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| 8-K - 8-K - EOG RESOURCES INC | eog8kpressrelease022516.htm |
| 8-K - 8-K PDF FILE - EOG RESOURCES INC | eog8kpressrelease022516.pdf |
EXHIBIT 99.1
EOG Resources, Inc. | P.O. Box 4362 Houston, TX 77210-4362 |
News Release | |
For Further Information Contact: | Investors |
Cedric W. Burgher | |
(713) 571-4658 | |
David J. Streit | |
(713) 571-4902 | |
Kimberly M. Ehmer | |
(713) 571-4676 | |
Media | |
K Leonard | |
(713) 571-3870 | |
EOG Resources Reports Fourth Quarter and Full Year 2015 Results and Announces 2016 Capital Program Focused on Premium Drilling Inventory
• | Exceeds Fourth Quarter and Full Year 2015 Production Targets |
• | Achieves Record Year for Improved Well Productivity and Efficiency Gains |
• | Reduces Fourth Quarter Per-Unit Lease and Well Expenses by 30 Percent Versus Prior Year |
• | Replaces 192 Percent of 2015 Production, Excluding Price Revisions |
• | Announces Disciplined 2016 Capital Plan and Operations Strategy |
• | Defines More Than 2.0 BnBoe and 10 Years of Premium Drilling Inventory |
FOR IMMEDIATE RELEASE: Thursday, February 25, 2016
HOUSTON - EOG Resources, Inc. (EOG) today reported a fourth quarter 2015 net loss of $284.3 million, or $0.52 per share. This compares to fourth quarter 2014 net income of $444.6 million, or $0.81 per share. For the full year 2015, EOG reported a net loss of $4.5 billion, or $8.29 per share, compared to net income of $2.9 billion, or $5.32 per share, for the full year 2014.
Adjusted non-GAAP net loss for the fourth quarter 2015 was $149.5 million, or $0.27 per share, compared to adjusted non-GAAP net income of $431.9 million, or $0.79 per share, for the same prior year period. Adjusted non-GAAP net income for the full year 2015 was $33.9 million, or $0.06 per share, compared to non-GAAP net income of $2.7 billion, or $4.95 per share, for the full year 2014. Adjusted non-GAAP net income (loss) is calculated by matching realizations to settlement months and making certain other adjustments in order to exclude one-time items. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.)
Significant reductions in operating expenses were more than offset by lower commodity prices, resulting in decreases to adjusted non-GAAP net income, discretionary cash flow and EBITDAX during
the fourth quarter and full year 2015 compared to the same periods in 2014. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.)
“EOG’s performance was resilient in 2015 as oil and natural gas prices declined sharply,” said William R. “Bill” Thomas, Chairman and Chief Executive Officer. “We achieved significant reductions in our finding and operating costs and substantially increased the size and the quality of our inventory, which further enhances our unique ability to create long-term shareholder value.”
Operational Highlights
For the full year 2015, while exploration and development expenditures (excluding acquisitions) decreased 42 percent, U.S. crude oil and condensate production remained flat, and overall total company production decreased just 4 percent compared to 2014. Total worldwide liquids production decreased 2 percent, and total worldwide natural gas production decreased 7 percent versus the prior year.
EOG restrained capital expenditures in the fourth quarter 2015 in response to the lower commodity price environment. Total exploration and development expenditures decreased 56 percent compared to the same prior year period. EOG’s U.S. crude oil and condensate production and total overall company production both decreased by 7 percent in the fourth quarter of 2015 compared to the same prior year period.
EOG continued to enhance operating efficiencies and leverage prior investments in infrastructure, resulting in cost reductions across its operations. During the fourth quarter of 2015, lease and well expenses decreased 30 percent and transportation costs decreased 8 percent compared to the same prior year period, both on a per-unit basis. Total general and administrative expenses decreased 17 percent compared to the fourth quarter 2014.
“EOG remained focused on returns and capital discipline in 2015,” Thomas said. “Our team raised the bar with record-setting operational achievements, technical advances and organic growth additions. These sustainable improvements uniquely position EOG for long-term success in any commodity price environment.”
2016 Capital Plan
EOG’s 2016 plan is designed to maximize returns, maintain the strong balance sheet and continue to achieve record-setting cost reduction and productivity gains.
Capital expenditures for 2016 are expected to range from $2.4 to $2.6 billion, including production facilities and gathering, processing and other expenditures, and excluding acquisitions. EOG expects to complete approximately 270 net wells in 2016, compared to 470 net wells in 2015, with total company crude oil production expected to decline only 5 percent versus 2015. This 45 to 50 percent year-over-year
reduction to capital expenditures reflects the current commodity price environment and further demonstrates EOG’s commitment to maintaining a strong balance sheet with disciplined capital spending.
The company is shifting its focus to premium drilling and completions in 2016. Driven by continued efficiencies, technical advancements and geoscience breakthroughs, the company has identified over 3,200 premium drilling locations capable of delivering solid rates of return at low commodity prices. Premium drilling is a step change to EOG’s long-term strategy that will enable it to expand its leadership in investment returns and well performance. The company is now positioned to return to high investment rates of return as oil prices experience even a modest recovery.
“EOG has now identified more than 2 billion barrels of oil equivalent (BnBoe) of estimated net resource potential and a decade of premium drilling inventory that can earn superior returns in a low commodity price environment,” Thomas said. “Breakthroughs of this magnitude are unique and will enable EOG to extend its lead as the low-cost U.S. horizontal oil producer. We are confident our organic growth machine will continue to increase both the size and quality of our premium drilling inventory and allow EOG to enjoy a strong competitive advantage in the world oil market.”
South Texas Eagle Ford
The South Texas Eagle Ford continues to showcase EOG’s technological advances in lateral placement and completion design. During 2015, the company expanded the use of precision lateral targeting and high-density completions across the Eagle Ford. EOG’s other plays benefit from these industry-leading breakthroughs by quickly adapting these new technologies to each unique environment.
During the fourth quarter of 2015, the Eagle Ford once again delivered outstanding well performance across the play. In the eastern Eagle Ford in Karnes County, the Lightfoot Unit 5H through 8H four-well pattern had average 30-day initial production rates per well of 2,425 barrels of oil per day (Bopd), 285 barrels per day (Bpd) of natural gas liquids (NGLs) and 1.9 million cubic feet per day (MMcfd) of natural gas. In Gonzales County, the Lepori Unit 4H had 30-day initial production rates of 2,915 Bopd, 370 Bpd of NGLs and 2.4 MMcfd of natural gas. In the western Eagle Ford in McMullen County, the Naylor Jones Unit 31-1H had 30-day initial production rates of 1,780 Bopd, 165 Bpd of NGLs and 1.1 MMcfd of natural gas.
In 2016, EOG plans to complete approximately 150 net wells in the Eagle Ford, compared to 329 net wells completed in 2015.
Delaware Basin
2015 was an important year for EOG in the Delaware Basin where EOG increased its estimated net resource potential by 1.0 BnBoe. With approximately 2.35 BnBoe in total estimated net resource
potential, EOG possesses a premier position in the Permian’s best horizontal oil basin. EOG made significant advances in the basin in 2015 by expanding its technical understanding and improving returns by increasing well productivity and reducing costs.
