish a ceiling price for the sale of notional volumes of natural gas as specified in the call option contracts. The call options require that EOG pay the difference between the call option strike price and either the average or last business day NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the call option strike price. In addition, EOG has purchased put options which establish a floor price for the sale of notional volumes of natural gas as specified in the put option contracts. The put options grant EOG the right to receive the difference between the put option strike price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the put option strike price. Presented below is a comprehensive summary of EOG's natural gas call and put option contracts through February 20, 2018, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||||||||
Natural Gas Option Contracts | |||||||||||||
Call Options Sold | Put Options Purchased | ||||||||||||
Volume (MMBtud) | Weighted Average Price ($/MMBtu) | Volume (MMBtud) | Weighted Average Price ($/MMBtu) | ||||||||||
2017 | |||||||||||||
March 1, 2017 through November 30, 2017 (closed) | 213,750 | $ | 3.44 | 171,000 | $ | 2.92 | |||||||
2018 | |||||||||||||
March 1, 2018 through November 30, 2018 | 120,000 | $ | 3.38 | 96,000 | $ | 2.94 |
EOG has also entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts. The collars require that EOG pay the difference between the ceiling price and the Henry Hub Index Price in the event the Henry Hub Index Price is above the ceiling price. The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price. Presented below is a comprehensive summary of EOG's natural gas collar contracts through February 20, 2018, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | ||||||||||
Natural Gas Collar Contracts | ||||||||||
Weighted Average Price ($/MMBtu) | ||||||||||
Volume (MMBtud) | Ceiling Price | Floor Price | ||||||||
2017 | ||||||||||
March 1, 2017 through November 30, 2017 (closed) | 80,000 | $ | 3.69 | $ | 3.20 |
Definitions | ||
Bbld | Barrels per day | |
$/Bbl | Dollars per barrel | |
MMBtud | Million British thermal units per day | |
$/MMBtu | Dollars per million British thermal units | |
NYMEX | U.S. New York Mercantile Exchange |
EOG RESOURCES, INC. |
Direct After-Tax Rate of Return (ATROR) |
The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated recoverable reserves ("net" to EOG’s interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements. |
Direct ATROR |
Based on Cash Flow and Time Value of Money |
- Estimated future commodity prices and operating costs |
- Costs incurred to drill, complete and equip a well, including facilities |
Excludes Indirect Capital |
- Gathering and Processing and other Midstream |
- Land, Seismic, Geological and Geophysical |
Payback ~12 Months on 100% Direct ATROR Wells |
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured |
Return on Equity / Return on Capital Employed |
Based on GAAP Accrual Accounting |
Includes All Indirect Capital and Growth Capital for Infrastructure |
- Eagle Ford, Bakken, Permian Facilities |
- Gathering and Processing |
Includes Legacy Gas Capital and Capital from Mature Wells |
EOG RESOURCES, INC. Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Loss) (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculations of Return on Capital Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest Expense (GAAP), Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively (Unaudited; in millions, except ratio data) | |||||||||||||||||||
The following chart reconciles Net Interest Expense (GAAP), Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Loss) (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income (Loss), Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||||||||||
2017 | 2016 | 2015 | 2014 | 2013 | |||||||||||||||
Return on Capital Employed (ROCE) (Non-GAAP) | |||||||||||||||||||
Net Interest Expense (GAAP) | $ | 274 | $ | 282 | $ | 237 | $ | 201 | |||||||||||
Tax Benefit Imputed (based on 35%) | (96 | ) | (99 | ) | (83 | ) | (70 | ) | |||||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 178 | $ | 183 | $ | 154 | $ | 131 | |||||||||||
