EOG RESOURCES, INC. EOG Resources Reports Third Quarter 2015 Results; Increases Delaware Basin Net Resource Potential by 1.0 BnBoe
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HOUSTON, Nov. 5, 2015/PRNewswire / --
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Updates DelawareBasin Net Resource Potential to 2.35 BnBoe
- Increases Wolfcamp Net Reserve Potential by 500 MMBoe
- Announces Second Bone Spring Sand Net Reserve Potential of 500 MMBoe
- Expands Drilling Inventory from 2,700 to 4,900 Net Wells
- Acquires 26,000 Net Acres in the DelawareBasin Oil Window in Three Transactions
- Completes Record Horizontal Well for DelawareBasin Wolfcamp
- Continues to Improve Well Productivity While Lowering Costs
- Exceeds Third Quarter Oil and Total Production Guidance
- Reduces Per-Unit Lease Operating Costs by 5 Percent Versus Second Quarter
EOG Resources, Inc. (NYSE: EOG) (EOG) today reported a third quarter 2015 net loss of $4.1 billion, or $7.47per share. This compares to third quarter 2014 net income of $1.1 billion, or $2.01per share.
Adjusted non-GAAP net income for the third quarter 2015 was $13.5 million, or $0.02per share, compared to the same prior year period adjusted non-GAAP net income of $720.6 million, or $1.31per share. Adjusted non-GAAP net income 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.)
During the third quarter 2015, proved oil and gas properties and related assets were written down to their fair value resulting in non-cash impairment charges of $4.1 billionnet of tax. The impairments were due to declines in commodity prices and were primarily related to legacy natural gas and marginal liquids assets.
Significant reductions in operating expenses were more than offset by lower commodity price realizations, resulting in decreases in adjusted non-GAAP net income, discretionary cash flow and adjusted EBITDAX during the third quarter 2015 compared to the third quarter 2014. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.)
Operational Highlights
In the third quarter 2015, total crude oil and condensate production exceeded prior guidance due to improved well productivity. Total company production decreased 5 percent compared to the third quarter 2014 excluding production related to EOG's Canadian operations, which were divested in the fourth quarter 2014. Total capital expenditures decreased 36 percent compared to the same prior year period.
EOG also continued to reduce completed well costs and operating costs compared to the same quarter last year. Lease and well expenses decreased 17 percent on a per-unit basis due to improved operational efficiencies and reduced service costs. Per-unit transportation costs decreased 11 percent, and total general and administrative expenses declined 6 percent.
'We are executing on our 2015 plan to reset the company to be successful in a low commodity price environment,' said William R. 'Bill' Thomas, Chairman and Chief Executive Officer. 'By continuing to make the best oil wells in the industry, significantly reducing costs and expanding resource potential in the best North American oil plays, EOG is uniquely positioned for 2016 and to lead the industry for years to come.'
2015 Capital Plan Update
EOG is maintaining full-year 2015 capital spending guidance. U.S. crude oil production guidance increased due to strong well performance. Total company crude oil production guidance is slightly lower due to delays in the startup of the U.K. Conwy project.
DelawareBasin
EOG increased its DelawareBasin net resource potential by 1.0 billion barrels of oil equivalent (BnBoe). For the DelawareBasin Wolfcamp, EOG added 950 net drilling locations and increased its net resource potential estimate over 60 percent to 1.3 BnBoe. Advancements in targeting and completion technology are enabling tighter well spacing and increased production per well. In the Second Bone Spring Sand oil play, EOG provided an initial net resource potential estimate of 500 million barrels of oil equivalent (MMBoe) and added 1,250 net drilling locations in this high quality crude oil play.
EOG added 26,000 net acres to its DelawareBasin position in the third quarter 2015 through three tactical acquisitions in Loving County, Texas, and Lea County, N.M., for a total of $368 million. Most of the acquired acreage is adjacent to EOG's existing operating areas in the high rate of return DelawareBasin oil window. Combined, these acquisitions added net production of 750 barrels of oil equivalent (Boe) per day with an associated 2.5 MMBoe of proved producing reserves. These acquisitions and the updated resource potential bring EOG's total DelawareBasin net position to 2.35 BnBoe and 4,900 locations, providing decades of high return drilling potential.
'Outstanding technical and operational advances enabled us to increase potential resource estimates for our DelawareBasin position by over 70 percent,' Thomas said. 'We are also pleased that through our tactical acquisitions of new, high quality DelawareBasin acreage, we added assets which meet our high rate of return hurdle. EOG's DelawareBasin assets along with the company's Eagle Ford and Bakken positions continue to grow in both size and quality. With premier assets and commitment to innovation, EOG continues to enhance its capability for high return growth in a low oil price environment.'
In addition, EOG completed a number of noteworthy new wells in the DelawareBasin in the third quarter.
In the Wolfcamp shale in Lea County, N.M., EOG completed the Thor 21 #701H and #702H with average initial production rates per well of 3,255 barrels of oil per day (Bopd), 470 barrels per day (Bpd) of natural gas liquids (NGLs) and 3.9 million cubic feet per day (MMcfd) of natural gas. The Thor 21 #702H set a new industry 30-day production record for horizontal wells in the DelawareBasin Wolfcamp.