In the Delaware Basin Wolfcamp, EOG completed a dozen wells in the fourth quarter 2015 with average 30-day initial production rates per well of 1,495 Bopd, 300 Bpd of NGLs and 2.5 MMcfd of natural gas.
EOG’s 2016 plans for the Delaware Basin include completing approximately 75 net wells versus 74 net wells completed in 2015.
North Dakota Bakken and Rockies
EOG continues to advance its high-potential Rockies oil plays. In 2015, EOG added 600 million barrels of oil equivalent (MMBoe) to its Bakken net resource potential estimate, bringing EOG’s total net resource potential estimate to approximately 1.0 BnBoe. EOG has decades of drilling inventory in this world-class oil basin.
During 2015, EOG continued to delineate its Powder River Basin and DJ Basin oil plays. In the fourth quarter 2015, EOG completed several wells in the Powder River Basin Turner oil play. The Blade 202-2116H and the Flatbow 602-1621H had 30-day initial production rates of 1,300 Bopd, 120 Bpd of NGLs and 1.4 MMcfd of natural gas, and 1,280 Bopd, 145 Bpd of NGLs and 1.7 MMcfd of natural gas, respectively.
In 2016, EOG plans to complete approximately 35 net wells in these plays, compared to 48 net wells in 2015.
Reserves
At year-end, total company net proved reserves were 2,118 MMBoe, comprised of 52 percent crude oil and condensate, 18 percent NGLs and 30 percent natural gas. Net proved reserve additions, excluding revisions due to price, replaced 192 percent of EOG’s 2015 production at a finding and development cost of $11.91 per barrel of oil equivalent. Revisions due to price reduced net proved reserves by 574 MMBoe. Driven by declines in commodity prices, total company net proved reserves decreased 15 percent in 2015. (For more reserves detail, including calculation of reserve replacement ratios and reserve replacement costs, please refer to the attached tables.)
For the 28th consecutive year, internal reserve estimates were within 5 percent of estimates independently prepared by DeGolyer and MacNaughton.
Hedging Activity
For the period March 1 through August 31, 2016, EOG has natural gas financial price swap contracts in place for 60,000 million British thermal units (MMBtu) per day at a weighted average price of $2.49 per MMBtu. EOG has no crude oil financial price contracts in place. A comprehensive summary of natural gas derivative contracts is provided in the attached tables.
Capital Structure
At December 31, 2015, EOG’s total debt outstanding was $6.7 billion with a debt-to-total capitalization ratio of 34 percent. Taking into account cash on the balance sheet of $719 million at year-end, EOG’s net debt was $5.9 billion with a net debt-to-total capitalization ratio of 31 percent. A reconciliation of non-GAAP measures to GAAP measures is provided in the attached tables.
Dividend
The board of directors declared a dividend of $0.1675 per share on EOG’s Common Stock, payable April 29, 2016, to stockholders of record as of April 15, 2016. The indicated annual rate is $0.67 per share.
Conference Call February 26, 2016
EOG’s fourth quarter 2015 results conference call will be available via live audio webcast at 9 a.m. Central time (10 a.m. Eastern time) on Friday, February 26, 2016. To listen, log on to www.eogresources.com. The webcast will be archived on EOG’s website through March 11, 2016.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG."
This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production and costs, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, reduce or otherwise control operating and capital costs, generate income or cash flows or pay dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable
and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
• | the timing, extent and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities; |
• | the extent to which EOG is successful in its efforts to acquire or discover additional reserves; |
• | the extent to which EOG is successful in its efforts to economically develop its acreage in, produce reserves and achieve anticipated production levels from, and maximize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects; |
• | the extent to which EOG is successful in its efforts to market its crude oil and condensate, natural gas liquids, natural gas and related commodity production; |
• | the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, transportation and refining facilities; |
• | the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights-of-way, and EOG’s ability to retain mineral licenses and leases; |
• | the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations; environmental, health and safety laws and regulations relating to air emissions, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities; |
• | EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties; |
• | the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully and economically; |
• | competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties, employees and other personnel, facilities, equipment, materials and services; |
• | the availability and cost of employees and other personnel, facilities, equipment, materials (such as water) and services; |
• | the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise; |
• | weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression and transportation facilities; |
• | the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG; |
• | EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements; |
• | the extent 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 13 through 21 of EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2015, and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K. |
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration and extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only “proved” reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also “probable” reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as “possible” reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC’s latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2015, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