Net Income (Loss) (GAAP) - (b) | $ | 2,583 | $ | (1,097 | ) | $ | (4,525 | ) | 2,915 | ||||||||||
Adjustments to Net Income (Loss), Net of Tax (See Accompanying Schedules) | (1,934 | ) | (a) | 204 | (b) | 4,559 | (c) | (199 | ) | (d) | |||||||||
Adjusted Net Income (Loss) (Non-GAAP) - (c) | $ | 649 | $ | (893 | ) | $ | 34 | $ | 2,716 | ||||||||||
Total Stockholders' Equity Before Retained Earnings Adjustment (GAAP) - (d) | $ | 16,283 | $ | 13,982 | $ | 12,943 | $ | 17,713 | $ | 15,418 | |||||||||
Less: Tax Reform Impact | (2,169 | ) | — | — | — | — | |||||||||||||
Total Stockholders' Equity (Non-GAAP) - (e) | $ | 14,114 | $ | 13,982 | $ | 12,943 | $ | 17,713 | $ | 15,418 | |||||||||
Average Total Stockholders' Equity (GAAP) * - (f) | $ | 15,133 | $ | 13,463 | $ | 15,328 | $ | 16,566 | |||||||||||
Average Total Stockholders' Equity (Non-GAAP) * - (g) | $ | 14,048 | $ | 13,463 | $ | 15,328 | $ | 16,566 | |||||||||||
Current and Long-Term Debt (GAAP) - (h) | $ | 6,387 | $ | 6,986 | $ | 6,655 | $ | 5,906 | $ | 5,909 | |||||||||
Less: Cash | (834 | ) | (1,600 | ) | (719 | ) | (2,087 | ) | (1,318 | ) | |||||||||
Net Debt (Non-GAAP) - (i) | $ | 5,553 | $ | 5,386 | $ | 5,936 | $ | 3,819 | $ | 4,591 | |||||||||
Total Capitalization (GAAP) - (d) + (h) | $ | 22,670 | $ | 20,968 | $ | 19,598 | $ | 23,619 | $ | 21,327 | |||||||||
Total Capitalization (Non-GAAP) - (e) + (i) | $ | 19,667 | $ | 19,368 | $ | 18,879 | $ | 21,532 | $ | 20,009 | |||||||||
Average Total Capitalization (Non-GAAP) * - (j) | $ | 19,518 | $ | 19,124 | $ | 20,206 | $ | 20,771 | |||||||||||
ROCE (GAAP Net Income) - [(a) + (b)] / (j) | 14.1 | % | -4.8 | % | -21.6 | % | 14.7 | % | |||||||||||
ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (j) | 4.2 | % | -3.7 | % | 0.9 | % | 13.7 | % | |||||||||||
Return on Equity (ROE) | |||||||||||||||||||
ROE (GAAP) (GAAP Net Income) - (b) / (f) | 17.1 | % | -8.1 | % | -29.5 | % | 17.6 | % | |||||||||||
ROE (Non-GAAP) (Non-GAAP Adjusted Net Income) - (c) / (g) | 4.6 | % | -6.6 | % | 0.2 | % | 16.4 | % | |||||||||||
* Average for the current and immediately preceding year |
(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. First Quarter and Full Year 2018 Forecast and Benchmark Commodity Pricing | |||||||||||||||||||
(a) First Quarter and Full Year 2018 Forecast | |||||||||||||||||||
The forecast items for the first quarter and full year 2018 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. | |||||||||||||||||||
(b) Benchmark Commodity Pricing | |||||||||||||||||||
EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. | |||||||||||||||||||
EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month. | |||||||||||||||||||
Estimated Ranges (Unaudited) | |||||||||||||||||||
1Q 2018 | Full Year 2018 | ||||||||||||||||||
Daily Sales Volumes | |||||||||||||||||||
Crude Oil and Condensate Volumes (MBbld) | |||||||||||||||||||
United States | 350.0 | - | 360.0 | 387.0 | - | 401.0 | |||||||||||||
Trinidad | 0.5 | - | 0.7 | 0.4 | - | 0.6 | |||||||||||||
Other International | 0.0 | - | 5.0 | 2.0 | - | 4.0 | |||||||||||||
Total | 350.5 | - | 365.7 | 389.4 | - | 405.6 | |||||||||||||
Natural Gas Liquids Volumes (MBbld) | |||||||||||||||||||
Total | 93.0 | - | 103.0 | 100.0 | - | 110.0 | |||||||||||||
Natural Gas Volumes (MMcfd) | |||||||||||||||||||
United States | 825 | - | 865 | 900 | - | 950 | |||||||||||||
Trinidad | 280 | - | 310 | 250 | - | 290 | |||||||||||||
Other International | 25 | - | 35 | 28 | - | 38 | |||||||||||||
Total | 1,130 | - | 1,210 | 1,178 | - | 1,278 | |||||||||||||
Crude Oil Equivalent Volumes (MBoed) | |||||||||||||||||||
United States | 580.5 | - | 607.2 | 637.0 | - | 669.3 | |||||||||||||
Trinidad | 47.2 | - | 52.4 | 42.1 | - | 48.9 | |||||||||||||
Other International | 4.2 | - | 10.8 | 6.7 | - | 10.3 | |||||||||||||
Total | 631.9 | - | 670.4 | 685.8 | - | 728.5 | |||||||||||||
Estimated Ranges (Unaudited) | |||||||||||||||||||
1Q 2018 | Full Year 2018 | ||||||||||||||||||
Operating Costs | |||||||||||||||||||
Unit Costs ($/Boe) | |||||||||||||||||||