In the Second Bone Spring Sand in Lea County, N.M., EOG completed the Neptune 10 State Com #501H and #502H in a two-well pattern with average initial production rates per well of 2,205 Bopd, 185 Bpd of NGLs and 1.5 MMcfd of natural gas.
In the Leonardshale in Lea County, N.M., EOG completed the Hawk 35 Fed #7H, #8H, #9H and #10H in a four-well pattern with average initial production rates per well of 1,615 Bopd, 160 Bpd of NGLs and 1.3 MMcfd of natural gas.
South Texas Eagle Ford
The Eagle Ford continues to be EOG's largest high return play. During 2015, the company expanded the use of high density completions to 95 percent of the Eagle Ford wells planned for the year. Enabled by high density completions and proprietary targeting technology, EOG is actively testing tighter well spacing in the lower Eagle Ford with stacked-staggered 'W' patterns. Additionally, an efficient drilling program increased the amount of acreage held by production to 91 percent of EOG's 561,000 net acres in the Eagle Ford oil window. In Gonzales County, EOG completed the Phoenix Unit #4H and #5H with average initial production rates per well of 3,815 Bopd, 415 Bpd of NGLs and 2.8 MMcfd of natural gas. In McMullen County, EOG completed the Naylor Jones Unit 26 #1H and #2H in a two-well pattern with average initial production rates per well of 2,650 Bopd with 150 Bpd of NGLs and 1.0 MMcfd of natural gas.
North Dakota Bakken
EOG's activity in North Dakotaremains focused on the Bakken Core and Antelope Extension areas. The company continued to improve its drilling and completion techniques including the expanded use of high density completions. In addition, recently installed water gathering facilities have significantly reduced operating expenses. During the third quarter 2015, the company completed the Parshall#88-3029H, #23-3029H and #26-3029H in a three-well pattern with average initial production rates per well of 1,830 Bopd and 1.0 MMcfd of rich natural gas. Average lateral lengths for the wells were 5,925 feet.
Hedging Activity
For the period November 1 through December 31, 2015, EOG has crude oil financial price swap contracts in place for 10,000 Bopd at a weighted average price of $89.98per barrel. In addition, EOG has put options in place which establish a floor price of $45.00per barrel for 82,500 Bopd for November 2015.
For December 2015, EOG has natural gas financial price swap contracts in place for 175,000 million British thermal units (MMBtu) per day at a weighted average price of $4.51per MMBtu, excluding unexercised options. Comprehensive summaries of crude oil and natural gas derivative contracts are provided in the attached tables.
Capital Structure
At September 30, 2015, EOG's total debt outstanding was $6.4 billionwith a debt-to-total capitalization ratio of 33 percent. Taking into account cash on the balance sheet of $743 millionat September 30, EOG's net debt was $5.7 billionwith a net debt-to-total capitalization ratio of 30 percent. A reconciliation of non-GAAP measures to GAAP measures is provided in the attached tables.
Conference Call November 6, 2015
EOG's third 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, November 6, 2015. To listen, log on to www.eogresources.com. The webcast will be archived on EOG's website through December 7, 2015.
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, 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, 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 optimize 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, 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 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 20 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2014, 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 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, 2014, available from EOG at P.O. Box 4362, Houston, Texas77210-4362 (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.
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 |
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EOG RESOURCES, INC. | |||||||||||
Financial Report | |||||||||||
(Unaudited; in millions, except per share data) | |||||||||||
Three Months Ended | Nine Months Ended | ||||||||||
September 30, | September 30, | ||||||||||
2015 | 2014 | 2015 | 2014 | ||||||||
Net Operating Revenues | $ | 2,172.4 | $ | 5,118.6 | $ | 6,960.7 | $ | 13,389.8 | |||
Net Income (Loss) | $ | (4,075.7) | $ | 1,103.6 | $ | (4,240.2) | $ | 2,470.9 | |||