###
EOG RESOURCES, INC. Financial Report (Unaudited; in millions, except per share data) | |||||||||||||||
Three Months Ended | Twelve Months Ended | ||||||||||||||
December 31, | December 31, | ||||||||||||||
2015 | 2014 | 2015 | 2014 | ||||||||||||
Net Operating Revenues | $ | 1,796.8 | $ | 4,645.5 | $ | 8,757.4 | $ | 18,035.3 | |||||||
Net Income (Loss) | $ | (284.3 | ) | $ | 444.6 | $ | (4,524.5 | ) | $ | 2,915.5 | |||||
Net Income (Loss) Per Share | |||||||||||||||
Basic | $ | (0.52 | ) | $ | 0.82 | $ | (8.29 | ) | $ | 5.36 | |||||
Diluted | $ | (0.52 | ) | $ | 0.81 | $ | (8.29 | ) | $ | 5.32 | |||||
Average Number of Common Shares | |||||||||||||||
Basic | 546.4 | 544.6 | 545.7 | 543.4 | |||||||||||
Diluted | 546.4 | 549.2 | 545.7 | 548.5 | |||||||||||
Summary Income Statements (Unaudited; in thousands, except per share data) | |||||||||||||||
Three Months Ended | Twelve Months Ended | ||||||||||||||
December 31, | December 31, | ||||||||||||||
2015 | 2014 | 2015 | 2014 | ||||||||||||
Net Operating Revenues | |||||||||||||||
Crude Oil and Condensate | $ | 1,040,470 | $ | 2,054,901 | $ | 4,934,562 | $ | 9,742,480 | |||||||
Natural Gas Liquids | 96,521 | 180,916 | 407,658 | 934,051 | |||||||||||
Natural Gas | 217,381 | 407,494 | 1,061,038 | 1,916,386 | |||||||||||
Gains on Mark-to-Market Commodity Derivative Contracts | 4,970 | 750,154 | 61,924 | 834,273 | |||||||||||
Gathering, Processing and Marketing | 432,292 | 806,177 | 2,253,135 | 4,046,316 | |||||||||||
Gains (Losses) on Asset Dispositions, Net | (3,656 | ) | 431,890 | (8,798 | ) | 507,590 | |||||||||
Other, Net | 8,783 | 13,965 | 47,909 | 54,244 | |||||||||||
Total | 1,796,761 | 4,645,497 | 8,757,428 | 18,035,340 | |||||||||||
Operating Expenses | |||||||||||||||
Lease and Well | 247,916 | 380,781 | 1,182,282 | 1,416,413 | |||||||||||
Transportation Costs | 207,580 | 242,293 | 849,319 | 972,176 | |||||||||||
Gathering and Processing Costs | 39,653 | 37,785 | 146,156 | 145,800 | |||||||||||
Exploration Costs | 34,946 | 45,167 | 149,494 | 184,388 | |||||||||||
Dry Hole Costs | 429 | 18,225 | 14,746 | 48,490 | |||||||||||
Impairments | 168,171 | 535,637 | 6,613,546 | 743,575 | |||||||||||
Marketing Costs | 461,848 | 862,589 | 2,385,982 | 4,126,060 | |||||||||||
Depreciation, Depletion and Amortization | 769,457 | 1,013,930 | 3,313,644 | 3,997,041 | |||||||||||
General and Administrative | 109,014 | 131,285 | 366,594 | 402,010 | |||||||||||
Taxes Other Than Income | 87,500 | 151,153 | 421,744 | 757,564 | |||||||||||
Total | 2,126,514 | 3,418,845 | 15,443,507 | 12,793,517 | |||||||||||
Operating Income (Loss) | (329,753 | ) | 1,226,652 | (6,686,079 | ) | 5,241,823 | |||||||||
Other Income (Expense), Net | (6,080 | ) | (28,324 | ) | 1,916 | (45,050 | ) | ||||||||
Income (Loss) Before Interest Expense and Income Taxes | (335,833 | ) | 1,198,328 | (6,684,163 | ) | 5,196,773 | |||||||||
Interest Expense, Net | 62,993 | 49,735 | 237,393 | 201,458 | |||||||||||
Income (Loss) Before Income Taxes | (398,826 | ) | 1,148,593 | (6,921,556 | ) | 4,995,315 | |||||||||
Income Tax Provision (Benefit) | (114,530 | ) | 704,005 | (2,397,041 | ) | 2,079,828 | |||||||||
Net Income (Loss) | $ | (284,296 | ) | $ | 444,588 | $ | (4,524,515 | ) | $ | 2,915,487 | |||||
Dividends Declared per Common Share | $ | 0.1675 | $ | 0.1675 | $ | 0.6700 | $ | 0.5850 | |||||||
EOG RESOURCES, INC. Operating Highlights (Unaudited) | |||||||||||||||
Three Months Ended | Twelve Months Ended | ||||||||||||||
December 31, | December 31, | ||||||||||||||
2015 | 2014 | 2015 | 2014 | ||||||||||||
Wellhead Volumes and Prices | |||||||||||||||
Crude Oil and Condensate Volumes (MBbld) (A) | |||||||||||||||
United States | 279.9 | 301.5 | 283.3 | 282.0 | |||||||||||
Trinidad | 0.9 | 0.9 | 0.9 | 1.0 | |||||||||||
Other International (B) | 0.2 | 5.3 | 0.2 | 5.9 | |||||||||||
Total | 281.0 | 307.7 | 284.4 | 288.9 | |||||||||||
Average Crude Oil and Condensate Prices ($/Bbl) (C) | |||||||||||||||
United States | $ | 40.34 | $ | 72.76 | $ | 47.55 | $ | 92.73 | |||||||
Trinidad | 32.38 | 63.65 | 39.51 | 84.63 | |||||||||||
Other International (B) | 53.28 | 72.91 | 57.32 | 86.75 | |||||||||||
Composite | 40.32 | 72.74 | 47.53 | 92.58 | |||||||||||
Natural Gas Liquids Volumes (MBbld) (A) | |||||||||||||||
United States | 79.1 | 83.1 | 76.9 | 79.7 | |||||||||||
Other International (B) | — | 0.5 | 0.1 | 0.6 | |||||||||||
Total | 79.1 | 83.6 | 77.0 | 80.3 | |||||||||||
Average Natural Gas Liquids Prices ($/Bbl) (C) | |||||||||||||||
United States | $ | 13.25 | $ | 23.48 | $ | 14.50 | $ | 31.84 | |||||||
Other International (B) | — | 31.42 | 4.61 | 40.73 | |||||||||||
Composite | 13.25 | 23.53 | 14.49 | 31.91 | |||||||||||
Natural Gas Volumes (MMcfd) (A) | |||||||||||||||
United States | 860 | 921 | 886 | 920 | |||||||||||
Trinidad | 370 | 329 | 349 | 363 | |||||||||||
Other International (B) | 27 | 60 | 30 | 70 | |||||||||||
Total | 1,257 | 1,310 | 1,265 | 1,353 | |||||||||||
Average Natural Gas Prices ($/Mcf) (C) | |||||||||||||||
United States | $ | 1.44 | $ | 3.21 | $ | 1.97 | $ | 3.93 | |||||||
Trinidad | 2.57 | 3.77 | 2.89 | 3.65 | |||||||||||
Other International (B) | 6.51 | 3.85 | 5.05 | 4.40 | |||||||||||
Composite | 1.88 | 3.38 | 2.30 | 3.88 | |||||||||||
Crude Oil Equivalent Volumes (MBoed) (D) | |||||||||||||||
United States | 502.2 | 538.3 | 507.9 | 515.0 | |||||||||||
Trinidad | 62.7 | 55.7 | 59.1 | 61.5 | |||||||||||
Other International (B) | 4.6 | 15.6 | 5.2 | 18.2 | |||||||||||
Total | 569.5 | 609.6 | 572.2 | 594.7 | |||||||||||
Total MMBoe (D) | 52.4 | 56.1 | 208.9 | 217.1 | |||||||||||
(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. |
(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, | ||||||
2015 | 2014 | ||||||
ASSETS | |||||||
Current Assets | |||||||
Cash and Cash Equivalents | $ | 718,506 | $ | 2,087,213 | |||
Accounts Receivable, Net | 930,610 | 1,779,311 | |||||
Inventories | 598,935 | 706,597 | |||||
Assets from Price Risk Management Activities | — | 465,128 | |||||