Lease and Well | $ | 4.70 | - | $ | 5.10 | $ | 4.20 | - | $ | 4.80 | |||||||||
Transportation Costs | $ | 3.00 | - | $ | 3.50 | $ | 2.75 | - | $ | 3.25 | |||||||||
Depreciation, Depletion and Amortization | $ | 13.00 | - | $ | 13.40 | $ | 13.10 | - | $ | 13.50 | |||||||||
Expenses ($MM) | |||||||||||||||||||
Exploration, Dry Hole and Impairment | $ | 90 | - | $ | 120 | $ | 375 | - | $ | 425 | |||||||||
General and Administrative | $ | 100 | - | $ | 110 | $ | 415 | - | $ | 445 | |||||||||
Gathering and Processing | $ | 95 | - | $ | 105 | $ | 430 | - | $ | 470 | |||||||||
Capitalized Interest | $ | 6 | - | $ | 8 | $ | 27 | - | $ | 32 | |||||||||
Net Interest | $ | 60 | - | $ | 62 | $ | 234 | - | $ | 242 | |||||||||
Taxes Other Than Income (% of Wellhead Revenue) | 6.6 | % | - | 7.0 | % | 6.5 | % | - | 6.9 | % | |||||||||
Income Taxes | |||||||||||||||||||
Effective Rate | 20 | % | - | 25 | % | 20 | % | - | 25 | % | |||||||||
Current Taxes ($MM) | $ | (90 | ) | - | $ | (55 | ) | $ | (310 | ) | - | $ | (270 | ) | |||||
Capital Expenditures (Excluding Acquisitions, $MM) | |||||||||||||||||||
Exploration and Development, Excluding Facilities | $ | 4,500 | - | $ | 4,800 | ||||||||||||||
Exploration and Development Facilities | $ | 600 | - | $ | 650 | ||||||||||||||
Gathering, Processing and Other | $ | 300 | - | $ | 350 | ||||||||||||||
Pricing - (Refer to Benchmark Commodity Pricing in text) | |||||||||||||||||||
Crude Oil and Condensate ($/Bbl) | |||||||||||||||||||
Differentials | |||||||||||||||||||
United States - above (below) WTI | $ | 0.00 | - | $ | 1.50 | $ | (1.00 | ) | - | $ | 1.00 | ||||||||
Trinidad - above (below) WTI | $ | (11.00 | ) | - | $ | (9.00 | ) | $ | (11.00 | ) | - | $ | (9.00 | ) | |||||
Other International - above (below) WTI | $ | 0.00 | - | $ | 2.00 | $ | 0.00 | - | $ | 2.00 | |||||||||
Natural Gas Liquids | |||||||||||||||||||
Realizations as % of WTI | 39 | % | - | 45 | % | 40 | % | - | 46 | % | |||||||||
Natural Gas ($/Mcf) | |||||||||||||||||||
Differentials | |||||||||||||||||||
United States - above (below) NYMEX Henry Hub | $ | (0.40 | ) | - | $ | 0.00 | $ | (0.60 | ) | - | $ | 0.00 | |||||||
Realizations | |||||||||||||||||||
Trinidad | $ | 2.50 | - | $ | 2.90 | $ | 2.15 | - | $ | 2.75 | |||||||||
Other International | $ | 4.15 | - | $ | 4.65 | $ | 4.00 | - | $ | 5.00 | |||||||||
Definitions | |||||||||||||||||||
$/Bbl | U.S. Dollars per barrel | ||||||||||||||||||
$/Boe | U.S. Dollars per barrel of oil equivalent | ||||||||||||||||||
$/Mcf | U.S. Dollars per thousand cubic feet | ||||||||||||||||||
$MM | U.S. Dollars in millions | ||||||||||||||||||
MBbld | Thousand barrels per day | ||||||||||||||||||
MBoed | Thousand barrels of oil equivalent per day | ||||||||||||||||||
MMcfd | Million cubic feet per day | ||||||||||||||||||
NYMEX | U.S. New York Mercantile Exchange | ||||||||||||||||||
WTI | West Texas Intermediate |
EOG RESOURCES, INC. Fourth Quarter 2017 Well Results by Play (Unaudited) | |||||||||||||||||||||
Wells Completed | Initial 30-Day Average Production Rate | ||||||||||||||||||||
Gross | Net | Lateral 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 | 51 | 45 | 6,000 | 1,410 | 310 | 2.5 | 2,145 | ||||||||||||||
Bone Spring | 9 | 9 | 6,700 | 1,085 | 160 | 1.3 | 1,470 | ||||||||||||||
Leonard | 5 | 5 | 8,700 | 1,230 | 265 | 2.2 | 1,865 | ||||||||||||||
Powder River Basin Turner | 9 | 7 | 7,700 | 990 | 375 | 4.7 | 2,150 | ||||||||||||||
DJ Basin Codell | 3 | 2 | 9,100 | 950 | 105 | 0.4 | 1,120 | ||||||||||||||
South Texas Eagle Ford | 74 | 70 | 7,400 | 1,525 | 195 | 1.1 | 1,915 | ||||||||||||||
South Texas Austin Chalk | 4 | 4 | 5,300 | 2,280 | 430 | 2.5 | 3,130 | ||||||||||||||
(A) Barrels per day or million cubic feet per day, as applicable. | |||||||||||||||||||||
(B) Barrels of oil equivalent per day; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. |
65A&-H86YG92 I(%1J($54(%$*<2 P(# @,"!R9R!"
M5" R,#4N,C(@-34P+C(U(%1D("A!8W0@*2!4:B!%5"!1"G$@," P(# @ 2 I(%1J($54(%$*0E0@
M+T8Q(#$P+C P(%1F($54"G$@," P(# @ '1E;G0@*2!4
M:B!%5"!1"G$@," P(# @'!R97-S960@*2!4
M:B!%5"!1"G$@," P(# @