Net Income (Loss) Per Share | |||||||||||
Basic | $ | (7.47) | $ | 2.03 | $ | (7.77) | $ | 4.55 | |||
Diluted | $ | (7.47) | $ | 2.01 | $ | (7.77) | $ | 4.51 | |||
Average Number of Common Shares | |||||||||||
Basic | 545.9 | 544.0 | 545.5 | 543.1 | |||||||
Diluted | 545.9 | 549.5 | 545.5 | 548.4 | |||||||
Summary Income Statements | |||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||
Three Months Ended | Nine Months Ended | ||||||||||
September 30, | September 30, | ||||||||||
2015 | 2014 | 2015 | 2014 | ||||||||
Net Operating Revenues | |||||||||||
Crude Oil and Condensate | $ | 1,181,092 | $ | 2,671,502 | $ | 3,894,092 | $ | 7,687,579 | |||
Natural Gas Liquids | 95,217 | 258,927 | 311,137 | 753,135 | |||||||
Natural Gas | 281,837 | 443,108 | 843,657 | 1,508,892 | |||||||
Gains on Mark-to-Market Commodity | |||||||||||
Derivative Contracts | 29,239 | 469,125 | 56,954 | 84,119 | |||||||
Gathering, Processing and Marketing | 572,217 | 1,196,933 | 1,820,843 | 3,240,139 | |||||||
Gains (Losses) on Asset Dispositions, Net | (1,185) | 60,346 | (5,142) | 75,700 | |||||||
Other, Net | 14,011 | 18,675 | 39,126 | 40,279 | |||||||
Total | 2,172,428 | 5,118,616 | 6,960,667 | 13,389,843 | |||||||
Operating Expenses | |||||||||||
Lease and Well | 283,221 | 368,340 | 934,366 | 1,035,632 | |||||||
Transportation Costs | 203,594 | 246,067 | 641,739 | 729,883 | |||||||
Gathering and Processing Costs | 35,497 | 41,621 | 106,503 | 108,015 | |||||||
Exploration Costs | 31,344 | 48,955 | 114,548 | 139,221 | |||||||
Dry Hole Costs | 198 | 16,359 | 14,317 | 30,265 | |||||||
Impairments | 6,307,420 | 55,542 | 6,445,375 | 207,938 | |||||||
Marketing Costs | 615,303 | 1,213,652 | 1,924,134 | 3,263,471 | |||||||
Depreciation, Depletion and Amortization | 722,172 | 1,040,018 | 2,544,187 | 2,983,111 | |||||||
General and Administrative | 90,959 | 96,931 | 257,580 | 270,725 | |||||||
Taxes Other Than Income | 105,677 | 204,969 | 334,244 | 606,411 | |||||||
Total | 8,395,385 | 3,332,454 | 13,316,993 | 9,374,672 | |||||||
Operating Income (Loss) | (6,222,957) | 1,786,162 | (6,356,326) | 4,015,171 | |||||||
Other Income (Expense), Net | 8,607 | (21,338) | 7,996 | (16,726) | |||||||
Income (Loss) Before Interest Expense and Income Taxes | (6,214,350) | 1,764,824 | (6,348,330) | 3,998,445 | |||||||
Interest Expense, Net | 60,571 | 49,704 | 174,400 | 151,723 | |||||||
Income (Loss) Before Income Taxes | (6,274,921) | 1,715,120 | (6,522,730) | 3,846,722 | |||||||
Income Tax Provision (Benefit) | (2,199,182) | 611,502 | (2,282,511) | 1,375,823 | |||||||
Net Income (Loss) | $ | (4,075,739) | $ | 1,103,618 | $ | (4,240,219) | $ | 2,470,899 | |||
Dividends Declared per Common Share | $ | 0.1675 | $ | 0.1675 | $ | 0.5025 | $ | 0.4175 | |||
EOG RESOURCES, INC. | |||||||||||
Operating Highlights | |||||||||||
(Unaudited) | |||||||||||
Three Months Ended | Nine Months Ended | ||||||||||
September 30, | September 30, | ||||||||||
2015 | 2014 | 2015 | 2014 | ||||||||
Wellhead Volumes and Prices | |||||||||||
Crude Oil and Condensate Volumes (MBbld) (A) | |||||||||||
United States | 278.3 | 293.2 | 284.4 | 275.5 | |||||||
Trinidad | 1.0 | 0.9 | 0.9 | 1.0 | |||||||
Other International (B) | 0.2 | 5.4 | 0.2 | 6.1 | |||||||
Total | 279.5 | 299.5 | 285.5 | 282.6 | |||||||
Average Crude Oil and Condensate Prices ($/Bbl) © | |||||||||||
United States | $ | 45.93 | $ | 97.33 | $ | 49.94 | $ | 100.10 | |||
Trinidad | 38.56 | 87.87 | 41.98 | 90.84 | |||||||
Other International (B) | 61.80 | 87.72 | 58.44 | 90.74 | |||||||
Composite | 45.91 | 97.13 | 49.92 | 99.87 | |||||||
Natural Gas Liquids Volumes (MBbld) (A) | |||||||||||
United States | 77.7 | 85.8 | 76.2 | 78.4 | |||||||
Other International (B) | 0.1 | 0.6 | 0.1 | 0.7 | |||||||
Total | 77.8 | 86.4 | 76.3 | 79.1 | |||||||
Average Natural Gas Liquids Prices ($/Bbl) © | |||||||||||
United States | $ | 13.25 | $ | 32.61 | $ | 14.94 | $ | 34.83 | |||
Other International (B) | 8.05 | 40.38 | 6.05 | 43.01 | |||||||
Composite | 13.24 | 32.67 | 14.93 | 34.90 | |||||||
Natural Gas Volumes (MMcfd) (A) | |||||||||||
United States | 889 | 941 | 895 | 920 | |||||||
Trinidad | 355 | 356 | 342 | 374 | |||||||
Other International (B) | 30 | 72 | 31 | 74 | |||||||
Total | 1,274 | 1,369 | 1,268 | 1,368 | |||||||
Average Natural Gas Prices ($/Mcf) © | |||||||||||
United States | $ | 2.04 | $ | 3.48 | $ | 2.14 | $ | 4.17 | |||