Income Taxes Receivable | 40,704 | 71,621 | |||||
Deferred Income Taxes | 147,812 | 19,618 | |||||
Other | 155,677 | 286,533 | |||||
Total | 2,592,244 | 5,416,021 | |||||
Property, Plant and Equipment | |||||||
Oil and Gas Properties (Successful Efforts Method) | 50,613,241 | 46,503,532 | |||||
Other Property, Plant and Equipment | 3,986,610 | 3,750,958 | |||||
Total Property, Plant and Equipment | 54,599,851 | 50,254,490 | |||||
Less: Accumulated Depreciation, Depletion and Amortization | (30,389,130 | ) | (21,081,846 | ) | |||
Total Property, Plant and Equipment, Net | 24,210,721 | 29,172,644 | |||||
Other Assets | 172,279 | 174,022 | |||||
Total Assets | $ | 26,975,244 | $ | 34,762,687 | |||
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||||
Current Liabilities | |||||||
Accounts Payable | $ | 1,471,953 | $ | 2,860,548 | |||
Accrued Taxes Payable | 93,618 | 140,098 | |||||
Dividends Payable | 91,546 | 91,594 | |||||
Deferred Income Taxes | — | 110,743 | |||||
Current Portion of Long-Term Debt | 6,579 | 6,579 | |||||
Other | 155,591 | 174,746 | |||||
Total | 1,819,287 | 3,384,308 | |||||
Long-Term Debt | 6,653,685 | 5,903,354 | |||||
Other Liabilities | 971,335 | 939,497 | |||||
Deferred Income Taxes | 4,587,902 | 6,822,946 | |||||
Commitments and Contingencies | |||||||
Stockholders' Equity | |||||||
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 550,150,823 and 549,028,374 Shares Issued at December 31, 2015 and 2014, respectively | 205,502 | 205,492 | |||||
Additional Paid in Capital | 2,923,461 | 2,837,150 | |||||
Accumulated Other Comprehensive Loss | (33,338 | ) | (23,056 | ) | |||
Retained Earnings | 9,870,816 | 14,763,098 | |||||
Common Stock Held in Treasury, 292,179 Shares and 733,517 Shares at December 31, 2015 and 2014, respectively | (23,406 | ) | (70,102 | ) | |||
Total Stockholders' Equity | 12,943,035 | 17,712,582 | |||||
Total Liabilities and Stockholders' Equity | $ | 26,975,244 | $ | 34,762,687 | |||
EOG RESOURCES, INC. Summary Statements of Cash Flows (Unaudited; in thousands) | |||||||
Twelve Months Ended | |||||||
December 31, | |||||||
2015 | 2014 | ||||||
Cash Flows from Operating Activities | |||||||
Reconciliation of Net Income (Loss) to Net Cash Provided by Operating Activities: | |||||||
Net Income (Loss) | $ | (4,524,515 | ) | $ | 2,915,487 | ||
Items Not Requiring (Providing) Cash | |||||||
Depreciation, Depletion and Amortization | 3,313,644 | 3,997,041 | |||||
Impairments | 6,613,546 | 743,575 | |||||
Stock-Based Compensation Expenses | 130,577 | 145,086 | |||||
Deferred Income Taxes | (2,482,307 | ) | 1,704,946 | ||||
(Gains) Losses on Asset Dispositions, Net | 8,798 | (507,590 | ) | ||||
Other, Net | 11,896 | 48,138 | |||||
Dry Hole Costs | 14,746 | 48,490 | |||||
Mark-to-Market Commodity Derivative Contracts | |||||||
Total Gains | (61,924 | ) | (834,273 | ) | |||
Net Cash Received from Settlements of Commodity Derivative Contracts | 730,114 | 34,007 | |||||
Excess Tax Benefits from Stock-Based Compensation | (26,058 | ) | (99,459 | ) | |||
Other, Net | 12,532 | 13,009 | |||||
Changes in Components of Working Capital and Other Assets and Liabilities | |||||||
Accounts Receivable | 641,412 | 84,982 | |||||
Inventories | 58,450 | (161,958 | ) | ||||
Accounts Payable | (1,409,197 | ) | 543,630 | ||||
Accrued Taxes Payable | 11,798 | 16,486 | |||||
Other Assets | 118,143 | (14,448 | ) | ||||
Other Liabilities | (66,257 | ) | 75,420 | ||||
Changes in Components of Working Capital Associated with Investing and Financing Activities | 499,767 | (103,414 | ) | ||||
Net Cash Provided by Operating Activities | 3,595,165 | 8,649,155 | |||||
Investing Cash Flows | |||||||
Additions to Oil and Gas Properties | (4,725,150 | ) | (7,519,667 | ) | |||
Additions to Other Property, Plant and Equipment | (288,013 | ) | (727,138 | ) | |||
Proceeds from Sales of Assets | 192,807 | 569,332 | |||||
Changes in Restricted Cash | — | 60,385 | |||||
Changes in Components of Working Capital Associated with Investing Activities | (499,900 | ) | 103,523 | ||||
Net Cash Used in Investing Activities | (5,320,256 | ) | (7,513,565 | ) | |||
Financing Cash Flows | |||||||
Net Commercial Paper Borrowings | 259,718 | — | |||||
Long-Term Debt Borrowings | 990,225 | 496,220 | |||||
Long-Term Debt Repayments | (500,000 | ) | (500,000 | ) | |||
Settlement of Foreign Currency Swap | — | (31,573 | ) | ||||
Dividends Paid | (367,005 | ) | (279,695 | ) | |||
Excess Tax Benefits from Stock-Based Compensation | 26,058 | 99,459 | |||||
Treasury Stock Purchased | (48,791 | ) | (127,424 | ) | |||
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan | 22,690 | 22,249 | |||||
Debt Issuance Costs | (5,951 | ) | (895 | ) | |||
Repayment of Capital Lease Obligation | (6,156 | ) | (5,966 | ) | |||
Other, Net | 133 | (109 | ) | ||||
Net Cash Provided by (Used in) Financing Activities | 370,921 | (327,734 | ) | ||||
Effect of Exchange Rate Changes on Cash | (14,537 | ) | (38,852 | ) | |||
Increase (Decrease) in Cash and Cash Equivalents | (1,368,707 | ) | 769,004 | ||||
Cash and Cash Equivalents at Beginning of Period | 2,087,213 | 1,318,209 | |||||
Cash and Cash Equivalents at End of Period | $ | 718,506 | $ | 2,087,213 | |||
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, 2015 and 2014 reported Net Income (Loss) (GAAP) to reflect actual net cash received from settlements of commodity derivative contracts by eliminating the unrealized mark-to-market gains from these transactions, to eliminate the net (gains) losses on asset dispositions, to eliminate the impact of the Texas margin tax rate reduction in 2015, to add back impairment charges related to certain of EOG's assets, to add back an early leasehold termination payment as the result of a legal settlement in 2015, to add back severance costs associated with EOG's North American operations in 2015 and to add back the tax expense related to the anticipated repatriation of accumulated foreign earnings in future years in 2014. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for comparative purposes within the industry. | |||||||||||||||
Three Months Ended | Twelve Months Ended | ||||||||||||||
December 31, | December 31, | ||||||||||||||
2015 | 2014 | 2015 | 2014 | ||||||||||||
Reported Net Income (Loss) (GAAP) | $ | (284,296 | ) | $ | 444,588 | $ | (4,524,515 | ) | $ | 2,915,487 | |||||
Commodity Derivative Contracts Impact | |||||||||||||||
Gains on Mark-to-Market Commodity Derivative Contracts | (4,970 | ) | (750,154 | ) | (61,924 | ) | (834,273 | ) | |||||||
Net Cash Received from Settlements of Commodity Derivative Contracts | 69,093 | 222,944 | 730,114 | 34,007 | |||||||||||
Subtotal | 64,123 | (527,210 | ) | 668,190 | (800,266 | ) | |||||||||
After-Tax MTM Impact | 41,263 | (339,792 | ) | 429,980 | (514,971 | ) | |||||||||
Less: Net (Gains) Losses on Asset Dispositions, Net of Tax | 2,921 | (439,834 | ) | 4,615 | (487,260 | ) | |||||||||
Less: Texas Margin Tax Rate Reduction | — | — | (19,500 | ) | — | ||||||||||
Add: Impairments of Certain Assets, Net of Tax | 78,149 | 517,041 | 4,125,372 | 553,099 | |||||||||||
Add: Legal Settlement - Early Leasehold Termination, Net of Tax | 12,455 | — | 12,455 | — | |||||||||||
Add: Severance Costs, Net of Tax | — | — | 5,473 | — | |||||||||||
Add: Tax Expense Related to the Repatriation of Accumulated Foreign Earnings in Future Years | — | 249,861 | — | 249,861 | |||||||||||
Adjusted Net Income (Loss) (Non-GAAP) | $ | (149,508 | ) | $ | 431,864 | $ | 33,880 | $ | 2,716,216 | ||||||
Net Income (Loss) Per Share (GAAP) | |||||||||||||||
Basic | $ | (0.52 | ) | $ | 0.82 | $ | (8.29 | ) | $ | 5.36 | |||||
Diluted | $ | (0.52 | ) | $ | 0.81 | $ | (8.29 | ) | $ | 5.32 | |||||
Adjusted Net Income (Loss) Per Share (Non-GAAP) | |||||||||||||||
Basic | $ | (0.27 | ) | $ | 0.79 | $ | 0.06 | $ | 5.00 | ||||||
Diluted | $ | (0.27 | ) | $ | 0.79 | $ | 0.06 | $ | 4.95 | ||||||
Adjusted Net Income (Loss) Per Diluted Share (Non-GAAP) - Percentage Decrease | -134 | % | -99 | % | |||||||||||
Average Number of Common Shares (GAAP) | |||||||||||||||
Basic | 546,432 | 544,579 | 545,697 | 543,443 | |||||||||||
Diluted | 546,432 | 549,153 | 545,697 | 548,539 | |||||||||||
Average Number of Common Shares (Non-GAAP) | |||||||||||||||
Basic | 546,432 | 544,579 | 545,697 | 543,443 | |||||||||||
Diluted | 546,432 | 549,153 | 549,610 | 548,539 | |||||||||||
EOG RESOURCES, INC. Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP) to Net Cash Provided by Operating Activities (GAAP) (Unaudited; in thousands) | |||||||||||||||
The following chart reconciles the three-month and twelve-month periods ended December 31, 2015 and 2014 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, 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 management uses this information for comparative purposes within the industry. | |||||||||||||||
Three Months Ended | Twelve Months Ended | ||||||||||||||
December 31, | December 31, | ||||||||||||||
2015 | 2014 | 2015 | 2014 | ||||||||||||
Net Cash Provided by Operating Activities (GAAP) | $ | 615,813 | $ | 2,110,438 | $ | 3,595,165 | $ | 8,649,155 | |||||||
Adjustments: | |||||||||||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) | 28,758 | 38,450 | 124,011 | 157,453 | |||||||||||
Excess Tax Benefits from Stock-Based Compensation | 1,839 | 11,632 | 26,058 | 99,459 | |||||||||||
Changes in Components of Working Capital and Other Assets and Liabilities | |||||||||||||||
Accounts Receivable | (193,101 | ) | (426,025 | ) | (641,412 | ) | (84,982 | ) | |||||||
Inventories | (31,443 | ) | 42,792 | (58,450 | ) | 161,958 | |||||||||
Accounts Payable | 98,986 | 23,123 | 1,409,197 | (543,630 | ) | ||||||||||
Accrued Taxes Payable | 65,777 | 159,926 | (11,798 | ) | (16,486 | ) | |||||||||
Other Assets | 28,822 | (47,518 | ) | (118,143 | ) | 14,448 | |||||||||
Other Liabilities | 50,574 | (8,802 | ) | 66,257 | (75,420 | ) | |||||||||
Changes in Components of Working Capital Associated with Investing and Financing Activities | 19,436 | (5,154 | ) | (499,767 | ) | 103,414 | |||||||||
Discretionary Cash Flow (Non-GAAP) | $ | 685,461 | $ | 1,898,862 | $ | 3,891,118 | $ | 8,465,369 | |||||||
Discretionary Cash Flow (Non-GAAP) - Percentage Decrease | -64 | % | -54 | % | |||||||||||
EOG RESOURCES, INC. Quantitative Reconciliation of Adjusted Earnings Before Interest Expense, Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs, Impairments and Additional Items (Adjusted EBITDAX) (Non-GAAP) to Income (Loss) Before Interest Expense and Income Taxes (GAAP) (Unaudited; in thousands) | |||||||||||||||
The following chart adjusts the three-month and twelve-month periods ended December 31, 2015 and 2014 reported Income (Loss) Before Interest Expense and Income Taxes (GAAP) to Earnings Before Interest Expense, Income Taxes, 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 settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) gains from these transactions and to eliminate the net (gains) losses on asset dispositions. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Income (Loss) Before Interest Expense and Income Taxes (GAAP) to add back 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 items. EOG management uses this information for comparative purposes within the industry. | |||||||||||||||
Three Months Ended | Twelve Months Ended | ||||||||||||||
December 31, | December 31, | ||||||||||||||
2015 | 2014 | 2015 | 2014 | ||||||||||||
Income (Loss) Before Interest Expense and Income Taxes (GAAP) | $ | (335,833 | ) | $ | 1,198,328 | $ | (6,684,163 | ) | $ | 5,196,773 | |||||
Adjustments: | |||||||||||||||
Depreciation, Depletion and Amortization | 769,457 | 1,013,930 | 3,313,644 | 3,997,041 | |||||||||||
Exploration Costs | 34,946 | 45,167 | 149,494 | 184,388 | |||||||||||
Dry Hole Costs | 429 | 18,225 | 14,746 | 48,490 | |||||||||||
Impairments | 168,171 | 535,637 | 6,613,546 | 743,575 | |||||||||||
EBITDAX (Non-GAAP) | 637,170 | 2,811,287 | 3,407,267 | 10,170,267 | |||||||||||
Total Gains on MTM Commodity Derivative Contracts | (4,970 | ) | (750,154 | ) | (61,924 | ) | (834,273 | ) | |||||||