Trinidad | 2.90 | 3.50 | 3.01 | 3.61 | |||||||
Other International (B) | 7.18 | (E) | 4.16 | 4.63 | (E) | 4.56 | |||||
Composite | 2.40 | 3.52 | 2.44 | 4.04 | |||||||
Crude Oil Equivalent Volumes (MBoed) (D) | |||||||||||
United States | 504.2 | 536.1 | 509.8 | 507.3 | |||||||
Trinidad | 60.2 | 60.1 | 57.9 | 63.4 | |||||||
Other International (B) | 5.2 | 17.9 | 5.4 | 19.0 | |||||||
Total | 569.6 | 614.1 | 573.1 | 589.7 | |||||||
Total MMBoe (D) | 52.4 | 56.5 | 156.5 | 161.0 | |||||||
(A) | Thousand barrels per day or million cubic feet per day, as applicable. | |||||||||||
(B) | Other International includes EOG's Canada, United Kingdom, China and Argentina operations. | |||||||||||
© | 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. | |||||||||||
(E) | Includes revenue adjustment of $3.62 per Mcf and $1.19 per Mcf for the quarter and year-to-date, respectively, related to a price adjustment for natural gas sales made in China during the period June 2012 through March 2015. | |||||||||||
EOG RESOURCES, INC. | |||||
Summary Balance Sheets | |||||
(Unaudited; in thousands, except share data) | |||||
September 30, | December 31, | ||||
2015 | 2014 | ||||
ASSETS | |||||
Current Assets | |||||
Cash and Cash Equivalents | $ | 742,689 | $ | 2,087,213 | |
Accounts Receivable, Net | 1,123,111 | 1,779,311 | |||
Inventories | 660,252 | 706,597 | |||
Assets from Price Risk Management Activities | 71,503 | 465,128 | |||
Income Taxes Receivable | 53,667 | 71,621 | |||
Deferred Income Taxes | 40,619 | 19,618 | |||
Other | 133,117 | 286,533 | |||
Total | 2,824,958 | 5,416,021 | |||
Property, Plant and Equipment | |||||
Oil and Gas Properties (Successful Efforts Method) | 50,025,191 | 46,503,532 | |||
Other Property, Plant and Equipment | 3,890,934 | 3,750,958 | |||
Total Property, Plant and Equipment | 53,916,125 | 50,254,490 | |||
Less: Accumulated Depreciation, Depletion and Amortization | (29,640,793) | (21,081,846) | |||
Total Property, Plant and Equipment, Net | 24,275,332 | 29,172,644 | |||
Other Assets | 176,957 | 174,022 | |||
Total Assets | $ | 27,277,247 | $ | 34,762,687 | |
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||
Current Liabilities | |||||
Accounts Payable | $ | 1,561,574 | $ | 2,860,548 | |
Accrued Taxes Payable | 174,897 | 140,098 | |||
Dividends Payable | 91,377 | 91,594 | |||
Deferred Income Taxes | - | 110,743 | |||
Short-Term Borrowings and Current Portion of Long-Term Debt | 36,279 | 6,579 | |||
Other | 182,834 | 174,746 | |||
Total | 2,046,961 | 3,384,308 | |||
Long-Term Debt | 6,393,931 | 5,903,354 | |||
Other Liabilities | 970,288 | 939,497 | |||
Deferred Income Taxes | 4,581,844 | 6,822,946 | |||
Commitments and Contingencies | |||||
Stockholders' Equity | |||||
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and | 205,503 | 205,492 | |||
Additional Paid in Capital | 2,897,439 | 2,837,150 | |||
Accumulated Other Comprehensive Loss | (34,979) | (23,056) | |||
Retained Earnings | 10,247,349 | 14,763,098 | |||
Common Stock Held in Treasury, 383,870 Shares at September 30, 2015 | (31,089) | (70,102) | |||
Total Stockholders' Equity | 13,284,223 | 17,712,582 | |||
Total Liabilities and Stockholders' Equity | $ | 27,277,247 | $ | 34,762,687 | |
EOG RESOURCES, INC. | |||||
Summary Statements of Cash Flows | |||||
(Unaudited; in thousands) | |||||
Nine Months Ended | |||||
September 30, | |||||
2015 | 2014 | ||||
Cash Flows from Operating Activities | |||||
Reconciliation of Net Income (Loss) to Net Cash Provided by Operating Activities: | |||||
Net Income (Loss) | $ | (4,240,219) | $ | 2,470,899 | |
Items Not Requiring (Providing) Cash | |||||
Depreciation, Depletion and Amortization | 2,544,187 | 2,983,111 | |||
Impairments | 6,445,375 | 207,938 | |||
Stock-Based Compensation Expenses | 101,926 | 103,636 | |||
Deferred Income Taxes | (2,377,030) | 974,522 | |||
(Gains) Losses on Asset Dispositions, Net | 5,142 | (75,700) | |||
Other, Net | 3,735 | 17,188 | |||
Dry Hole Costs | 14,317 | 30,265 | |||
Mark-to-Market Commodity Derivative Contracts | |||||
Total Gains | (56,954) | (84,119) | |||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts | 661,021 | (188,937) | |||
Excess Tax Benefits from Stock-Based Compensation | (24,219) | (87,827) | |||
Other, Net | 8,904 | 8,701 | |||
Changes in Components of Working Capital and Other Assets and Liabilities | |||||
Accounts Receivable | 448,311 | (341,043) | |||
Inventories | 27,007 | (119,166) | |||