Net Cash Received from Settlements of Commodity Derivative Contracts | 69,093 | 222,944 | 730,114 | 34,007 | |||||||||||
(Gains) Losses on Asset Dispositions, Net | 3,656 | (431,890 | ) | 8,798 | (507,590 | ) | |||||||||
Adjusted EBITDAX (Non-GAAP) | $ | 704,949 | $ | 1,852,187 | $ | 4,084,255 | $ | 8,862,411 | |||||||
Adjusted EBITDAX (Non-GAAP) - Percentage Decrease | -62 | % | -54 | % | |||||||||||
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, | ||||||
2015 | 2014 | ||||||
Total Stockholders' Equity - (a) | $ | 12,943 | $ | 17,713 | |||
Current and Long-Term Debt (GAAP) - (b) | 6,660 | 5,910 | |||||
Less: Cash | (719 | ) | (2,087 | ) | |||
Net Debt (Non-GAAP) - (c) | 5,941 | 3,823 | |||||
Total Capitalization (GAAP) - (a) + (b) | $ | 19,603 | $ | 23,623 | |||
Total Capitalization (Non-GAAP) - (a) + (c) | $ | 18,884 | $ | 21,536 | |||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] | 34 | % | 25 | % | |||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] | 31 | % | 18 | % | |||
EOG RESOURCES, INC. | |||||||||||||||
Reserves Supplemental Data | |||||||||||||||
(Unaudited) | |||||||||||||||
2015 NET PROVED RESERVES RECONCILIATION SUMMARY | |||||||||||||||
United States | Trinidad | Other Int'l | Total | ||||||||||||
CRUDE OIL & CONDENSATE (MMBbl) | |||||||||||||||
Beginning Reserves | 1,129.8 | 1.3 | 8.7 | 1,139.8 | |||||||||||
Revisions | (115.0 | ) | — | — | (115.0 | ) | |||||||||
Purchases in place | 35.9 | — | — | 35.9 | |||||||||||
Extensions, discoveries and other additions | 141.3 | 0.1 | — | 141.4 | |||||||||||
Sales in place | (0.7 | ) | — | — | (0.7 | ) | |||||||||
Production | (103.4 | ) | (0.3 | ) | (0.1 | ) | (103.8 | ) | |||||||
Ending Reserves | 1,087.9 | 1.1 | 8.6 | 1,097.6 | |||||||||||
NATURAL GAS LIQUIDS (MMBbl) | |||||||||||||||
Beginning Reserves | 467.0 | — | 0.1 | 467.1 | |||||||||||
Revisions | (113.3 | ) | — | 0.1 | (113.2 | ) | |||||||||
Purchases in place | 8.3 | — | — | 8.3 | |||||||||||
Extensions, discoveries and other additions | 49.1 | — | — | 49.1 | |||||||||||
Sales in place | (0.1 | ) | — | (0.2 | ) | (0.3 | ) | ||||||||
Production | (28.1 | ) | — | — | (28.1 | ) | |||||||||
Ending Reserves | 382.9 | — | — | 382.9 | |||||||||||
NATURAL GAS (Bcf) | |||||||||||||||
Beginning Reserves | 4,905.5 | 405.6 | 31.5 | 5,342.6 | |||||||||||
Revisions | (1,453.1 | ) | 16.8 | 5.6 | (1,430.7 | ) | |||||||||
Purchases in place | 72.3 | — | — | 72.3 | |||||||||||
Extensions, discoveries and other additions | 306.3 | 21.7 | 4.4 | 332.4 | |||||||||||
Sales in place | (3.9 | ) | — | (11.1 | ) | (15.0 | ) | ||||||||
Production | (337.3 | ) | (127.5 | ) | (10.9 | ) | (475.7 | ) | |||||||
Ending Reserves | 3,489.8 | 316.6 | 19.5 | 3,825.9 | |||||||||||
OIL EQUIVALANTS (MMBoe) | |||||||||||||||
Beginning Reserves | 2,414.2 | 69.0 | 14.1 | 2,497.3 | |||||||||||
Revisions | (470.4 | ) | 2.8 | 1.0 | (466.6 | ) | |||||||||
Purchases in place | 56.2 | — | — | 56.2 | |||||||||||
Extensions, discoveries and other additions | 241.5 | 3.6 | 0.8 | 245.9 | |||||||||||
Sales in place | (1.5 | ) | — | (2.0 | ) | (3.5 | ) | ||||||||
Production | (187.7 | ) | (21.6 | ) | (1.9 | ) | (211.2 | ) | |||||||
Ending Reserves | 2,052.3 | 53.8 | 12.0 | 2,118.1 | |||||||||||
Net Proved Developed Reserves (MMBoe) | |||||||||||||||
At December 21, 2014 | 1,275.4 | 67.5 | 5.0 | 1,347.9 | |||||||||||
At December 31, 2015 | 1,018.5 | 50.7 | 3.3 | 1,072.5 | |||||||||||
2015 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ Millions) | |||||||||||||||
United States | Trinidad | Other Int'l | Total | ||||||||||||
Acquisition Cost of Unproved Properties | $ | 133.8 | $ | — | $ | 0.1 | $ | 133.9 | |||||||
Exploration Costs | 206.9 | 22.8 | 23.0 | 252.7 | |||||||||||
Development Costs | 3,815.4 | 87.2 | 105.0 | 4,007.6 | |||||||||||
Total Drilling | 4,156.1 | 110.0 | 128.1 | 4,394.2 | |||||||||||
Acquisition Cost of Proved Properties | 480.6 | — | — | 480.6 | |||||||||||
Total Exploration & Development Expenditures | 4,636.7 | 110.0 | 128.1 | 4,874.8 | |||||||||||
Gathering, Processing and Other | 287.4 | 0.3 | 0.4 | 288.1 | |||||||||||
Asset Retirement Costs | 32.4 | 15.5 | 5.6 | 53.5 | |||||||||||
Total Expenditures | 4,956.5 | 125.8 | 134.1 | 5,216.4 | |||||||||||
Proceeds from Sales in Place | (170.9 | ) | — | (21.9 | ) | (192.8 | ) | ||||||||
Net Expenditures | $ | 4,785.6 | $ | 125.8 | $ | 112.2 | $ | 5,023.6 | |||||||
RESERVE REPLACEMENT COSTS ($ / Boe) * | |||||||||||||||
Total Drilling, Before Revisions | $ | 17.21 | $ | 30.56 | $ | 160.13 | $ | 17.87 | |||||||
All-in Total, Net of Revisions | $ | (26.85 | ) | $ | 17.19 | $ | 71.17 | $ | (29.63 | ) | |||||
All-in Total, Excluding Revisions Due to Price | $ | 11.56 | $ | 17.19 | $ | 71.17 | $ | 11.91 | |||||||
RESERVE REPLACEMENT * | |||||||||||||||
Drilling Only | 129 | % | 17 | % | 42 | % | 116 | % | |||||||
All-in Total, Net of Revisions & Dispositions | -93 | % | 30 | % | -11 | % | -80 | % | |||||||
All-in Total, Excluding Revisions Due to Price | 213 | % | 30 | % | -11 | % | 192 | % | |||||||
All-in Total, Liquids | 4 | % | 33 | % | -100 | % | 4 | % | |||||||
* See attached reconciliation schedule for calculation methodology | |||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||
Quantitative Reconciliation of Total Exploration and Development Expenditures | |||||||||||||||
For Drilling Only (Non-GAAP) and Total Exploration and Development Expenditures (Non-GAAP) | |||||||||||||||
As Used in the Calculation of Reserve Replacement Costs ($ / BOE) | |||||||||||||||
To Total Costs Incurred in Exploration and Development Activities (GAAP) | |||||||||||||||
(Unaudited; in millions, except ratio information) | |||||||||||||||
The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) and Total Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Reserve Replacement Costs per Boe. There are numerous ways that industry participants present Reserve Replacement Costs, including “Drilling Only” and “All-In”, which reflect total exploration and development expenditures divided by total net proved reserve additions from extensions and discoveries only, or from all sources. Combined with Reserve Replacement, these statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry. Please note that the actual cost of adding reserves will vary from the reported statistics due to timing differences in reserve bookings and capital expenditures. Accordingly, some analysts use three- or five-year averages of reported statistics, while others prefer to estimate future costs. EOG has not included future capital costs to develop proved undeveloped reserves in exploration and development expenditures. | |||||||||||||||
United States | Trinidad | Other Int'l | Total | ||||||||||||
Total Costs Incurred in Exploration and Development Activities (GAAP) | $ | 4,669.1 | $ | 125.5 | $ | 133.7 | $ | 4,928.3 | |||||||
Less: Asset Retirement Costs | (32.4 | ) | (15.5 | ) | (5.6 | ) | (53.5 | ) | |||||||
Acquisition Cost of Proved Properties | (480.6 | ) | — | — | (480.6 | ) | |||||||||
Total Exploration & Development Expenditures for Drilling Only (Non-GAAP) (a) | $ | 4,156.1 | $ | 110.0 | $ | 128.1 | $ | 4,394.2 | |||||||
Total Costs Incurred in Exploration and Development Activities (GAAP) | $ | 4,669.1 | $ | 125.5 | $ | 133.7 | $ | 4,928.3 | |||||||
Less: Asset Retirement Costs | (32.4 | ) | (15.5 | ) | (5.6 | ) | (53.5 | ) | |||||||
Total Exploration & Development Expenditures (Non-GAAP) (b) | $ | 4,636.7 | $ | 110.0 | $ | 128.1 | $ | 4,874.8 | |||||||
Total Expenditures (GAAP) | $ | 4,956.5 | $ | 125.8 | $ | 134.1 | $ | 5,216.4 | |||||||
Less: Asset Retirement Costs | (32.4 | ) | (15.5 | ) | (5.6 | ) | (53.5 | ) | |||||||
Non-Cash Acquisition Costs of Unproved Properties | — | — | — | — | |||||||||||
Total Cash Expenditures (Non-GAAP) | $ | 4,924.1 | $ | 110.3 | $ | 128.5 | $ | 5,162.9 | |||||||
Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe) | |||||||||||||||
Revisions due to price (c) | (573.8 | ) | — | — | (573.8 | ) | |||||||||
Revisions other than price | 103.4 | 2.8 | 1.0 | 107.2 | |||||||||||
Purchases in place | 56.2 | — | — | 56.2 | |||||||||||
Extensions, discoveries and other additions (d) | 241.5 | 3.6 | 0.8 | 245.9 | |||||||||||
Total Proved Reserve Additions (e) | (172.7 | ) | 6.4 | 1.8 | (164.5 | ) | |||||||||
Sales in place | (1.5 | ) | — | (2.0 | ) | (3.5 | ) | ||||||||
Net Proved Reserve Additions From All Sources (f) | (174.2 | ) | 6.4 | (0.2 | ) | (168.0 | ) | ||||||||
Production (g) | 187.7 | 21.6 | 1.9 | 211.2 | |||||||||||
RESERVE REPLACEMENT COSTS ($ / Boe) | |||||||||||||||
Total Drilling, Before Revisions (a / d) | $ | 17.21 | $ | 30.56 | $ | 160.13 | $ | 17.87 | |||||||
All-in Total, Net of Revisions (b / e) | $ | (26.85 | ) | $ | 17.19 | $ | 71.17 | $ | (29.63 | ) | |||||
All-in Total, Excluding Revisions Due to Price (b / (e - c)) | $ | 11.56 | $ | 17.19 | $ | 71.17 | $ | 11.91 | |||||||
RESERVE REPLACEMENT | |||||||||||||||
Drilling Only (d / g) | 129 | % | 17 | % | 42 | % | 116 | % | |||||||
All-in Total, Net of Revisions & Dispositions (f / g) | -93 | % | 30 | % | -11 | % | -80 | % | |||||||
All-in Total, Excluding Revisions Due to Price ((f - c) / g) | 213 | % | 30 | % | -11 | % | 192 | % | |||||||
Net Proved Reserve Additions From All Sources - Liquids (MMBbl) | |||||||||||||||
Revisions | (228.3 | ) | — | 0.1 | (228.2 | ) | |||||||||
Purchases in place | 44.2 | — | — | 44.2 | |||||||||||
Extensions, discoveries and other additions (h) | 190.4 | 0.1 | — | 190.5 | |||||||||||
Total Proved Reserve Additions | 6.3 | 0.1 | 0.1 | 6.5 | |||||||||||
Sales in place | (0.8 | ) | — | (0.2 | ) | (1.0 | ) | ||||||||
Net Proved Reserve Additions From All Sources (i) | 5.5 | 0.1 | (0.1 | ) | 5.5 | ||||||||||
Production (j) | 131.5 | 0.3 | 0.1 | 131.9 | |||||||||||
RESERVE REPLACEMENT - LIQUIDS | |||||||||||||||
Drilling Only (h / j) | 145 | % | 33 | % | 0 | % | 144 | % | |||||||
All-in Total, Net of Revisions & Dispositions (i / j) | 4 | % | 33 | % | -100 | % | 4 | % | |||||||
EOG RESOURCES, INC. Natural Gas Financial Commodity Derivative Contracts | |||||||||
Presented below is a comprehensive summary of EOG's natural gas derivative contracts at February 25, 2016, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. | |||||||||
Natural Gas Price Swap Contracts | |||||||||
Weighted | |||||||||
Volume | Average Price | ||||||||
(MMBtud) | ($/MMBtu) | ||||||||
2016 | |||||||||
March 1, 2016 through August 31, 2016 | 60,000 | $ | 2.49 | ||||||
$/MMBtu | Dollars per million British thermal units | |
MMBtud | Million British thermal units per day | |
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 proved reserves ("net" to EOG’s interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements. |
Direct ATROR |
Based on Cash Flow and Time Value of Money |
- Estimated future commodity prices and operating costs |
- Costs incurred to drill, complete and equip a well, including facilities |
Excludes Indirect Capital |
- Gathering and Processing and other Midstream |
- Land, Seismic, Geological and Geophysical |
Payback ~12 Months on 100% Direct ATROR Wells |
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured |
Return on Equity / Return on Capital Employed |
Based on GAAP Accrual Accounting |
Includes All Indirect Capital and Growth Capital for Infrastructure |
- Eagle Ford, Bakken, Permian Facilities |
- Gathering and Processing |
Includes Legacy Gas Capital and Capital from Mature Wells |
EOG RESOURCES, INC. Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculations of Return on Capital Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest Expense (GAAP), Net Income (Loss) (GAAP), Current and Long-Term (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 (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income, Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for comparative purposes within the industry. | |||||||||||||||
2015 | 2014 | 2013 | 2012 | ||||||||||||
Return on Capital Employed (ROCE) (Non-GAAP) | |||||||||||||||
Net Interest Expense (GAAP) | $ | 237 | $ | 201 | $ | 235 | |||||||||
Tax Benefit Imputed (based on 35%) | (83 | ) | (70 | ) | (82 | ) | |||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 154 | $ | 131 | $ | 153 | |||||||||