Accounts Payable | (1,310,211) | 566,753 | |||
Accrued Taxes Payable | 77,575 | 176,412 | |||
Other Assets | 146,965 | (61,966) | |||
Other Liabilities | (15,683) | 66,618 | |||
Changes in Components of Working Capital Associated with Investing and Financing | |||||
Activities | 519,203 | (108,568) | |||
Net Cash Provided by Operating Activities | 2,979,352 | 6,538,717 | |||
Investing Cash Flows | |||||
Additions to Oil and Gas Properties | (3,918,065) | (5,653,035) | |||
Additions to Other Property, Plant and Equipment | (252,295) | (587,178) | |||
Proceeds from Sales of Assets | 144,285 | 91,335 | |||
Changes in Restricted Cash | - | (91,238) | |||
Changes in Components of Working Capital Associated with Investing Activities | (519,323) | 108,999 | |||
Net Cash Used in Investing Activities | (4,545,398) | (6,131,117) | |||
Financing Cash Flows | |||||
Net Commercial Paper Borrowings | 29,700 | - | |||
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 | (274,577) | (187,670) | |||
Excess Tax Benefits from Stock-Based Compensation | 24,219 | 87,827 | |||
Treasury Stock Purchased | (43,419) | (114,824) | |||
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan | 14,967 | 11,740 | |||
Debt Issuance Costs | (5,933) | (895) | |||
Repayment of Capital Lease Obligation | (4,599) | (4,457) | |||
Other, Net | 120 | (431) | |||
Net Cash Provided by (Used in) Financing Activities | 230,703 | (244,063) | |||
Effect of Exchange Rate Changes on Cash | (9,181) | (601) | |||
Increase (Decrease) in Cash and Cash Equivalents | (1,344,524) | 162,936 | |||
Cash and Cash Equivalents at Beginning of Period | 2,087,213 | 1,318,209 | |||
Cash and Cash Equivalents at End of Period | $ | 742,689 | $ | 1,481,145 | |
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EOG RESOURCES, INC. | |||||||||||
Quantitative Reconciliation of Adjusted Net Income (Non-GAAP) | |||||||||||
to Net Income (Loss) (GAAP) | |||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||
The following chart adjusts the three-month and nine-month periods ended September 30, 2015 and 2014 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 from these transactions, to eliminate the impact of the Texas margin tax rate reduction in 2015, to eliminate the net (gains) losses on asset dispositions, to add back severance costs associated with EOG's North American operations in 2015 and to add back impairment charges related to certain of EOG's assets in 2015 and 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 | Nine Months Ended | ||||||||||
September 30, | September 30, | ||||||||||
2015 | 2014 | 2015 | 2014 | ||||||||
Reported Net Income (Loss) (GAAP) | $ | (4,075,739) | $ | 1,103,618 | $ | (4,240,219) | $ | 2,470,899 | |||
Commodity Derivative Contracts Impact | |||||||||||
Gains on Mark-to-Market Commodity Derivative Contracts | (29,239) | (469,125) | (56,954) | (84,119) | |||||||
Net Cash Received from (Payments for) Settlements of Commodity | 99,879 | (68,037) | 661,021 | (188,937) | |||||||
Subtotal | 70,640 | (537,162) | 604,067 | (273,056) | |||||||
After-Tax MTM Impact | 45,457 | (344,616) | 388,717 | (175,179) | |||||||
Less: Texas Margin Tax Rate Reduction | - | - | (19,500) | - | |||||||
Less: Net (Gains) Losses on Asset Dispositions, Net of Tax | (3,429) | (38,386) | 1,694 | (47,426) | |||||||
Add: Severance Costs, Net of Tax | - | - | 5,473 | - | |||||||
Add: Impairments of Certain Assets, Net of Tax | 4,047,223 | - | 4,047,223 | 36,058 | |||||||
Adjusted Net Income (Non-GAAP) | $ | 13,512 | $ | 720,616 | $ | 183,388 | $ | 2,284,352 | |||
Net Income (Loss) Per Share (GAAP) | |||||||||||
Basic | $ | (7.47) | $ | 2.03 | $ | (7.77) | $ | 4.55 | |||
Diluted | $ | (7.47) | $ | 2.01 | $ | (7.77) | $ | 4.51 | |||
Adjusted Net Income Per Share (Non-GAAP) | |||||||||||
Basic | $ | 0.02 | $ | 1.32 | $ | 0.34 | $ | 4.21 | |||
Diluted | $ | 0.02 | $ | 1.31 | $ | 0.33 | $ | 4.17 | |||
Adjusted Net Income Per Diluted Share (Non-GAAP) - | -98 | % | -92 | % | |||||||
Average Number of Common Shares (GAAP) | |||||||||||
Basic | 545,920 | 543,984 | 545,466 | 543,086 | |||||||
Diluted | 545,920 | 549,518 | 545,466 | 548,401 | |||||||
Average Number of Common Shares (Non-GAAP) | |||||||||||
Basic | 545,920 | 543,984 | 545,466 | 543,086 | |||||||
Diluted | 549,434 | 549,518 | 549,414 | 548,401 | |||||||
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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 nine-month periods ended September 30, 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 | Nine Months Ended | |||||||||||
September 30, | September 30, | |||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||
Net Cash Provided by Operating Activities (GAAP) | $ | 1,131,432 | $ | 2,336,469 | $ | 2,979,352 | $ | 6,538,717 | ||||
Adjustments: | ||||||||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) | 25,286 | 42,220 | 95,253 | 119,003 | ||||||||
Excess Tax Benefits from Stock-Based Compensation | 7,826 | 24,068 | 24,219 | 87,827 | ||||||||
Changes in Components of Working Capital and Other Assets and Liabilities | ||||||||||||
Accounts Receivable | (150,128) | 91,707 | (448,311) | 341,043 | ||||||||
Inventories | 10,602 | 9,410 | (27,007) | 119,166 | ||||||||
Accounts Payable | 310,567 | (219,214) | 1,310,211 | (566,753) | ||||||||
Accrued Taxes Payable | (13,451) | (60,744) | (77,575) | (176,412) | ||||||||
Other Assets | (70,851) | (79,487) | (146,965) | 61,966 | ||||||||
Other Liabilities | (33,165) | (9,517) | 15,683 | (66,618) | ||||||||
Changes in Components of Working Capital Associated with Investing and | ||||||||||||
Financing Activities | (349,401) | 76,924 | (519,203) | 108,568 | ||||||||
Discretionary Cash Flow (Non-GAAP) | $ | 868,717 | $ | 2,211,836 | $ | 3,205,657 | $ | 6,566,507 | ||||
Discretionary Cash Flow (Non-GAAP) - Percentage Decrease | -61 | % | -51 | % | ||||||||
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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 nine-month periods ended September 30, 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 (payments for) 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 | Nine Months Ended | ||||||||||
September 30, | September 30, | ||||||||||
2015 | 2014 | 2015 | 2014 | ||||||||
Income (Loss) Before Interest Expense and Income Taxes (GAAP) | $ | (6,214,350) | $ | 1,764,824 | $ | (6,348,330) | $ | 3,998,445 | |||
Adjustments: | |||||||||||
Depreciation, Depletion and Amortization | 722,172 | 1,040,018 | 2,544,187 | 2,983,111 | |||||||
Exploration Costs | 31,344 | 48,955 | 114,548 | 139,221 | |||||||
Dry Hole Costs | 198 | 16,359 | 14,317 | 30,265 | |||||||
Impairments | 6,307,420 | 55,542 | 6,445,375 | 207,938 | |||||||
EBITDAX (Non-GAAP) | 846,784 | 2,925,698 | 2,770,097 | 7,358,980 | |||||||
Total Gains on MTM Commodity Derivative Contracts | (29,239) | (469,125) | (56,954) | (84,119) | |||||||
Net Cash Received from (Payments for) Settlements of | 99,879 | (68,037) | 661,021 | (188,937) | |||||||
(Gains) Losses on Asset Dispositions, Net | 1,185 | (60,346) | 5,142 | (75,700) | |||||||
Adjusted EBITDAX (Non-GAAP) | $ | 918,609 | $ | 2,328,190 | $ | 3,379,306 | $ | 7,010,224 | |||
Adjusted EBITDAX (Non-GAAP) - Percentage Decrease | -61 | % | -52 | % | |||||||
EOG RESOURCES, INC. |
Quantitative Reconciliation of Net Debt (Non-GAAP) and Total |
Capitalization (Non-GAAP) as Used in the Calculation of |
the Net Debt-to-Total Capitalization Ratio (Non-GAAP) to |
Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) |
(Unaudited; in millions, except ratio data) |
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. |
At | At | |||||
September 30, | December 31, | |||||
2015 | 2014 | |||||
Total Stockholders' Equity - (a) | $ | 13,284 | $ | 17,713 | ||
Current and Long-Term Debt (GAAP) - (b) | 6,430 | 5,910 | ||||
Less: Cash | (743) | (2,087) | ||||
Net Debt (Non-GAAP) - (c) | 5,687 | 3,823 | ||||
Total Capitalization (GAAP) - (a) + (b) | $ | 19,714 | $ | 23,623 | ||
Total Capitalization (Non-GAAP) - (a) + (c) | $ | 18,971 | $ | 21,536 | ||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] | 33 | % | 25 | % | ||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] | 30 | % | 18 | % | ||
EOG RESOURCES, INC. | ||||||||||||||||||
Crude Oil and Natural Gas Financial | ||||||||||||||||||
Commodity Derivative Contracts | ||||||||||||||||||
Presented below is a comprehensive summary of EOG's crude oil and natural gas derivative contracts at November 5, 2015, with notional volumes expressed in Bbld and MMBtud and prices and premiums expressed in $/Bbl and $/MMBtu. EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. | ||||||||||||||||||
Crude Oil Price Swap Contracts | ||||||||||||||||||
Weighted | ||||||||||||||||||
Volume | Average Price | |||||||||||||||||
(Bbld) | ($/Bbl) | |||||||||||||||||
2015 | ||||||||||||||||||
January 1, 2015 through June 30, 2015 (closed) | 47,000 | $ | 91.22 | |||||||||||||||