Net Income (Loss) (GAAP) - (b) | $ | (4,525 | ) | $ | 2,915 | $ | 2,197 | ||||||||
Add: After-Tax Mark-to-Market Commodity Derivative Contracts Impact | 430 | (515 | ) | 182 | |||||||||||
Add: Impairments of Certain Assets, Net of Tax | 4,125 | 553 | 4 | ||||||||||||
Less: Texas Margin Tax Rate Reduction | (20 | ) | — | — | |||||||||||
Add: Legal Settlement - Early Leasehold Termination, Net of Tax | 13 | — | — | ||||||||||||
Add: Severance Costs, Net of Tax | 6 | — | — | ||||||||||||
Less: Net (Gains) Losses on Asset Dispositions, Net of Tax | 5 | (487 | ) | (137 | ) | ||||||||||
Add: Tax Expense Related to the Repatriation of Accumulated Foreign Earnings in Future Years | — | 250 | — | ||||||||||||
Adjusted Net Income (Non-GAAP) - (c) | $ | 34 | $ | 2,716 | $ | 2,246 | |||||||||
Total Stockholders' Equity - (d) | $ | 12,943 | $ | 17,713 | $ | 15,418 | $ | 13,285 | |||||||
Average Total Stockholders' Equity * - (e) | $ | 15,328 | $ | 16,566 | $ | 14,352 | |||||||||
Current and Long-Term Debt (GAAP) - (f) | $ | 6,660 | $ | 5,910 | $ | 5,913 | $ | 6,312 | |||||||
Less: Cash | (719 | ) | (2,087 | ) | (1,318 | ) | (876 | ) | |||||||
Net Debt (Non-GAAP) - (g) | $ | 5,941 | $ | 3,823 | $ | 4,595 | $ | 5,436 | |||||||
Total Capitalization (GAAP) - (d) + (f) | $ | 19,603 | $ | 23,623 | $ | 21,331 | $ | 19,597 | |||||||
Total Capitalization (Non-GAAP) - (d) + (g) | $ | 18,884 | $ | 21,536 | $ | 20,013 | $ | 18,721 | |||||||
Average Total Capitalization (Non-GAAP) * - (h) | $ | 20,210 | $ | 20,775 | $ | 19,367 | |||||||||
ROCE (GAAP Net Income) - [(a) + (b)] / (h) | -21.6 | % | 14.7 | % | 12.1 | % | |||||||||
ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (h) | 0.9 | % | 13.7 | % | 12.4 | % | |||||||||
Return on Equity (ROE) (Non-GAAP) | |||||||||||||||
ROE (GAAP Net Income) - (b) / (e) | -29.5 | % | 17.6 | % | 15.3 | % | |||||||||
ROE (Non-GAAP Adjusted Net Income) - (c) / (e) | 0.2 | % | 16.4 | % | 15.6 | % | |||||||||
* Average for the current and immediately preceding year | |||||||||||||||
EOG RESOURCES, INC. First Quarter and Full Year 2016 Forecast and Benchmark Commodity Pricing | |||||||||||||||||||
(a) First Quarter and Full Year 2016 Forecast | |||||||||||||||||||
The forecast items for the first quarter and full year 2016 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 2016 | Full Year 2016 | ||||||||||||||||||
Daily Production | |||||||||||||||||||
Crude Oil and Condensate Volumes (MBbld) | |||||||||||||||||||
United States | 255.0 | - | 265.0 | 250.0 | - | 265.0 | |||||||||||||
Trinidad | 0.3 | - | 0.5 | 0.3 | - | 0.5 | |||||||||||||
Other International | 0.0 | - | 6.0 | 9.7 | - | 14.5 | |||||||||||||
Total | 255.3 | - | 271.5 | 260.0 | - | 280.0 | |||||||||||||
Natural Gas Liquids Volumes (MBbld) | |||||||||||||||||||
Total | 71.0 | - | 79.0 | 70.0 | - | 80.0 | |||||||||||||
Natural Gas Volumes (MMcfd) | |||||||||||||||||||
United States | 795 | - | 815 | 770 | - | 800 | |||||||||||||
Trinidad | 340 | - | 360 | 280 | - | 310 | |||||||||||||
Other International | 22 | - | 28 | 20 | - | 25 | |||||||||||||
Total | 1,157 | - | 1,203 | 1,070 | - | 1,135 | |||||||||||||
Crude Oil Equivalent Volumes (MBoed) | |||||||||||||||||||
United States | 458.5 | - | 479.8 | 448.3 | - | 478.3 | |||||||||||||
Trinidad | 57.0 | - | 60.5 | 47.0 | - | 52.2 | |||||||||||||
Other International | 3.7 | - | 10.7 | 13.0 | - | 18.7 | |||||||||||||
Total | 519.2 | - | 551.0 | 508.3 | - | 549.2 | |||||||||||||
Estimated Ranges (Unaudited) | |||||||||||||||||||
1Q 2016 | Full Year 2016 | ||||||||||||||||||
Operating Costs | |||||||||||||||||||
Unit Costs ($/Boe) | |||||||||||||||||||
Lease and Well | $ | 5.25 | - | $ | 5.75 | $ | 5.30 | - | $ | 6.10 | |||||||||
Transportation Costs | $ | 3.90 | - | $ | 4.50 | $ | 4.00 | - | $ | 4.60 | |||||||||
Depreciation, Depletion and Amortization | $ | 18.55 | - | $ | 18.95 | $ | 17.95 | - | $ | 18.55 | |||||||||
Expenses ($MM) | |||||||||||||||||||
Exploration, Dry Hole and Impairment | $ | 100 | - | $ | 120 | $ | 425 | - | $ | 475 | |||||||||
General and Administrative | $ | 83 | - | $ | 93 | $ | 335 | - | $ | 365 | |||||||||
Gathering and Processing | $ | 35 | - | $ | 40 | $ | 130 | - | $ | 150 | |||||||||
Capitalized Interest | $ | 7 | - | $ | 9 | $ | 27 | - | $ | 33 | |||||||||
Net Interest | $ | 67 | - | $ | 69 | $ | 275 | - | $ | 285 | |||||||||
Taxes Other Than Income (% of Wellhead Revenue) | 6.5 | % | - | 7.0 | % | 6.3 | % | - | 6.8 | % | |||||||||
Income Taxes | |||||||||||||||||||
Effective Rate | 32 | % | - | 37 | % | 32 | % | - | 37 | % | |||||||||
Current Taxes ($MM) | $ | (55 | ) | - | $ | (40 | ) | $ | (190 | ) | - | $ | (170 | ) | |||||
Capital Expenditures (Excluding Acquisitions, $MM) | |||||||||||||||||||
Exploration and Development, Excluding Facilities | $ | 1,925 | - | $ | 2,025 | ||||||||||||||
Exploration and Development Facilities | $ | 350 | - | $ | 400 | ||||||||||||||
Gathering, Processing and Other | $ | 125 | - | $ | 175 | ||||||||||||||
Pricing - (Refer to Benchmark Commodity Pricing in text) | |||||||||||||||||||
Crude Oil and Condensate ($/Bbl) | |||||||||||||||||||
Differentials | |||||||||||||||||||
United States - above (below) WTI | $ | (4.00 | ) | - | $ | (2.00 | ) | $ | (3.75 | ) | - | $ | (1.75 | ) | |||||
Trinidad - above (below) WTI | $ | (10.50 | ) | - | $ | (9.50 | ) | $ | (12.00 | ) | - | $ | (8.00 | ) | |||||
Natural Gas Liquids | |||||||||||||||||||
Realizations as % of WTI | 31 | % | - | 35 | % | 31 | % | - | 35 | % | |||||||||
Natural Gas ($/Mcf) | |||||||||||||||||||
Differentials | |||||||||||||||||||
United States - above (below) NYMEX Henry Hub | $ | (1.20 | ) | - | $ | (0.50 | ) | $ | (1.20 | ) | - | $ | (0.50 | ) | |||||
Realizations | |||||||||||||||||||
Trinidad | $ | 2.10 | - | $ | 2.90 | $ | 2.40 | - | $ | 2.90 | |||||||||
Other International | $ | 3.00 | - | $ | 4.25 | $ | 3.30 | - | $ | 3.90 | |||||||||
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 | New York Mercantile Exchange | ||||||||||||||||||
WTI | West Texas Intermediate | ||||||||||||||||||