July 1, 2015 through October 31, 2015 (closed) | 10,000 | 89.98 | ||||||||||||||||
November 1, 2015 through December 31, 2015 | 10,000 | 89.98 | ||||||||||||||||
Crude Oil Put Option Contracts | ||||||||||||||||||
Average | Strike | |||||||||||||||||
Volume | Premium | Price | ||||||||||||||||
(Bbld) | ($/Bbl) | ($/Bbl) | ||||||||||||||||
2015 (1) | ||||||||||||||||||
September 1, 2015 through October 31, 2015 (closed) | 82,500 | $ | 1.75 | $ | 45.00 | |||||||||||||
November 2015 | 82,500 | 1.75 | 45.00 | |||||||||||||||
(1) | EOG has purchased put options which establish a floor price for the sale of certain notional volumes of crude oil 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 average NYMEX West Texas Intermediate crude oil price for the contract month (Index Price), in the event the Index Price is below the put option strike price. If the Index Price is above the put option strike price, EOG is only required to pay the put option premium. | |||||||||||||||||
Natural Gas Price Swap Contracts | ||||||||||||||||||
Weighted | ||||||||||||||||||
Volume | Average Price | |||||||||||||||||
(MMBtud) | ($/MMBtu) | |||||||||||||||||
2015 (2) | ||||||||||||||||||
January 1, 2015 through February 28, 2015 (closed) | 235,000 | $ | 4.47 | |||||||||||||||
March 2015 (closed) | 225,000 | 4.48 | ||||||||||||||||
April 2015 (closed) | 195,000 | 4.49 | ||||||||||||||||
May 2015 (closed) | 235,000 | 4.13 | ||||||||||||||||
June 1, 2015 through July 31, 2015 (closed) | 275,000 | 3.98 | ||||||||||||||||
August 1, 2015 through November 30, 2015 (closed) | 175,000 | 4.51 | ||||||||||||||||
December 2015 | 175,000 | 4.51 | ||||||||||||||||
(2) | EOG has entered into natural gas price swap contracts which give counterparties the option of entering into price swap contracts at future dates. All such options are exercisable monthly up until the settlement date of each monthly contract. If the counterparties exercise all such options, the notional volume of EOG's existing natural gas price swap contracts will increase by 175,000 MMBtud at an average price of $4.51 per MMBtu for the month of December 2015. | |||||||||||||||||
$/Bbl Dollars per barrel | ||
$/MMBtu Dollars per million British thermal units | ||
Bbld Barrels per day | ||
MMBtu Million British thermal units | ||
MMBtud Million British thermal units per day | ||
NYMEX 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 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 (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively | ||||||||
(Unaudited; in millions, except ratio data) | ||||||||
The following chart reconciles Net Interest Expense (GAAP), Net Income (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income, Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for comparative purposes within the industry. | ||||||||
2014 | 2013 | 2012 | ||||||
Return on Capital Employed (ROCE) (Non-GAAP) | ||||||||
Net Interest Expense (GAAP) | $ | 201 | $ | 235 | ||||
Tax Benefit Imputed (based on 35%) | (70) | (82) | ||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 131 | $ | 153 | ||||
Net Income (GAAP) - (b) | $ | 2,915 | $ | 2,197 | ||||
Add: After-Tax Mark-to-Market Commodity Derivative Contracts Impact | (515) | 182 | ||||||
Add: Impairments of Certain Assets, Net of Tax | 553 | 4 | ||||||
Add: Tax Expense Related to the Repatriation of Accumulated | 250 | - | ||||||
Less: Net Gains on Asset Dispositions, Net of Tax | (487) | (137) | ||||||
Adjusted Net Income (Non-GAAP) - (c) | $ | 2,716 | $ | 2,246 | ||||
Total Stockholders' Equity - (d) | $ | 17,713 | $ | 15,418 | $ | 13,285 | ||
Average Total Stockholders' Equity * - (e) | $ | 16,566 | $ | 14,352 | ||||
Current and Long-Term Debt (GAAP) - (f) | $ | 5,910 | $ | 5,913 | $ | 6,312 | ||
Less: Cash | (2,087) | (1,318) | (876) | |||||
Net Debt (Non-GAAP) - (g) | $ | 3,823 | $ | 4,595 | $ | 5,436 | ||
Total Capitalization (GAAP) - (d) + (f) | $ | 23,623 | $ | 21,331 | $ | 19,597 | ||
Total Capitalization (Non-GAAP) - (d) + (g) | $ | 21,536 | $ | 20,013 | $ | 18,721 | ||
Average Total Capitalization (Non-GAAP) * - (h) | $ | 20,775 | $ | 19,367 | ||||
ROCE (GAAP Net Income) - [(a) + (b)] / (h) | 14.7 | % | 12.1 | % | ||||
ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (h) | 13.7 | % | 12.4 | % | ||||
Return on Equity (ROE) (Non-GAAP) | ||||||||
ROE (GAAP Net Income) - (b) / (e) | 17.6 | % | 15.3 | % | ||||
ROE (Non-GAAP Adjusted Net Income) - (c) / (e) | 16.4 | % | 15.6 | % | ||||
* Average for the current and immediately preceding year | ||||||||
EOG RESOURCES, INC. | ||||||||||||||||
Fourth Quarter and Full Year 2015 Forecast and Benchmark Commodity Pricing | ||||||||||||||||
(a) Fourth Quarter and Full Year 2015 Forecast | ||||||||||||||||
The forecast items for the fourth quarter and full year 2015 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. | ||||||||||||||||
(b) Benchmark Commodity Pricing | ||||||||||||||||
EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. | ||||||||||||||||
EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month. | ||||||||||||||||
Estimated Ranges | ||||||||||||||||
(Unaudited) | ||||||||||||||||
4Q 2015 | Full Year 2015 | |||||||||||||||
Daily Production | ||||||||||||||||
Crude Oil and Condensate Volumes (MBbld) | ||||||||||||||||
United States | 274.0 | - | 280.0 | 281.8 | - | 283.3 | ||||||||||
Trinidad | 0.8 | - | 1.0 | 0.8 | - | 1.0 | ||||||||||
Other International | 0.0 | - | 5.0 | 0.1 | - | 1.4 | ||||||||||
Total | 274.8 | - | 286.0 | 282.7 | - | 285.7 | ||||||||||
Natural Gas Liquids Volumes (MBbld) | ||||||||||||||||
Total | 72.0 | - | 78.0 | 75.2 | - | 76.7 | ||||||||||
Natural Gas Volumes (MMcfd) | ||||||||||||||||
United States | 840 | - | 880 | 881 | - | 891 | ||||||||||
Trinidad | 350 | - | 370 | 344 | - | 349 | ||||||||||
Other International | 24 | - | 30 | 29 | - | 31 | ||||||||||
Total | 1,214 | - | 1,280 | 1,254 | - | 1,271 | ||||||||||
Crude Oil Equivalent Volumes (MBoed) | ||||||||||||||||
United States | 486.0 | - | 504.7 | 503.8 | - | 508.5 | ||||||||||
Trinidad | 59.1 | - | 62.7 | 58.1 | - | 59.2 | ||||||||||
Other International | 4.0 | - | 10.0 | 4.9 | - | 6.6 | ||||||||||
Total | 549.1 | - | 577.4 | 566.8 | - | 574.3 | ||||||||||
Operating Costs | ||||||||||||||||
Unit Costs ($/Boe) | ||||||||||||||||
Lease and Well | $ | 5.30 | - | $ | 6.10 | $ | 5.79 | - | $ | 5.99 | ||||||
Transportation Costs | $ | 3.80 | - | $ | 4.70 | $ | 4.02 | - | $ | 4.24 | ||||||
Depreciation, Depletion and Amortization | $ | 14.50 | - | $ | 15.50 | $ | 15.79 | - | $ | 16.02 | ||||||
Expenses ($MM) | ||||||||||||||||
Exploration, Dry Hole and Impairment (A) | $ | 140 | - | $ | 160 | $ | 501 | - | $ | 521 | ||||||
General and Administrative | $ | 90 | - | $ | 98 | $ | 348 | - | $ | 356 | ||||||
Gathering and Processing | $ | 32 | - | $ | 36 | $ | 139 | - | $ | 143 | ||||||
Capitalized Interest | $ | 10 | - | $ | 11 | $ | 43 | - | $ | 44 | ||||||
Net Interest | $ | 59 | - | $ | 60 | $ | 233 | - | $ | 234 | ||||||
Taxes Other Than Income (% of Wellhead Revenue) | 6.2 | % | - | 6.6 | % | 6.5 | % | - | 6.7 | % | ||||||
Income Taxes | ||||||||||||||||
Effective Rate | 5 | % | - | 15 | % | 33 | % | - | 36 | % | ||||||
Current Taxes ($MM) | $ | 15 | - | $ | 30 | $ | 110 | - | $ | 125 | ||||||
Capital Expenditures (Excluding Acquisitions, $MM) | ||||||||||||||||
Exploration and Development, Excluding Facilities | $ | 3,700 | - | $ | 3,800 | |||||||||||
Exploration and Development Facilities | $ | 725 | - | $ | 775 | |||||||||||
Gathering, Processing and Other | $ | 275 | - | $ | 325 | |||||||||||
Pricing - (Refer to Benchmark Commodity Pricing in text) | ||||||||||||||||
Crude Oil and Condensate ($/Bbl) | ||||||||||||||||
Differentials | ||||||||||||||||
United States - above (below) WTI | $ | (2.00) | - | $ | 0.00 | $ | (1.27) | - | $ | (0.78) | ||||||
Trinidad - above (below) WTI | $ | (10.50) | - | $ | (9.50) | $ | (9.25) | - | $ | (9.00) | ||||||
Natural Gas Liquids | ||||||||||||||||
Realizations as % of WTI | 27 | % | - | 31 | % | 29 | % | - | 30 | % | ||||||
Natural Gas ($/Mcf) | ||||||||||||||||
Differentials | ||||||||||||||||
United States - above (below) NYMEX Henry Hub | $ | (0.90) | - | $ | (0.45) | $ | (0.71) | - | $ | (0.60) | ||||||
Realizations | ||||||||||||||||
Trinidad | $ | 2.40 | - | $ | 2.90 | $ | 2.85 | - | $ | 2.98 | ||||||
Other International | $ | 3.25 | - | $ | 3.75 | $ | 4.31 | - | $ | 4.42 | ||||||
(A) Excludes the impairments of proved oil and gas properties, other property, plant and equipment and other assets in the third quarter of 2015 of $6,213 million. | ||||||||||||||||
Definitions | |
$/Bbl | U.S. Dollars per barrel |
$/Boe | U.S. Dollars per barrel of oil equivalent |
$/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 |
SOURCE EOG Resources, Inc.
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